As filed with the Securities and Exchange Commission on December 15, 2006

Registration No. 333-            

 

 

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

First City Tower
1001 Fannin, Suite 1700
Houston, TX 77002
Tel. (713) 599-4910
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Jonathan L. Phillips, Esq.
General Counsel
First City Tower
1001 Fannin, Suite 1700
Houston, TX 77002
Tel. (713) 599-4910

(Name, address, including zip code and telephone number, including area code, of agent for service)

Please address a copy of all communications to:

     Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

     If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

     If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

     If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

     If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

     If delivery of the prospectus is expected to be made pursuant to Rule 434, check the following box. o

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

     We are selling          shares of our common stock. We have granted the underwriters an option to purchase up to          additional shares of common stock to cover over-allotments.

     This is the initial public offering of our common stock. We currently expect the initial public offering price to be between $        and $       per share. We are applying to have the common stock listed on The Nasdaq Global Market under the symbol “NSNG.”

     Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

     The underwriters expect to deliver the shares to purchasers on or about      , 2007.

Sole Book-Runner

     , 2007

     You should only rely on the information contained in this prospectus. We have not authorized anyone to provide you any information other than the information contained in this prospectus. We are not, and the underwriters are not, making any offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should assume that the information contained in this prospectus is accurate only as of the date of this prospectus regardless of the time of delivery of this prospectus or any sale of the common stock.

     Until      , 2007 (25 days after the commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

     This prospectus includes industry data and forecasts that we obtained from publicly available information, industry publications, and surveys. Our forecasts are based upon management’s current understanding of industry conditions and speak only as of the date of this prospectus unless the context indicates otherwise. This information has not been independently verified by us and may not be consistent with other third-party information. We believe that the information included in this prospectus from industry surveys, publications and forecasts is reliable.

with highly rated creditworthy customers, any such price decreases would impact us more severely than competitors that have greater financial resources. Accordingly, potential overcapacity in the LNG terminal marketplace could have a material adverse effect on our ability to enter into long-term TUAs with highly rated creditworthy customers and would materially and adversely affect our business and you could lose all or a significant portion of your investment.

The construction of our proposed LNG terminals will be dependent on performance by, and our relationship with, the EPC contractor that we engage at each facility.

     We plan to enter into turnkey contracts with one or more major EPC contractors for the construction of our proposed LNG terminals. The success of our LNG terminal projects is highly dependent on our ability to enter into acceptable contracts with reputable EPC contractors and for these contractors to perform their obligations under the contracts, including completing the projects on a timely basis. Nevertheless, we may not be able to enter into acceptable EPC contracts for the construction of our proposed LNG terminals. As a result, we may encounter unexpected delays or problems in connection with the construction of any of our proposed LNG terminals. Moreover, any EPC contract could be terminated under certain circumstances prior to completion of construction. If our relationship with any initial EPC contractor were to fail, we would be forced to engage a substitute contractor, which would likely result in increased construction costs and a delay in construction of our LNG terminals, which would materially and adversely affect our business and you could lose all or a significant portion of your investment.

The cost of constructing our proposed LNG terminals will be dependent on several factors, including change orders, cost overruns and commodity prices. As a result, if completed, the actual construction cost of these facilities may be significantly higher than our current estimates, excluding interest during construction and financing fees.

     Although certain of our senior management have experience developing and constructing LNG terminals, we have no prior experience in constructing LNG terminals. Prior to 2005, no LNG terminal had been constructed in the continental United States in over 25 years. If we are able to commence construction on our projects, we may decide or be forced to submit change orders to our EPC contractor that could result in a longer construction period and higher construction costs and greater financing costs. Similarly, we may encounter significant cost overruns during some phases of the construction process. In addition, under any agreement with an EPC contractor, we may retain the commodity price risk for construction materials. As a result, any significant change orders, cost overruns or increases in the price of construction materials and labor would materially and adversely affect our business and you could lose all or a significant portion of your investment.

We may not be able to hire or maintain the staff or contractors necessary to construct or operate our LNG terminals, which may have a material adverse effect on our ability to implement our business plan and our ability to generate revenues and profits.

     As of November 15, 2006, we had 23 employees and many contractors who are primarily focused on the development of our proposed LNG terminals. Once we begin construction, we will need to hire onsite employees to manage the construction of each facility and EPC contractors and other contractors to construct the LNG terminals. Later, once we commence operations, we will need to hire a full staff to operate each completed facility. Only our senior management has experience in the construction or operation of LNG terminals, and, as a result, we will be forced to rely significantly on the employees we hire to perform these functions. We currently estimate that 35 to 40 employees will be required to operate each LNG terminal. As our operations expand, we will also have to expand our administrative staff. If we are unable to locate or attract as employees individuals who can carry out these construction and operations roles, our business could be materially and adversely affected.

We may invest in additional LNG terminal projects and/or change our operating and investment strategy and make other LNG-related investments, including upstream and downstream opportunities, which may entail greater risk.

     We may consider acquisitions of additional LNG terminal projects. We cannot assure you that we will be able to identify, acquire, continue to develop, or profitably manage additional LNG terminal projects or that we will be able to successfully integrate any acquired LNG terminal projects without substantial costs, delays, or other operational or financial problems. Acquisitions involve a number of special risks, including failure of the acquired business to achieve expected results, diversion of management’s attention, failure to retain key personnel of the acquired business and risks associated with unanticipated events or liabilities. If we experience any regulatory problems or negative publicity with regard to any LNG

terminal project, it could have a generally adverse effect on our reputation and harm our local, regional, or national development initiatives. In addition, we cannot assure you that any acquired projects will be completed or produce any revenues or earnings.

     We may finance future acquisitions, if any, by using shares of our common stock for a substantial portion of the consideration to be paid. If potential acquisition candidates are unwilling to accept common stock as part of the consideration for the sale of their businesses, we may be required to pay cash, if available, in order to complete any acquisitions. If we do not have sufficient cash resources to make acquisitions, we may miss important corporate opportunities, experience dilution, or otherwise be unable to execute our business strategy. Acquisitions using our common stock will dilute the interests of all stockholders, and if the effective value of our common stock declines due to dilution, your investment could be materially adversely affected.

     We may also change our operating and investment strategy at any time without your consent, which could result in our acquiring or investing in projects that are different from, and possibly riskier than, the LNG terminal projects described in this prospectus, such as natural gas pipelines and storage, marketing and trading, LNG shipping, oil and gas exploration, development and transportation, securing foreign LNG supply arrangements and developing foreign natural gas reserves that could be converted to LNG. We may not be successful in any future acquisitions of LNG terminal projects or in pursuing any downstream or upstream LNG opportunities and, even if successful, we could be exposed to greater and unanticipated risks. Any changes to our operating and investment strategy could cause us to become a substantially different company, which could adversely affect our business and financial condition.

     If we begin conducting development, construction or operations of LNG terminals outside of the United States due to any potential foreign acquisition or other opportunity our financial condition and results of operations may be materially adversely affected by economic, political and governmental conditions in the countries where we engage in business. Any disruptions caused by these factors could harm our business, including the risks of war, expropriation or nationalization of assets, renegotiation or nullification of existing contracts, changing laws and policies affecting trade, taxation and investment, fluctuating currency values and exchange rates and overlap of tax structures.

We depend on key personnel, and the loss of any of these individuals could have a material adverse effect on our business and operations.

     Several of our executive officers, including Mr. Garrett, our Chief Executive Officer, Mr. Soanes, our President, and Mr. Glessner, our Vice President, Engineering and Construction, have been involved in the development of our LNG terminals prior to our founding and are familiar with the development plans and issues. In addition, these individuals have extensive project development experience in the energy sector, including with respect to LNG terminals. The loss of services of one or more of these individuals could prevent or delay the development of our LNG terminals and could have a material adverse effect on the success of our business.

Certain of our executive officers have the right to pursue other business interests which may adversely affect our ability to achieve our strategic plan.

     Mr. Garrett, Mr. Soanes and Mr. Phillips may only hold an ownership interest in, hold an executive officer position with, have defined services with respect to and sit on the board of, one or more biodiesel businesses without violation of their respective employment agreements if (1) such activities do not materially interfere with the performance of duties under their employment agreements and (2) such business or businesses do not enter into any line of business that competes with the business of the Company or its affiliates. Nevertheless, these other business interests may demand their attention and reduce the amount of time they have available to devote to our business, which may adversely affect our ability to implement our business plan successfully.

We expect to enter into TUAs that will be subject to termination by our capacity holders under certain circumstances, and we expect to be generally dependent on the performance of those counterparties under the TUAs.

     We expect to enter into long-term TUAs under which payments received from our capacity holders will be our principal source of operating income. Each TUA will contain various termination rights. For example, these rights may include the right to terminate a TUA during the construction period of a proposed LNG terminal for any reasonable determination that “substantial completion” of the terminal will not occur prior to a future date or if we fail to reach certain milestones. It may

not be possible to replace a TUA on desirable terms, or at all, if a TUA is terminated. In addition, we may be dependent on our capacity holders’ creditworthiness and their continued ability and willingness to perform their obligations under our TUAs and may be subject to a concentration of credit risk due to the minimal number of counterparties. If any of our capacity holders were to fail to perform under its respective TUA, our revenues could be materially adversely affected, even if we were to be ultimately successful in seeking damages from that counterparty for a breach of the TUA. In addition, termination of a TUA and failure to obtain a replacement TUA may constitute an event of default on our indebtedness, which could lead to foreclosure upon our facilities which would materially and adversely affect our business and you could lose all or a significant portion of your investment.

The inability of potential LNG customers to import LNG into the United States due to, among other things, governmental regulation, potential instability in countries that supply natural gas or other circumstances beyond our control could adversely affect our business and you could lose all or a significant portion of your investment.

     Upon completion of our LNG terminals, our business will be dependent upon the ability of our customers to import LNG into the United States. Political instability in foreign countries that supply LNG, or strained relations between those countries and the United States, may impede the ability of LNG suppliers in those countries to export LNG to the United States. These foreign suppliers may also be able to negotiate more favorable prices with other LNG customers around the world than with customers in the United States, thereby reducing the supply of LNG available to be imported into the U.S. market. In addition, the lack of sufficient LNG carriers available to deliver the forecasted amount of LNG would impede our customers’ ability to import LNG into the United States.

     Furthermore, our customers may be able to suspend, terminate, or otherwise not perform obligations under their contracts upon the occurrence of events of force majeure, including but not limited to strikes and other industrial or labor disturbances, terrorism, restraints of government, civil disturbances, accidents or breakages of machinery, failure of suppliers, interruptions or delays in transportation, or any natural disaster, all being circumstances out of our control.

     Any significant impediment to our customers’ ability to import LNG into the United States or their ability to suspend, terminate or otherwise not perform their obligations under their contracts could adversely affect our business and you could lose all or a significant portion of your investment.

Volatility in the demand for LNG regasification capacity may result in reduced operating revenues.

     If we do not contract for all of our base capacity through long-term TUAs, we will be forced to sell our capacity on the spot market. Spot market sales are subject to cyclical swings in prices, which could adversely affect our results of operations and the value of your investment.

     Any resulting increases and decreases in the available supply of natural gas and volatility in the demand for LNG receiving capacity could adversely affect our business and you could lose all or a significant portion of your investment.

LNG terminals are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.

     The construction and operation of our proposed LNG terminals will be subject to the inherent risks normally associated with these types of operations, including accidents, pollution, adverse weather conditions and other hazards, each of which could result in damage to or destruction of our facilities or damage to persons and property for which we could be liable. In addition, our operations face possible risks associated with acts of aggression on our assets and the assets of third parties on which our operations are dependent.

     In accordance with customary industry practices, we intend to maintain insurance against some, but not all, of these risks and losses. We may not be able to maintain adequate insurance in the future at rates that we consider commercially reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business and operations and, in the event of a partial or total loss, our ability to repair or replace the damaged assets.

The impact of natural disasters such as earthquakes, volcanic eruptions, tsunamis, hurricanes and floods could have a material adverse effect on our business and operations.

     The construction and operation of our proposed LNG terminals on the West Coast could be materially adversely affected by earthquakes, volcanic eruptions, tsunamis, hurricanes, floods, and other similar natural catastrophes.

Terrorist attacks or sustained military campaigns may adversely impact our business.

     The terrorist attacks that took place in the United States on September 11, 2001 were unprecedented events that have created many long-lasting economic and political uncertainties, some of which may materially adversely impact our business. The continued threat of terrorism and the impact of military and other action will likely lead to continued volatility in prices for natural gas and could affect the markets for the operations of LNG customers on which we will be dependent. Furthermore, the U.S. government has issued public warnings indicating that pipelines and other energy assets might be specific targets of terrorist organizations. The continuation of these developments may subject our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business, operations, financial condition, and the value of your investment.

     In addition, LNG and oil facilities, shipyards, carriers, pipelines, and oil and gas fields and virtually all other energy-related facilities could be targets of future terrorist attacks. Any such attacks could lead to, among other things, bodily injury or loss of life or other property damage, increased operational costs, including insurance costs, and the inability to operate our LNG terminals. Terrorist attacks, war or other events beyond our control that adversely affect the distribution, production or transportation of LNG could reduce payments under our TUAs or entitle our customers to terminate our TUAs, which could materially and adversely affect our business and you could lose all or a significant portion of your investment.

Our bylaws do not prevent our directors from pursuing or acquiring corporate opportunities that may be in competition with us and as a result may adversely affect our financial condition and results of operations.

     Our bylaws provide that if one of our directors that is a member, manager, principal, employee, or other representative or nominee of a large financial institution or investment fund, or any affiliate thereof, who is a holder of our common stock, acquires knowledge of an investment opportunity, such director will be deemed not to have violated its fiduciary duty to us and our stockholders and such director will not be liable to us or our stockholders for breach of any fiduciary duty by reason of the fact that the director (or the related financial institution or investment fund) pursues or acquires the opportunity for itself or directs the opportunity to another person or does not communicate information regarding the opportunity to us.

     As a result, certain of our directors may pursue corporate opportunities directly competitive with our business, rather than presenting corporate opportunities to us, which may materially and adversely affect our financial condition and results of operations.

We may be required to repurchase all or a portion of our convertible notes in cash on May 17, 2009.

     The holders of our convertible notes may require us to repurchase all or any portion of the convertible notes on May 17, 2009 in cash at a price equal to the conversion amount applicable to the principal amount being redeemed plus interest accrued but not paid. Based on the amount of convertible notes outstanding as of November 15, 2006, if we were to be required to redeem all of the convertible notes we would be required to make cash payments to convertible note holders in an aggregate amount of up to $103.5 million plus interest accrued through May 17, 2009, unless all or a portion of the convertible notes are converted by the holders or redeemed by us prior to such date. In addition, if we choose to pay interest on the convertible notes in kind with additional convertible notes, our cash requirements if we are required to repurchase the convertible notes will increase. If we do not have sufficient cash to meet our repurchase obligations under the convertible notes we may suffer material harm to our ability to operate our business or be required to obtain financing on less favorable terms than would otherwise be available to us.

Our stock price may decline due to sales of shares by our other stockholders.

     Sales of substantial amounts of our common stock, or the perception that these sales may occur, may adversely affect the price of our common stock and impede our ability to raise capital through the issuance of equity securities in the future. All shares sold in this offering are freely transferable without restriction or further registration under the Securities Act, subject to

restrictions that may be applicable to our affiliates, as that term is defined under Rule 144 under the Securities Act. In addition, our convertible notes are convertible into 11,346,552 shares of our common stock based on our estimated conversion price of $9.12 per share. In addition, substantially all of the shares held by our existing stockholders are subject to registration rights, and we believe these rights will be exercised. A significant number of these shares may be sold, which may decrease the price of shares of our common stock.

     In connection with this offering, we and our executive officers, directors, substantially all our stockholders, and all the holders of our convertible notes entered into 180-day lock-up agreements. These lock-up agreements prohibit us and our executive officers, directors, and such stockholders and holders of our convertible notes from selling or otherwise disposing of shares of our common stock, except in limited circumstances. The terms of the lock-up agreements can be waived, at any time, by the underwriters at their discretion, without prior notice or pronouncement, to allow us or our executive officers, directors, stockholders, and holders of our convertible notes to sell shares of our common stock. If the terms of the lock-up agreements are waived, shares of our common stock will be available for sale in the public market sooner, which could reduce the price of our common stock.

     The future market price for our shares may be very volatile. This price volatility may make it more difficult for you to sell your shares when you want at prices you find attractive. The stock market in general has experienced extreme price and volume fluctuations that often are unrelated or disproportionate to the performance of the company. Broad market factors and the investing public’s negative perception of our business may reduce our stock price, regardless of our performance. Market fluctuations and volatility, as well as general economic, market, and political conditions, could reduce our market price. As a result, this may make it difficult or impossible for you to sell our common stock for a positive return on your investment.

     Some of the factors in addition to the risks described above that could negatively affect the price of our common stock include:

     As a result of these factors, you may not be able to sell your shares at or above the initial offering price. These broad market fluctuations and industry factors may materially reduce the market price of our common stock, regardless of our operating performance.

If we fail to meet continued listing standards of Nasdaq, our common stock may be delisted which would have a material adverse effect on the price of our common stock.

     In order for our securities to be eligible for continued listing on Nasdaq, we must remain in compliance with certain listing standards. Among other things, these standards require that we remain current in our filings with the SEC and comply with certain provisions of the Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley Act). If we were to become noncompliant with Nasdaq’s continued listing requirements, our common stock may be delisted which would have a material adverse affect on the price of our common stock.

If we are delisted, our common stock may become subject to the “penny stock” rules of the Securities and Exchange Commission, which would make transactions in our common stock cumbersome and may reduce the value of an investment in our stock.

     The Securities and Exchange Commission (SEC) has adopted Rule 3a51-1 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that is not listed on a national securities exchange or registered national securities association’s automated quotation system and has a market price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, Rule 15g-9 require:

     In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

     The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the Securities and Exchange Commission relating to the penny stock market, which, in highlight form:

     Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

If securities analysts downgrade our common stock or cease coverage of us, the price of our common stock could decline.

     The trading market for our common stock will rely in part on the research and reports that industry or financial analysts publish about us or our business. We do not control these analysts. Furthermore, there are other well-established, publicly traded companies active in our industry, which may mean that it is less likely that we will receive widespread analyst coverage. If one or more of the analysts who do cover us downgrade our common stock, our common stock price would likely decline rapidly. If one or more of these analysts cease coverage of us, we could lose visibility in the market, which in turn could cause our common stock price to decline.

Certain provisions of our charter documents and agreements, as well as Delaware law, could discourage, delay or prevent a merger or acquisition at a premium price and upon a change of control, we may be required to redeem some or all of our convertible notes.

     Our amended and restated certificate of incorporation and bylaws will contain provisions that:

     The foregoing provisions may impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders.

     In addition, our convertible notes provide that, upon a change of control, holders may require us to redeem all or a portion of their convertible notes at a price either 110% of the conversion amount applicable to the principal amount being redeemed, in the case of a mandatory change of control redemption, or 100% of the conversion amount applicable to the principal amount being redeemed, in the case of an optional change of control redemption, plus any accrued and unpaid interest.

If you purchase shares of common stock sold in this offering, you will experience immediate and substantial dilution.

     If you purchase shares of our common stock in this offering, you will experience immediate and substantial dilution of pro forma net tangible book value per share because the price that you pay will be substantially greater than the net tangible book value per share of the shares you acquire, based on the net tangible book value per share as of September 30, 2006. This dilution is due in large part to the fact that our earlier investors paid substantially less than the initial public offering price when they purchased their shares. You will experience additional dilution upon the exercise of stock options by certain employees or certain directors to purchase common stock under our equity incentive plan and conversion of our convertible notes.

     We currently have no operating revenues and do not expect to pay dividends in the foreseeable future. We presently anticipate that all earnings, if any, will be retained for the development of our business. Any future dividends will be subject to the discretion of our board of directors and will depend on, among other things, future earnings, our operating and financial condition, our capital requirements, and general business conditions. Investors seeking cash interest and/or dividends should not purchase our common stock.

The conversion price of our Senior Convertible Notes may be lowered if we issue shares of our common stock at a price less than the existing conversion price, which could cause dilution to our common stockholders.

     Subject to certain exclusions, if we issue common stock at a price less than the existing conversion price for our Senior Convertible Notes due 2013 (convertible notes), the conversion price shall be adjusted downward to a price no less than $7.30 per share which would dilute our common stock holders upon conversion. The conversion price will be adjusted for certain issuances of our securities, stock splits, cash dividends, and stock dividends.

Our executive officers, directors and other five percent or greater stockholders and entities affiliated with them own a large percentage of our company, and could influence matters requiring approval by our stockholders.

     Prior to the close of this offering, our executive officers, directors and other five percent or greater stockholders and entities affiliated with them, acting together, will be able to influence matters requiring approval by our stockholders, including the election of directors. After the offering, assuming none of the holders of our convertible notes elect to convert their convertible notes, MatlinPatterson will control approximately     % of our outstanding common stock and approximately     % of our outstanding common stock if the over-allotment option is exercised in full. In addition, MatlinPatterson holds $10 million in principal amount of our convertible notes. Accordingly, MatlinPatterson will be in a position to control or influence the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of MatlinPatterson may differ from yours, and MatlinPatterson may vote its common stock in a manner that may adversely affect you. In addition, Section 203 of the Delaware General Corporation Law (DGCL) provides for a three-year moratorium on certain business combinations with interested stockholders (generally, persons who own, individually or with or through other persons, 15% or more of the corporation’s outstanding voting stock). The DGCL, however, permits a corporation to opt out of the restrictions imposed by Section 203. We plan to opt out of Section 203 of the DGCL in the amended and restated certificate of incorporation which we plan to adopt prior to the completion of this offering. Accordingly, we will be able to engage in business combinations with interested stockholders, such as MatlinPatterson.

     The concentration of ownership of our shares of common stock may also have the effect of delaying or preventing a change in control.

When we become a public company, we will incur increased costs that may place a strain on our resources or divert our management’s attention from other business concerns.

     When we become a public company, we will incur additional legal, accounting and other expenses that we do not incur as a private company. The Exchange Act will require us to file annual, quarterly and current reports with respect to our business and financial condition, which will require us to incur substantial legal and accounting expenses. The Sarbanes-Oxley Act will require us to maintain effective disclosure controls and procedures and internal controls for financial reporting. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight will be required. We expect the corporate governance rules and regulations of the SEC and any exchange on which we may list will increase our legal and financial compliance costs and make some activities more time consuming and costly. These requirements may place a strain on our systems and resources and may divert our management’s attention from other business concerns, which could have a material adverse effect on our business, financial condition and results of operations. In addition, we are hiring and will continue to hire additional legal, accounting and financial staff with appropriate public company experience and technical accounting knowledge, which will increase our operating expenses in future periods.

     We also expect these rules and regulations to make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified persons to serve on our board of directors or as executive officers. We are currently evaluating and monitoring developments with respect to these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

We may be exposed to potential risks resulting from new requirements that we evaluate our internal controls over financial reporting under Section 404 of the Sarbanes-Oxley Act of 2002.

     Section 404 of the Sarbanes-Oxley Act requires that publicly reporting companies cause their management to perform annual assessments of the effectiveness of their internal controls over financial reporting and their independent auditors to prepare reports that address such assessments. Once the registration statement for this offering has been declared effective by the SEC, we are required to satisfy the requirements of Section 404 upon the filing of our second annual report after becoming a public company.

     We may not be able to assess our current internal controls and comply with these requirements within the required timeframe. If we are able to proceed with a complete assessment in a timely manner, we may identify deficiencies which we

may not be able to remediate, may identify deficiencies which will demand significant resources to remediate, or may be unable to identify existing deficiencies at all. In addition, if we fail to achieve and maintain the adequacy of our internal controls, we may not be able to conclude on an ongoing basis that we have effective internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Moreover, effective internal controls, particularly those related to revenue recognition, are necessary for us to produce reliable financial reports and are important to helping prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information and the trading price of the common stock offered hereby could drop significantly. Our compliance with the Sarbanes-Oxley Act may require significant expenses and management resources that would need to be diverted from our other operations and could require a restructuring of our internal financial reporting. Any such expenses, time reallocations or restructuring could have a material adverse effect on our operations. The applicability of the Sarbanes-Oxley Act to us could make it more difficult and more expensive for us to obtain director and officer liability insurance, and also make it more difficult for us to attract and retain qualified individuals to serve on our board of directors and, particularly, our audit committee, or to serve as executive officers.

We will retain broad discretion in using the net proceeds from this offering, and may not use the proceeds effectively.

     Although we expect to use a substantial portion of the net proceeds from this offering to fund the development of our three active projects, the equity financing for the construction of our Bradwood LNG project, the development of other LNG terminals in addition to our initial projects, and general corporate purposes, our management will retain broad discretion to allocate the net proceeds of this offering. The net proceeds may be applied in ways with which you and other investors in the offering may not agree. Moreover, our management may use the proceeds for corporate purposes that may not increase our market value or make us profitable. Management’s failure to spend the proceeds effectively could have an adverse effect on our business and our ability to complete development and construction of our proposed LNG terminals.

We may be or become a United States real property holding corporation. If we are or become such a corporation, non-U.S. investors may be subject to U.S. federal income tax (including withholding tax) on gains realized on disposition of our common stock, and U.S. investors selling our common stock may be required to certify as to their status in order to avoid withholding.

     A United States real property holding corporation is a corporation in which 50% or more of the fair market value of its assets consist of United States real property. Whether we are or are likely to become a United States real property holding corporation is subject to significant legal and factual issues, but there is a significant risk that we are or may become such a corporation. If we were a United States real property holding corporation, a non-U.S. holder of our common stock would generally be subject to U.S. federal income tax on gains realized on a sale or other disposition of our common stock. Certain non-U.S. holders of our common stock may be eligible for an exception to the foregoing general rule if our common stock is regularly traded on an established securities market during the calendar year in which the sale or disposition occurs. We would be so treated if we were listed on Nasdaq and we satisfied certain requirements, including requirements as to minimum volumes of trading. We cannot offer any assurance that our common stock will be so traded at any point in time in the future.

     If our common stock is not considered to be regularly traded on an established securities market during the calendar year in which a sale or disposition occurs, the buyer or other transferee of our common stock will generally be required to withhold tax at the rate of 10% on the sales price or other amount realized, unless the transferor furnishes an affidavit certifying that it is not a foreign person in the manner and form specified in applicable Treasury regulations.

     This prospectus includes “forward-looking statements,” as defined by federal securities laws, with respect to our financial condition, results of operations, our industry, and business. Forward-looking statements are those that do not relate solely to historical fact. They include, but are not limited to, any statement that may predict, forecast, indicate or imply future results, performance, achievements or events. Words such as, but not limited to, “will,” “may,” “should,” “could,” “would,” “predicts,” “potential,” “continue,” “expects,” “anticipates,” “future,” “intends,” “plans,” “believes,” “estimates,” and similar expressions or phrases, as well as statements in future tense, identify forward-looking statements. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements.

     All forward-looking statements involve significant risks and uncertainties. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we cannot assure you that they will prove to have been correct. The occurrence of the events described, and the achievement of the expected results, depend on many events, many or all of which are not predictable or within our control. Should one or more of these uncertainties or management’s current assumptions regarding risks, among others, materialize, actual results may vary materially from those estimated, anticipated or projected.

     Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” and include:

     We urge you to carefully review and consider the disclosures made in this prospectus of the risks and factors that may affect our business. See “Risk Factors” on page 10 of this prospectus for examples of factors, risks and uncertainties that could cause actual outcomes and results to be materially different from those projected or assumed in our forward-looking statements. Other currently unknown or unpredictable factors could also harm our results. Consequently, there can be no assurance that actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected consequences to, or effects on, us.

     Given these uncertainties, prospective investors are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this prospectus unless the context indicates otherwise. We undertake no obligation to update or revise any forward-looking statements, either to reflect new developments, or for any other reason, except as required by law.

     We expect to receive net proceeds of approximately $     million from the sale of          shares of common stock by us in this offering at an assumed initial public offering price of $     per share (the mid-point of the range set forth on the cover page of this prospectus), after deducting estimated underwriting commissions and discounts and estimated expenses. Our estimates assume an initial public offering price of $     per share of common stock and no exercise of the underwriters’ option to purchase additional shares. An increase or decrease in the initial public offering price of $      per share would cause the net proceeds from the offering, after deducting underwriting discounts and fees and offering expenses payable by us, to increase or decrease by $     million (or $     million assuming full exercise of the underwriters’ option to purchase additional shares).

     We anticipate using the net proceeds to us from this offering as follows:

     We are a recently formed development stage company without revenue generating capability and have paid no dividends in the past. We do not anticipate paying cash dividends in the foreseeable future. Any declaration and payment of dividends will be at the discretion of our board of directors and will depend upon, among other things, our earnings, financial condition, capital requirements, level of indebtedness, contractual restrictions with respect to the payment of dividends, and other considerations that the Board deems relevant. Our board of directors’ ability to declare a dividend is also subject to limits imposed by Delaware corporate law and by the provisions of our Senior Convertible Notes due 2013. See “Description of Senior Convertible Notes.”

     The following table sets forth our cash, cash equivalents, marketable securities, and capitalization as of September 30, 2006 on an actual basis and pro forma as adjusted basis after giving effect to our receipt of the net proceeds from our sale of common stock in this offering.

     This table should be read in conjunction with our financial statements and the notes thereto, “Use of Proceeds,” “Dividend Policy,” “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Description of Senior Convertible Notes” included elsewhere in this prospectus.

     Purchasers of the common stock in this offering will be immediately and substantially diluted to the extent of the difference between the initial public offering price per share of our common stock and the net tangible book value per share of our common stock immediately after completion of this offering. Dilution results from the fact that the per share offering price of the common stock is substantially in excess of the net tangible book value per share of our common stock immediately following the completion of the offering. Net tangible book value represents the amount of our total tangible assets reduced by our total liabilities. Tangible assets represent our total assets less intangible assets. Net tangible book value per share represents our net tangible book value divided by the number of shares of common stock outstanding. As of September 30, 2006, our net tangible deficit was $25.6 million or $0.93 per share.

     The following table illustrates this substantial and immediate per share dilution to new investors:

     The following table presents as of September 30, 2006 and on a pro forma basis after giving effect to this offering, the total number of shares of common stock purchased from us, the total consideration paid to us, assuming an initial public offering price of $     per share (before deducting the estimated underwriting discounts and commissions and offering expenses payable by us in this offering), and the average price per share paid by existing stockholders and by new investors purchasing shares in this offering.

     The foregoing table does not include the impact of the underwriters’ over-allotment option. If the underwriters exercise their option to purchase additional shares of our common stock in full in this offering, the as adjusted net tangible book value per share after this offering would be $           per share, the decrease in net tangible book value per share to existing stockholders would be           per share and the dilution to new investors purchasing shares in this offering would be     per share.

     A $1.00 change in the assumed public offering price of $     per share of our common stock would change our pro forma net tangible book value after giving effect to the offering by $      million, the pro forma net tangible book value per share of our common stock after giving effect to this offering by $     and the dilution in pro forma net tangible book value per share of our common stock to new investors by $     , assuming no change in the number of shares of common stock offered by us as set forth on the cover page of this prospectus, and after deducting underwriting discounts and commissions and other expenses of the offering. The pro forma information discussed above is illustrative only. Our net tangible book value following completion of the offering is subject to adjustment based upon the actual offering price of our common stock and other terms of this offering at pricing.

The discussion and tables above exclude the following:

     The following table presents our selected consolidated historical financial information. The consolidated statement of operations and balance sheet data for the period from inception (May 17, 2005) through December 31, 2005 and as of December 31, 2005 are derived from our audited consolidated financial statements and related notes included in this prospectus. The consolidated statement of operations and balance sheet data for the nine months ended September 30, 2006 are derived from our unaudited consolidated financial statements included in this prospectus. The consolidated statement of operations from the date of our inception through September 30, 2006 is derived from our audited and unaudited consolidated financial statements included in this prospectus. In the opinion of management, the unaudited consolidated financial statements have been prepared on the same basis as our audited consolidated financial statements and include all adjustments, consisting of only normal recurring adjustments, necessary for a fair presentation of the information set forth therein. As we are a recently formed development stage company with no operating revenues our historical results for any annual or interim period are not necessarily indicative of results to be expected for a full year or for any future period as development activities and related costs have varied in the past and are anticipated to continue to vary in the future. The net loss per share information is computed using the weighted average number of units/common shares outstanding during the related period.

     You should read this information together with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and the related notes thereto included elsewhere in this prospectus. Our historical financial statements have been prepared in accordance with generally accepted accounting principles in the United States.

     You should read the following discussion and analysis in conjunction with the section “Selected Historical Financial Data” and the financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements and reflects our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors such as those set forth under “Risk Factors” and elsewhere in this prospectus.

     Our business was founded by our Chief Executive Officer, Mr. Garrett, and our President, Mr. Soanes, who have significant global project development experience and who, together with other members of our senior management team, have been involved in the development of more than 50 energy infrastructure projects with an aggregate investment of over $15 billion.

     Commencing in May 2005, Mr. Garrett and Mr. Soanes, through an entity controlled by them, formed a joint venture with certain affiliates of MatlinPatterson Global Advisors LLC (MatlinPatterson). The joint venture was specifically formed to develop and eventually construct the Bradwood LNG terminal project. Mr. Garrett and Mr. Soanes agreed to provide services to the joint venture and not compete with the venture in the U.S. Pacific Northwest. MatlinPatterson agreed to provide up to $14 million for the costs to develop the project.

     The audited and unaudited financial statements of NorthernStar Natural Gas Inc. and subsidiaries (formerly NorthernStar Natural Gas LLC), represent the original entity through which MatlinPatterson made its investment in the joint venture and include the development stage operating results of this business from inception, May 17, 2005, through December 31, 2005 and for the period January 1, 2006 through September 30, 2006. The original joint venture was reorganized by an exchange of membership units and the issuance of membership units to certain persons who assisted in its formation and are among our current or former directors. This resulted in our owning the entire Bradwood project. Under the provisions of FIN 46 R, Bradwood has been fully consolidated in our financial statements as if it were a wholly-owned subsidiary since our founding on May 17, 2005. This exchange of equity interests is more fully discussed under “—Results of Operations” below.

     Our Chief Executive Officer and our President were historically involved in the development of our two other LNG projects, the assets of which we acquired during 2006. One of these acquisitions, Clearwater, was formed in January 2002 by third parties and was managed by Mr. Garrett and Mr. Soanes through a consulting arrangement. Clearwater utilizes Platform Grace, an existing offshore oil and gas production platform located approximately 13 miles offshore of Oxnard, California. From October 2003 through March 2006, Mr. Garrett and Mr. Soanes led the development efforts for this project. On March 27, 2006, we acquired the entity developing this project and it became a wholly-owned subsidiary named Clearwater Port Holdings LLC. The financial results of Clearwater are included in our consolidated financial statements subsequent to the acquisition date. Clearwater was and is a development stage company.

     Our Orion project was an acquisition of certain proprietary information related to a proposed LNG terminal project that Mr. Garrett and Mr. Soanes began to develop along with other parties in early 2002 in Southern California. In October 2002, the development entity managed by Mr. Garrett and Mr. Soanes sold the rights to the project to an unrelated third party and was retained by the purchaser as a project development adviser. The selling entity received consulting income during the period that it served as a project development adviser. The purchaser actively pursued the development of the project, including making expenditures for seismic studies, permit applications, engineering, and pipeline routing and environmental studies; however, in September 2005 the purchaser discontinued its development of the project and in accordance with the initial sales agreement, all intellectual property and intangible rights related to the development of the project reverted to the initial development entity. Mr. Garrett and Mr. Soanes, through this entity, began evaluating a new project offshore of Southern California using some of the intellectual property and intangible rights related to the prior project. The intellectual property and intangible rights related to the new project were sold to Orion and Orion was acquired by us on March 7, 2006. Orion’s financial results are included in our consolidated financial statements after the acquisition date. These acquired intangible assets do not constitute a business and, accordingly, no financial statements have been prepared.

     Our company was founded in May 2005 to develop, own, and operate LNG receiving/importation terminals on the West Coast of the United States (West Coast). We consolidated ownership of our LNG terminal projects in March 2006 to take advantage of project portfolio diversification, economies of scale, and greater access to capital.

     Our three initial LNG terminal projects are as follows:

     We were incorporated on May 16, 2006, with previous members exchanging their membership units in NorthernStar Natural Gas LLC for our shares of the common stock of NorthernStar Natural Gas Inc. (NorthernStar) using an exchange ratio of 210,000 shares for each membership unit of NorthernStar Natural Gas LLC. Our three projects are held by our wholly-owned subsidiaries.

     To date, our activities have been limited to development activities related to our three LNG terminal projects. Those projects, if completed according to plan, will provide direct access to major West Coast natural gas demand centers. We intend to negotiate and sign terminal use agreements (TUAs) for all or substantially all of the long-term base capacity of each LNG terminal with highly rated creditworthy counterparties. We expect to provide offloading and regasification services under the TUAs without taking ownership of LNG or natural gas. Each TUA is expected to have a 20-year term and to generate a steady, predictable stream of contracted fee payments with no commodity price risk. In addition, we may periodically sell capacity to third parties or purchase, regasify, and sell cargoes of LNG on a spot basis as opportunities arise when the terminals’ firm capacity is not being utilized by our TUA customers, generating additional revenues to supplement those received under the TUAs.

     We estimate the remaining aggregate costs from September 30, 2006 to bring all three projects to the end of the development stage to be approximately $62 million. We continue to pursue necessary permits and approvals for construction of these projects and believe such permits and approvals will be obtained and if pursued to their conclusion that all of the projects will be economically viable to construct and operate. Our business success will depend to a significant extent upon our ability to obtain the funding necessary to construct our LNG terminals, to bring them into operation on a commercial basis and to finance the costs of staffing, operating and expanding our company during that process.

     Our ability to obtain construction financing for our projects will depend on the final costs of the project, the quality of our engineering, procurement and construction (EPC) contractor, the terms of our contract with such EPC contractor, and the economic viability of each LNG terminal project to prospective lenders. We intend to negotiate our TUAs close to the time or following the receipt of the permits necessary to initiate construction of the LNG terminals in order to maximize our negotiating leverage with purchasers of our capacity. We will seek to enter into long-term TUAs with highly rated creditworthy “anchor tenants” for our planned regasification capacity. Our TUAs may provide an advance payment for regasification capacity sold, which may provide additional capital to help meet our ongoing liquidity needs. Furthermore, these TUAs are expected to serve as collateral to facilitate project level debt financing that we intend to obtain with respect to the construction of the related LNG terminal(s); however, we do not expect our LNG terminal projects to become a source of material revenues until after commercial operations successfully commence.

     Our Bradwood project is designed as a land-based LNG terminal engineered to have an initial sustainable base capacity of 1.0 Bcf/d, peak capacity of 1.3 Bcf/d and a pre-engineered capability to expand the base capacity to 2.0 Bcf/d. Bradwood is the only LNG terminal project in the Pacific Northwest to have completed the Federal Energy Regulatory Commission (FERC) prefiling process under Section 3 of the Natural Gas Act for authorization to construct and operate an LNG receiving terminal. To commence construction of the project, we need to obtain all required permits from FERC and certain other regulatory agencies and obtain the necessary financing. See “State and Federal Government Regulatory Matters.” We are targeting regulatory approvals for the Bradwood project by the FERC and state and local authorities in the third quarter of 2007 and the commencement of commercial operations in the first quarter of 2011.

     Our Clearwater project is an offshore, platform-based LNG terminal that is engineered to have a sustainable base capacity of 1.2 Bcf/d and a peak capacity of 1.4 Bcf/d. The platform will be connected through a 13-mile offshore pipeline to the Southern California Gas Co. pipeline network and storage infrastructure serving the approximately 4.0 Bcf/d Southern California market. We filed our original Deepwater Port (DWP) license application in February 2004, and, following our purchase of this project, submitted an amended and restated application in June 2006 as a more comprehensive response to additional data requests with direction from the U.S. Coast Guard, the California State Lands Commission (CSLC), and other agencies. Based upon new agency reviews, the U.S. Coast Guard and the CSLC will move forward with engagement of a contractor for the preparation of our draft environmental reports. We are anticipating regulatory approval in the second quarter of 2008, the commencement of construction in the third quarter of 2008, and the commencement of commercial operations in the second quarter of 2010.

     Our Orion project has advanced with a target location about 25 miles offshore of Carlsbad, California with direct access to the Los Angeles and San Diego markets. Orion is expected to be designed to include a concrete hull floating storage and regasification unit with a design capacity of 1.2 Bcf/d. As of November 2006, Orion was in the early development phase. We intend to pursue the development of Orion in conjunction with the approval process of our Clearwater project.

Results of Operations for the Nine Months Ended September 30, 2006

     Overview

     Our financial results for the nine months ended September 30, 2006 reflect a net loss of $42.8 million, or $1.57 per share (basic and diluted). Major factors contributing to our loss at September 30, 2006 include the operating results of Orion and Clearwater since they became members of the controlled group in March 2006. See “Purchase and Financing of Our LNG Terminal Projects and LNG Related Assets” for further discussion of the purchase of these projects. Additionally, consulting fees and employee costs related to stock option grants contributed significantly to our net loss and net loss per share. Other expenses include (1) project development expenses of $13.1 million, which includes $9.4 million for permitting, $2.1 million for public relations, and $1.5 million for engineering, legal and other project related costs; (2) $27.3 million in general and administrative expenses, including $13.9 million related to consulting services provided in relation to our LNG terminal project acquisitions; and (3) $10.1 million in payroll and contract services, including $7.4 million representing non-cash stock option expense recorded in accordance with SFAS No. 123R related to the stock options granted under the 2006 Long-Term Incentive Plan, and the remainder for legal, travel and other administrative costs.

     LNG Terminal Development Costs

     Bradwood, Clearwater, and Orion are development stage companies and to date have received no revenue from operations. LNG terminal development expenses for Bradwood, Clearwater and Orion were $9.3, $3.6, and $0.2 million, respectively, for the nine months ended September 30, 2006, primarily consisting of consulting and engineering studies, permitting costs, legal, public relations, and general and administrative activities.

     Other General and Administrative Expenses

     Other general and administrative expenses are primarily related to our general corporate and other activities. These expenses were $27.3 million for the nine months ended September 30, 2006. General and administrative expenses include $13.9 million related to consulting services provided in relation to our LNG terminal project acquisitions, including a $8.9 million non-cash consulting fee paid in company stock to our Chairman and a former director and $5.0 million in cash to an entity controlled by our Chief Executive Officer and our President as additional consideration for intellectual and intangible properties held by ESI Holdings, Ltd.; $10.1 million in payroll-related and contract services including $7.4 million of which represents a non-cash stock option expense recorded in accordance with SFAS No. 123R pursuant to the stock options granted under the 2006 Management Incentive Plan and $0.4 million in stock grants to non-employee members of the board of directors pursuant to the 2006 Non-Employee Directors’ Stock Plan; and the remainder for legal, travel and other administrative costs.

     These costs increased significantly during 2006 primarily because we began hiring the personnel and developing the infrastructure needed to complete development of our LNG terminal projects and carry out our corporate activities. As of September 30, 2006, we had 19 employees. We had no employees at December 31, 2005.

     LNG Terminal Development Costs

     Bradwood’s predecessor company, NorthernStar LLC, operated in the development stage during the period May 17, 2005 through December 31, 2005 and generated no operating revenue during that period. There is no comparable period as 2005 was its first year of existence; however, as the Bradwood LNG terminal project development has progressed, the rate of expenditures has increased. Through December 31, 2005, we had incurred $7.7 million in development costs, primarily related to costs for environmental studies and preliminary engineering activities necessary to prepare and submit regulatory permit applications, related processes and public relations.

     The audited historical financial statements included in this prospectus represent the financial position and results of operations of Bradwood as if it were our wholly-owned subsidiary since inception. Bradwood was determined to be a variable interest entity (VIE) under the Financial Accounting Standards Board’s Financial Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51.” Accordingly, we were determined to be the primary beneficiary of Bradwood, and therefore Bradwood has been consolidated as if it were a wholly-owned subsidiary in our historical financial statements presented herein, though we held only a 50% equity interest in Bradwood as of December 31, 2005

     Other General and Administrative Expenses

     Other general and administrative expenses were $0.9 million for the year ended December 31, 2005. These costs relate to general corporate activities including consulting and professional fees, public relations, rent, utilities, and non income-related state and local taxes. As of December 31, 2005, the Company had no employees.

2006

     In March 2006, we issued membership units (NorthernStar units) in NorthernStar Natural Gas LLC (NorthernStar LLC) to holders of interests in our LNG terminal projects. Under GAAP, we are acquired to record the assets required at the historical cost of the prior owners of the LNG terminal projects. We followed Staff Accounting Bulletin 103, Topic 5, Item G “Transfer of Nonmonetary Assets by Promoters or Shareholders” (SAB 103) which requires that transfers of non-monetary assets to a company by its promoters or shareholders in exchange for stock prior to the company’s initial public offering be recorded at the transferor’s historical cost basis as determined under GAAP. The following table sets forth the consideration paid: (a) in cash, (b) through the issuance of notes payable, and (c) in shares of our common stock, giving effect to the conversion to corporate form on May 16, 2006 and with the issuance of 210,000 shares for each membership unit to the then-existing equity holders of each of the membership units outstanding.

     NorthernStar LLC issued 93.48 NorthernStar units, cash, and obligations to pay cash as consideration for the interests in Clearwater and Orion and the 50% interest in Bradwood that it did not own. Additionally, 4.64 NorthernStar units were issued to our Chairperson and a former director as advisors. These units were converted to 20,605,200 shares of common stock on May 16, 2006. MatlinPatterson also received 100,000 additional shares in conjunction with the exchange of advances and the indebtedness owed to it by our three LNG terminal project companies. MatlinPatterson was also granted an option to have up to 2,920,000 Mcf per year of gas processed out of interruptible capacity for its own account per terminal for an option exercise price equal to 0.5% of the cost of each terminal. The exercise of this option to purchase interruptible capacity will not affect our ability to sell all or substantially all of our base, firm capacity under TUAs. See “Certain Relationships and Related Transactions — Exchange of Debt and Preferred Interests; Preferential Capacity Rights.”

     On March 7, 2006, a limited partnership controlled by Mr. Garrett and Mr. Soanes, and in which Mr. Glessner holds a minority interest, exchanged the 50% common membership interest in Bradwood that NorthernStar LLC did not own in exchange for NorthernStar membership units. On March 7, 2006, NorthernStar LLC acquired intellectual and intangible properties held by ESI Holdings, Ltd., an entity controlled by Mr. Garrett and Mr. Soanes, related to the LNG development business for $5.0 million. This amount was expensed as a general and administrative expense in the accompanying Statement of Operations for the Nine Months Ending September 30, 2006.

     On March 27, 2006, MatlinPatterson received a 40% equity interest in Clearwater for the commitment to finance up to $16.0 million for development costs. The remaining equity interest was held by the then-existing members of Clearwater. NorthernStar LLC then acquired the Clearwater entity by exchanging NorthernStar membership units for all of the Clearwater common membership interests, making Clearwater a wholly-owned subsidiary. NorthernStar LLC issued 41.15 NorthernStar membership units in the acquisition of Clearwater.

     MatlinPatterson formed Orion on March 7, 2006 and acquired the intellectual property and intangible rights from an entity controlled by Mr. Garrett and Mr. Soanes. The acquisition price was comprised of $1.0 million in cash, 19.55% of the equity interests in Orion, and $2.66 million in non-interest bearing notes (which were discounted by us to $2.2 million using a rate of 10%) and a commitment by MatlinPatterson to provide development cost funding for the LNG terminal project of up to $21 million. NorthernStar LLC then acquired Orion by exchanging 20.46 NorthernStar membership units for all of the Orion common membership units. Orion had no operations or assets prior to the acquisition of these project assets.

     The majority of the assets acquired in the above transactions are related to ongoing development activities. The liabilities incurred as a result of these transactions and unpaid as of September 30, 2006 primarily relate to the non interest bearing note payable assumed in the Orion transaction ($2.2 million) and the non interest bearing advance note payable assumed in the Clearwater acquisition ($6.0 million).

     On May 17, 2006, we issued $100,000,000 in Senior Convertible Notes due 2013 (convertible notes). The convertible notes are interest bearing and we, at our discretion, may pay interest in cash or in-kind by increasing the principal amount of the convertible notes. The convertible notes bear interest at 5% per annum if paid in cash and 7% per annum if paid in kind. Interest is payable on May 15 and November 15 of each year. We chose to pay in-kind on the initial interest payment date,

November 15, 2006. The interest rate is subject to increase by 1% under certain circumstances, including if we fail to complete certain milestones, such as the filing of a registration statement for an initial public offering; meeting an established deadline for the date such registration statement is declared effective by the SEC; and meeting an established deadline for the completion of an initial public offering; however, any such increase in interest is removed upon completion of the milestone. Unless previously converted, redeemed or repurchased, the convertible notes are convertible at any time prior to May 15, 2013 into shares of our common stock with a par value of $0.01 per share, at an initial conversion price of $9.12 per share. The conversion price is subject to adjustment in certain circumstances.

     The convertible notes may be redeemed at our option after a qualified initial public offering (Qualified IPO) on the later of 18 months after the issue date or 12 months after the Qualified IPO subject to satisfaction of certain conditions, at 100% of the principal amount plus additional amounts set forth in “Description of Senior Convertible Notes.” A Qualified IPO is an underwritten initial public offering at not less than $10 per share and with gross proceeds to us and any selling stockholders of more than $125 million. This offering will constitute a Qualified IPO. The holders may require us to repurchase all or any portion of the convertible notes on May 17, 2009 in cash at a price equal to 100% of the principal amount plus accrued and unpaid interest. We may also redeem the convertible notes at any time after the third anniversary of the date of issuance of the convertible notes at our option at 100% of the principal amount plus accrued and unpaid interest, subject to satisfaction of certain conditions. Unless previously converted, redeemed or repurchased, the convertible notes will mature and be payable on May 15, 2013 at 100% of the principal amount plus accrued and unpaid interest. Upon the occurrence of a change of control, we are required to make an offer to repurchase any outstanding convertible notes at 110% and 100% prior to a Qualified IPO and after a Qualified IPO, respectively, plus additional amounts as stated in the convertible notes.

     We are required to file within 90 days of the completion of this offering a Registration Statement to register the convertible notes and the underlying shares of our common stock or we begin to incur liquidated damage penalties. See “Description of Senior Convertible Notes.”

     See “Description of Senior Convertible Notes” for further discussion of the terms and conditions of these securities.

Bradwood Funding

     Funding for Bradwood’s development activities was through a total financing commitment with an affiliate of MatlinPatterson for $14.0 million with advances of $6.9 million as of December 31, 2005. These amounts substantially funded all of the business activities of Bradwood from its inception through December 31, 2005. These amounts were converted to capital upon issuance of the convertible notes described above as part of MatlinPatterson’s consideration for its acquisition of equity in us.

LNG Terminal Development

     We are primarily engaged in developing LNG terminals and expect to spend the next several years developing our projects and continuing the permitting and approval process with federal and state agencies. These LNG terminal projects will require significant amounts of capital and are subject to risks and delays in completion. Even if successfully completed, these projects will not begin to operate and generate significant cash flows until 2010, at the earliest, and their generation of revenue from on-going operations will be subject to various risks, including credit risks inherent with reliance on a small number of customers, and operational risks including those of the LNG terminal as well as connecting pipelines and related infrastructure, among other things.

     As a result, our initial and on-going business success will depend to a significant extent upon our ability to obtain the funding necessary to construct our proposed LNG terminals and commence operations, and to finance the costs of staffing, operating and expanding our company during the long development process and our ability to negotiate and execute TUAs.

     We expect for the near term that our operations will primarily consist of expenditures for development of our three LNG terminal projects to a point at which they have the approvals and financing necessary to commence construction. Our ultimate generation of revenues will depend on our ability to obtain TUAs for our projects. Although we believe it will be possible to negotiate such agreements early in each project’s development, we intend to finalize negotiations of our TUAs close to the time or after the time we have construction approvals in order to maximize our negotiating leverage with

purchasers of our capacity. In so doing, we believe we can obtain better economic terms. We may negotiate for payments that would begin prior to the completion of construction of our LNG terminals or we may seek higher payments commencing upon project operations. Generally, payments for our regasification services will include a fixed capacity payment and a payment based on the volumes of LNG processed.

     We currently estimate that the total construction cost for our Bradwood and Clearwater projects will be approximately $1.4 billion, excluding interest during construction and financing fees. Through September 30, 2006, we have incurred a total of approximately $20.8 million for development costs for all three of our projects.

     As of September 30, 2006, we had working capital of $77.9 million, provided primarily by the issuance of our convertible notes. We currently expect that capital requirements for our three initial LNG terminal projects will be financed in part through issuances of project level debt, equity or a combination of the two. An overview of the development and construction costs of all three initial LNG terminal projects and our detailed financing plans and anticipated capital requirements for our three initial LNG terminal development projects follow.

     Our three initial LNG terminal projects are currently in the development stage with no operating revenues. The primary costs and expenses related to our operations have been:

     Development and construction of LNG terminals is capital intensive. Because we are in the preliminary stage of developing our LNG receiving terminals, substantially all of the costs to date, related to such activities, have been expensed. These costs primarily include $17.0 million of consulting and engineering studies, permitting costs, legal, public relations, and general and administrative. As a result, we are incurring substantial net losses and negative operating cash flow.

     Our ability to obtain construction financing for our projects will depend on our ability to demonstrate the economic viability and our ability to complete construction of the LNG terminals to potential lenders which will depend on the final costs of the project, the quality of our engineering, procurement and construction (EPC) contractor, the terms of our contract with such EPC contractor, as well as our ability to attract, negotiate and sell the base, firm terminal capacity under TUAs.

          Bradwood

     By the third quarter of 2007, we anticipate receiving all federal, state and local permits, obtaining necessary financing, and commencing construction in the fourth quarter of 2007. The terminal is not expected to commence operations prior to the first quarter of 2011.

     The Bradwood LNG terminal project has been developed through MatlinPatterson’s member equity contributions and proceeds from our convertible note offering. Bradwood used $7.0 million of net cash for development-stage operating activities for the period ended December 31, 2005 and $9.3 million for the nine months ended September 30, 2006.

     We currently estimate that, in the aggregate, the Bradwood LNG terminal project will cost approximately $600 million, excluding development costs, before interest during construction and financing fees, to construct and place in service. To date, none of these costs are committed. We will seek to fund these costs using a combination of project financing, sales of equity at the project company level, or from proceeds of debt or equity offerings by us. If these types of financing are not available, we will be required to seek alternative sources of financing, which may not be available on terms acceptable to us, if at all.

          Clearwater

     We anticipate that construction of the Clearwater terminal, which will be subject to obtaining necessary financing, among other factors, will begin in the third quarter of 2008. We expect that terminal operations will commence in the second quarter of 2010.

     To date, Clearwater has been developed through member equity contributions and proceeds from our convertible note offering. Clearwater used $3.6 million during the nine months ended September 30, 2006.

     We currently estimate that, in the aggregate, the Clearwater LNG terminal project will cost approximately $800 million, excluding development costs, before interest during construction and financing fees, to construct and place in service. To date, none of these costs are committed. We expect to be able to fund these costs using a combination of project financing, sales of equity at the project company level or from proceeds of debt or equity offerings by us. If these types of financing are not available, we will be required to seek alternative sources of financing, which may not be available on terms acceptable to us, if at all.

          Orion

     Plans for the Orion project are still preliminary and we are unable to provide meaningful estimates for Coast Guard approval or construction start times. Orion has been financed through member equity contributions and proceeds from our convertible note offering.

     Our short term liquidity needs for project development have been primarily funded with the proceeds from the MatlinPatterson fundings and from our convertible notes offering. Funding for actual construction will require additional funding and proceeds from this offering are intended to fund a portion of that amount. Construction of the LNG terminals may be financed through a combination of any or all of the following:

     Our historical liquidity and capital resources position is not representative of our current situation and expected position going forward. At December 31, 2005, Bradwood, then known as NorthernStar LLC, had working capital of $0.3 million and Clearwater had a working capital deficit of $0.6 million. Orion was not in existence in 2005. As of September 30, 2006 we had a cash and cash equivalent balance of $82.3 million, following the issuance of our convertible notes in May 2006 resulting in net proceeds of $94 million, and working capital of $77.9 million.

     Net cash used for development and general and administrative expenses for the nine months ended September 30, 2006 totaled $25.0 million, including $6.0 million in cash payments resulting from the project company acquisitions. Net cash provided by investing activities was $0.3 million for this period. We have incurred $1.2 million in capital expenditures, prior to consideration of the landlord’s allowance, primarily associated with the buildout of our corporate offices to accommodate our growth. We also paid $0.2 million for the renewal of the land option at Bradwood. These investing activity expenditures were offset by the assumption of $1.8 million in cash from the Clearwater acquisition, which was utilized to reduce liabilities

assumed in the acquisition. Net cash provided by financing activities was $105.6 million. This number was comprised of $100 million gross proceeds from the issuance of our convertible notes on May 17, 2006, reduced by $7.5 million in underwriting fees and legal costs. Additionally we received $13.1 million in capital contributions from members prior to the offering of the convertible notes.

     Prior to the issuance of our convertible notes, our source of funds was the commitment of MatlinPatterson to advance up to an aggregate of $54.3 million, of which $21.0 million was funded through April 17, 2006. These amounts were converted to capital upon issue of the convertible notes described above as part of MatlinPatterson’s consideration for its acquisition of equity in us.

     In October 2004, Clearwater entered into an agreement with an LNG supplier to provide a $14.0 million, non-interest bearing, cancelable funding commitment to be used exclusively for development of the Clearwater project. Two advances, totalling $6.0 million,were made by the LNG supplier prior to the termination of the agreement in June 2005, resulting in no further obligation to fund the remaining $8.0 million of the commitment. We are obligated to repay the advances out of the proceeds of the first draw in the event it is successful in completing a long-term construction and term loan financing for the completion of the terminal. In the event such financing is not obtained, the advances shall be repaid in monthly installments over five years upon the achievement of commercial operations of the terminal or if Clearwater makes a distribution to us. In August 2006, the LNG supplier filed suit claiming repayment of the advance had been triggered as a result of the project being acquired by us. See “—Legal Proceedings” for discussion of this claim.

     We are committed to making cash payments in the future under three office leases, two of which are for periods of one year or less. Our obligations under option agreements to purchase or lease our LNG terminal locations are renewable on an annual or semiannual basis. We may terminate our obligations at any time by electing not to renew the options.

     Our contractual obligations for indebtedness and operating leases at September 30, 2006 are as follows:

Transactions with Affiliates

     In January 2004, ESI Holdings, Ltd. entered into a consulting agreement, which was subsequently assigned to Bradwood, with a limited company controlled by Mr. Coppedge who, following the offering, will indirectly hold     % of our outstanding common stock assuming the over-allotment option is not exercised. Under the terms of the agreement, the entity provides project development management services in obtaining certain regulatory and construction permits. Among other things, the agreement provided for payments of $15,000 per month during an initial period and $34,000 per month during a subsequent period defined by certain milestones. In addition, it will receive potential bonus payments of $500,000 to $2,000,000 for the achievement of certain milestones. Payments to the related party during the period from inception through the year ended December 31, 2005 and the nine months ended September 30, 2006, were approximately $738,000 and $524,000, respectively with $212,000 and $178,000 included in accounts payable as of the year ended December 31, 2005 and the nine months ended September 30, 2006, respectively.

     Prior to their being named as our officers, Bradwood and Clearwater retained ESI Holdings, Ltd., an entity controlled by our Chief Executive Officer and our President, for certain consulting services primarily relating to the development of Bradwood’s business and strategic plans. Payments to the related party during the period from inception through the year ended December 31, 2005 and the nine months ended September 30, 2006 were approximately $841,000 and $375,000, respectively. This agreement was terminated effective March 1, 2006.

     See “—Background” and “—Purchase and Financing of Our LNG Terminal Projects and LNG Related Assets” for a description of related party transactions in our formation history.

     Concurrently with the acquisition of Bradwood and Orion, we acquired intellectual property rights relating to LNG project conceptualization and development activities from an entity owned by our Chief Executive Officer and our President in exchange for a $5.0 million cash payment which was paid on May 17, 2006. This payment has been included as general and administrative expenses in the September 30, 2006 financial statements.

     In addition, we issued shares of our common stock valued at $8.9 million to Mr. Lindner, one of our directors, and a former director, for consulting services provided during our formation and initial capitalization. These costs have also been included as general and administrative expenses in our September 30, 2006 financial statements.

     On April 1, 2006 we entered into a lease for office space in California with Real Estate Energy Company, Ltd., an entity controlled by Mr. Lindner, a member of our board of directors. The lease period extends through May 31, 2007 and is terminable upon 30 days notice with no termination penalty. Payments for the lease are $2,000 per month, which we believe is indicative of the market rates for such commercial office space and services available in the local region.

Critical Accounting Estimates and Policies

     The selection and application of accounting policies is an important process that will continue to develop as our business activities evolve and as accounting rules continue to be developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment, applied to the specific set of circumstances existing in our business. We make every effort to comply with all applicable rules on or before their adoption, and believe the proper implementation and consistent application of the accounting rules are critical. Nevertheless the accounting literature does not specifically address every situation. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by analogizing to similar situations and the accounting guidance governing them, and consult with our independent accountants about the appropriate interpretation and application of these policies.

     We are in the preliminary stage of developing our LNG terminals. Our policy is to 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 costs related to environmental studies and preliminary engineering activities necessary to prepare and submit regulatory permit applications for the LNG terminal and related pipelines and related regulatory processes and public relations. Land costs associated with LNG terminal sites are capitalized. Costs of certain permits will be capitalized as intangible LNG assets when we have received approval to commence construction. We have also capitalized costs related to options to purchase or lease land that may be used for potential LNG terminal sites.

     LNG regasification capacity fees that are advanced prior to performance of any services or the availability of operational capacity will initially be deferred and will be recognized as revenue once capacity becomes operational over the term of the respective TUA.

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent gains and losses at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

     We evaluate our estimates on an ongoing basis, including those related to accrual of expenses, the useful lives of property and equipment, and assumptions used in valuing common stock options for the purpose of determining stock-based compensation. We base our stock option expense calculations on available market information, appropriate valuation methodologies, including the Black-Scholes-Merton option model, or the Model, and on various other assumptions that are believed to be reasonable, the results of which form the basis for making judgments about the carrying value of assets and liabilities. The inputs for this Model are stock price at valuation and issue date, strike price for the option, dividend yield, risk-free interest rate, life of the option in years, the expected forfeiture rate and volatility.

     In June 2005, the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force reached a consensus on Issue No. 05-6, Determining the Amortization Period for Leasehold Improvements (EITF 05-6). The guidance requires that leasehold improvements acquired in a business combination or purchased subsequent to the inception of a lease be amortized over the lesser of the useful life of the assets or a term that includes renewals that are reasonably assured at the date of the business combination or purchases. The guidance is effective for periods beginning after June 29, 2005. The Company’s adoption of EITF 05-6 did not have a significant effect on its financial statements.

     In May 2005, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 154, Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3 (SFAS No. 154). SFAS No. 154 requires retrospective application to prior periods’ financial statements for changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle, such as a change in non-discretionary profit-sharing payments resulting from an accounting change, should be recognized in the period of the accounting change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted for accounting changes and corrections of errors made in fiscal years beginning after the date this statement was issued. The Company’s adoption of SFAS No. 154 is not expected to have a material effect on the Company’s reported financial position or results of operations.

     In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29” (SFAS No. 153). The guidance in APB Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB Opinion No. 29), is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of assets exchanged. The guidance in APB Opinion No. 29, however, included certain exceptions to that principle. SFAS No.153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005. Our adoption of SFAS No. 153 is not expected to have a material impact on our reported financial position and results of operations.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157), which clarifies the definition of fair value, establishes guidelines for measuring fair value, and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements and eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 will be effective for the Company on January 1, 2008. The Company is currently evaluating the impact of adopting SFAS 157 on its financial position, cash flows, and results of operations.

     In September 2006, the Securities and Exchange Commission (SEC) released Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB 108). SAB 108 provides interpretive guidance on the SEC’s views on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. The provisions of SAB

108 will be effective for us for the fiscal year ended December 31, 2006. We are currently evaluating the impact of applying SAB 108 but we do not believe that the application of SAB 108 will have a material effect on our financial position, cash flows, and results of operations.

     The development of our LNG terminal business is based upon the belief that prices of natural gas will continue to support the development of LNG terminals in the United States. Any decline in the price of natural gas in the United States below those levels could significantly, negatively affect our ability to develop and operate LNG terminals.

     We have cash investments that we manage based on internal investment guidelines emphasizing liquidity and preservation of capital. These investments are stated at historical cost, which approximates fair market value on our consolidated balance sheet.

     The information in the section below has been derived, in part, from various official, private and public sources. Our commentary is based upon management’s current understanding of industry conditions and speak only as of the date of this prospectus unless the context indicates otherwise. This information has not been independently verified by us or the Initial Purchaser and may not be consistent with other third-party information. We believe that the information included in this prospectus from industry surveys, publications and forecasts is reliable.

     During the first nine months of 2006, North America consumed an average of more than 60 billion cubic feet per day (Bcf/d) of natural gas. The United States is the largest energy consumer in the world and is expected to require the largest increase in LNG imports to meet its growing demand for natural gas. LNG only accounted for approximately 3% of total United States gas consumption in 2005. However, declining North American natural gas reserves coupled with steadily increasing demand is creating a constrained supply with a projected shortfall of 13 Bcf/d by 2015 based on projections by the Energy Information Administration (EIA).

     The California and the Pacific Northwest gas markets are at the end of the North American pipeline system and import over 80% of their natural gas supply from neighboring states or Canada. As a result, these markets are at risk of supply disruptions caused by growth of demand in “upstream” gas markets as gas reserves in North America decline. We believe that West Coast LNG terminals are needed to increase regional gas supply and reliability by allowing these markets to access the abundant reserves of natural gas in the Asia Pacific and Middle East regions. Currently, there are only five operational LNG terminals in North America, all of which are located on the East or Gulf Coasts of the United States. According to the Federal Energy Regulatory Commission (FERC), five LNG terminals are currently under construction in North America, but only one of these is on the west coast of North America, located on the Baja Peninsula in Mexico.

     We believe that natural gas suppliers in the Asia Pacific and Middle East regions will have a cost, including a 12% return on capital, to produce, liquefy, ship and deliver regasified LNG through our terminals to West Coast pipeline networks that will be $2.50 — $4.70 per million British thermal unit (MMBtu). This will enable them to compete favorably with North American domestic supplies of natural gas given current and projected natural gas market prices. On December 5, 2006, the Henry Hub spot rate for immediate natural gas deliveries was $7.32/MMBtu, and the price on New York Mercantile Exchange (NYMEX) for futures contracts for first quarter 2011 deliveries, when we expect Bradwood to be in operation, was approximately $8.02/MMBtu (this futures pricing is not necessarily indicative of actual pricing that will ultimately be experienced in first quarter 2011).

Demand for Natural Gas

     North America is one of the largest interconnected natural gas markets in the world consuming more than 75 Bcf/d, of which the United States alone accounts for more than 60 Bcf/d. The U.S. is the world’s largest producer, consumer, and net importer of energy, ranking eleventh worldwide in reserves of oil, sixth in natural gas, and first in coal. While we believe oil will continue to be the preferred choice for the production of transportation fuels (gasoline and diesel) and coal consumption will continue to dominate as the primary fuel for existing base load electric power generation, natural gas consumption is forecast to have the greatest demand growth of all hydrocarbon fuels in the United States, driven by the need for clean and efficient mid-market and peaking power generation, for industrial use and home heating. In its 2006 Energy Outlook, the EIA forecasts U.S. natural gas demand to grow at an average rate of 1.25% per year, with gas demand increasing from its current level of 61 Bcf/d to 74 Bcf/d by 2025.

     In recent years, despite record gas prices and record levels of drilling activity, the production of natural gas in the United States and Canada has failed to increase. The 2006 EIA long-term gas outlook predicts the production of natural gas in North America to remain nearly flat through 2015 as shown below. Although U.S. unconventional production is expected to increase marginally, Canadian and conventional U.S. gas production, not including Alaska and Hawaii, is projected to

decrease. With the continued increase in demand and flat production profile, a potential natural gas shortfall of as much as 13 Bcf/d is forecasted by 2015.

          Source: EIA 2006 International Energy Outlook & EIA 2006 Annual Energy Outlook

     As the gas market begins to recognize the expected growing imbalance between supply and demand, we expect natural gas prices will rise until the market reaches equilibrium. There has been a significant rise in the North American market reference gas price measured at Henry Hub over the past six years with prices ranging from a low of $2.72/MMBtu in January 2000 to a high of $13.36/MMBtu in October 2005 because of real or perceived shortfalls of natural gas supply.

          Source: NYMEX settled prices.

     As illustrated below, over the past two decades, increases in new natural gas reserves have far exceeded the amount of gas produced during the same period, doubling the estimated proven reserves from approximately 3,300 trillion cubic feet (Tcf) in 1984 to more than 6,300 Tcf at year end 2004. Many of these increases resulted from discoveries resulting from drilling for oil. While global proven reserves have increased over 80% during the last 20 years, North American reserves have declined by 30% during the same period. In its Statistical Review of World Energy 2005, BP (formerly British Petroleum) estimates that at present production rates, proven global reserves will sustain current global demand for 66 years.

          Source: BP Statistical Review of World Energy 2006.

     In addition, the U.S. Geological Service (USGS) in its most recent assessment, estimated that there is a 95% probability that the world outside of the United States contains over 2,000 Tcf of undiscovered natural gas reserves. The USGS median, or 50% probability estimate, is for 4,333 Tcf of still to be discovered reserves, which would mean that over 40% of the world’s total gas reserves have not yet been discovered. Almost all these undiscovered reserves are expected to be found outside North America. These undiscovered reserves combined with proven reserves would provide over 110 years of natural gas supply.

     Although the United States ranks as having the sixth-largest proved reserves of natural gas, North America as a whole, including Canada, the United States and Mexico, had proved reserves of only 263 Tcf as of 2005, representing approximately 4% of the proved global reserves at that time. North America is the only continental region where net proved reserves diminished in 2005 and is the only regional gas market where natural gas production has outstripped new discoveries. Moreover, the North American gas fields are mature and have been extensively explored and drilled. Within North America, the greatest share of the proved, but as yet large undeveloped reserves, are located in Alaska, the Mackenzie Delta, and the Yukon regions of Canada. Developing these reserves and associated infrastructure to transport this gas to market, will require massive capital investments estimated to be as high as $25 to $30 billion. Moreover, the construction of production facilities and pipelines in the Arctic wilderness is likely to face significant regulatory hurdles, and completion of this project could take up to 10 years.

     The worldwide LNG market is loosely comprised of two markets, the Pacific Basin LNG market and Atlantic Basin LNG market. The Atlantic Basin LNG market, including the U.S. East and the Gulf Coast and Europe, is predominately supplied

by the Middle East region and the Atlantic/Mediterranean producing regions. The Pacific Basin LNG market, which will include the West Coast, is predominately supplied by the Asia Pacific region producers. Because of their central location, Middle East region liquefaction projects are capable of economically supplying both LNG market basins. For example, the reported cost of shipping LNG from the Middle East to the Gulf Coast is estimated to be approximately $0.04-0.10 per MMBtu more expensive than shipping LNG from the Middle East to the West Coast.

     Asia Pacific region producers currently supply approximately 45% of LNG consumed globally, and have plans to increase liquefaction capacity by more than 10 Bcf/d from 2005 to 2015. During the same time period, Middle East region producers plan to add an additional 10 Bcf/d of liquefaction capacity. The following table shows the global LNG liquefaction capacity of both existing and anticipated future facilities by producing region.

          Source: Purvin & Gertz, November 2006.

     The table above shows the amount of LNG capacity currently contracted under long-term agreements. The uncontracted capacity, sometimes referred to as a supply overhang, represents the supply potential for regasification projects that require access to liquid markets that are supported by highly rated creditworthy buyers.

     Over its 40-year history LNG has become more competitive due to several advances in technology that have contributed to significantly lowering the cost for the liquefaction, transportation and regasification of LNG. Together, the effect of the recent technological advances, increased scale and more competition have resulted in LNG competing favorably with other sources of gas supply. We believe LNG can be delivered to the West Coast at a price of between approximately $2.50 to $4.70/MMbtu as detailed in the attached table, which shows the build up of the cost structure of the LNG value chain for various existing LNG supply projects supplying the Pacific Basin LNG market (excluding potential or proposed LNG supply projects at Gorgon, Peru and Sakhalin).

     LNG has been used to provide peaking services for natural gas deliveries in the United States for many years. There are 126 small scale LNG storage facilities that provide peak shaving and load balancing services throughout the United States.

     In the 1970s and early 1980s, four LNG terminals capable of receiving cargoes by LNG carrier were constructed and operated for a brief period of time. As a result of the decline in natural gas prices that occurred in the late 1970s, all but one of those terminals were decommissioned as the cost of delivered LNG became noncompetitive with conventional U.S. domestic supplies. Now, each of the decommissioned terminals has since been reactivated, and have undergone or are

proposing substantial capacity expansions. Moreover, all conventional regasification facilities are fully contracted for periods in excess of 20 years.

     The following table presents the existing LNG imports terminals in the United States that are capable of receiving LNG from LNG carriers and their related daily send-out capacity:

     Although additional LNG regasification capacity is under construction in North America, less than 0.75 Bcf/d of LNG supply to North America is expected to flow through these LNG terminals to the southwestern U.S. markets.

     We believe the projected supply shortfall in the west coast of North America can cost-effectively be met by LNG since North America is not within economical pipeline distance of gas reserves in other regions and gas supplies from Alaska are not expected to be developed prior to 2015. Furthermore, construction of major pipelines connecting Rockies gas with eastern pipelines such as Kinder Morgan’s Rockies Express and CenterPoint’s Mid-Continent Express will transport gas production away from the west coast of North America. Whether or not the LNG industry will be able to supply as much as 13 Bcf/d of LNG by 2015 is uncertain at this stage. We believe it is likely that supply and demand will be balanced at a higher price level balancing the increased level of drilling and production and reduced demand. Under such a scenario, LNG is expected to play an increasingly significant role in balancing supply and demand.

     The LNG supply overhang is primarily concentrated in the Asia Pacific region where the availability of reserves has outpaced the growth in the Pacific Basin LNG market. Other than the west coast of North America, the likely Asia Pacific region customers for the projected additional LNG supplies in Asia Pacific and Middle East regions are the established LNG-consuming countries of Japan, South Korea and Taiwan, and the emerging economies of China and India.

     The traditional Pacific Basin LNG markets of Japan, Korea and Taiwan offer potential suppliers the advantage of an established infrastructure, relatively short supply lines and creditworthy buyers, but these markets are relatively saturated, highly seasonal, and are characterized by oligopoly/monopoly structures. Long-term pricing for LNG in the Asia Pacific market is largely based on formulae that link the LNG price to the price of selected crude oil and alternative energy products. Additionally, these contracts often contain price formulas that limit the impact of the crude oil price movements above and below certain crude oil price levels, commonly referred to as the “S” Curve. The “S” Curve typically reduces the volatility by reducing the rate of increase (when prices are high) or decrease (when prices are low) in the LNG price once certain agreed upon levels are reached.

     India and China are fast growing markets in the Asia Pacific region with huge demand potential. We believe the lack of downstream gas distribution infrastructure, non-competitive pricing, and credit uncertainty will present formidable challenges to developers of an LNG liquefaction project looking to these markets as off takers. As reported in LNG in World Markets in November 2006, China’s earlier priced LNG contracts with North West Shelf and Tangguh were priced far below global LNG prices (less than $3.80/MMBtu). Recently signed contracts, such as the Shanghai LNG/Petronas agreement, suggest China is now willing to pay closer to market rate ($5.80/MMBtu at an oil price of $60/bbl). India and Pakistan, however, based on recent negotiations with Iran and published in Platt’s LNG Daily in December 2006, are targeting to pay no more than $4.50/MMBtu for LNG compared to prices in the traditional Pacific Basin markets of approximately $6 to $8/MMBtu.

     In contrast, U.S. prices are expected to average $1/MMBtu higher than other traditional Pacific Basin markets, $2/MMBtu above China and in excess of $3/MMBtu higher than India and Pakistan. As a result, we believe LNG producers are likely to view the West Coast market more favorably than selling more LNG into India and China at terms similar to those of existing contracts.

     NorthernStar Natural Gas Inc. was founded in May 2005 to develop, own and operate liquefied natural gas (LNG) receiving/importation terminals on the West Coast of the United States (West Coast). We consolidated ownership of our LNG terminal projects in March 2006 to take advantage of project portfolio diversification, economies of scale, and greater access to capital.

     The members of our senior management team have significant project development experience and have been involved in the development of more than 50 energy infrastructure projects with an aggregate cost of over $15 billion. They have been directly involved in either the development, construction or operation of nine LNG terminal projects, including our three development projects.

     Our LNG terminal projects, when complete, will provide direct access to major West Coast natural gas demand centers. We intend to negotiate and sign terminal use agreements (TUAs) for all or substantially all of the long-term base capacity of each LNG terminal with highly rated creditworthy counterparties. We expect to provide offloading and regasification services under the TUAs without taking ownership of LNG or natural gas. Each TUA is expected to have a 20-year term and to generate a steady, predictable stream of contracted fee payments with no commodity price risk. In addition, we may periodically sell capacity to third parties or purchase, regasify and sell cargoes of LNG on a spot basis as opportunities arise when the terminals’ firm capacity is not being utilized by our TUA customers, generating additional revenues to supplement those received under the TUAs.

     Our existing LNG terminal project portfolio consists of one project in Oregon and two projects in Southern California.

     Our three LNG terminal projects are designed to have an aggregate sustainable base capacity of 3.4 Bcf/d and expansion capability that could increase our base capacity to 4.4 Bcf/d.

     We expect the proceeds of this offering to fund the equity portion of the construction of our Bradwood LNG terminal project, to fund the continued development of our remaining initial projects, and to fund the development of LNG projects in addition to our initial projects that we determine to have strong development potential, to pay the transaction costs related to this offering and to fund working capital for general corporate purposes. We expect construction of our LNG terminals to be funded by project financings supported by TUAs with highly rated creditworthy parties. The aggregate construction cost for our Bradwood and Clearwater projects is projected to be approximately $1.4 billion, excluding interest during construction and financing fees. Through September 30, 2006, we have incurred a total of approximately $20.8 million in development costs for all three of our projects.

     We believe that our competitive strengths include the following:

     Strategic project locations provide Pacific basin suppliers with access to attractive U.S. West Coast markets. We have selected the locations of our LNG terminals because each offers (i) access to attractive markets; (ii) reduced downstream transportation costs for our customers; (iii) the opportunity for cost-effective development and construction, reducing unproductive capital investments; and (iv) reduced development time for permitting and construction.

     Significant barriers to entry based on advanced positioning in regulatory approval processes and natural / existing infrastructure of LNG Terminal sites. We believe that Bradwood and Clearwater, if completed on schedule, will be the first operating LNG terminals in their respective markets. Bradwood is the only LNG project in the Pacific Northwest to have completed the Federal Energy Regulatory Commission (FERC) prefiling process under Section 3 of the Natural Gas Act for authorization to construct and operate an LNG receiving terminal. We believe Bradwood is approximately 6 to 12 months ahead of competing projects in the region reflecting the current stage of its permitting activities. Its deepwater location does not require a costly breakwater or significant dredging. Clearwater utilizes an existing platform and does not require construction of LNG storage facilities, thus we believe that it can have a 24 to 30 months shorter construction period compared to other offshore terminal designs.

     Portfolio of LNG Terminal projects provides economies of scale, market optionality and increased likelihood for success. We believe that our portfolio of LNG terminal projects in Oregon and California will be more attractive to potential TUA capacity holders than single project entities because we can provide our terminal customers with flexibility to deliver

LNG supply to multiple receiving points connecting to several major pipelines and West Coast markets. Further, we believe that simultaneously pursuing a portfolio of LNG terminals will provide economies of scale at the development, TUA marketing, financing, construction and operating stages. We believe that we will be able to leverage our knowledge and experience as we develop our projects to expedite the permitting process and to increase the likelihood of success for each successive project.

     Seasoned and incentivized management team with significant project development experience. The members of our senior management team have significant project development experience, having been involved in the development of more than 50 energy infrastructure projects with an aggregate investment of over $15 billion. They have been directly involved in either the development, construction or operation of nine LNG terminal projects worldwide including all the existing projects currently being developed by us. Following the completion of this offering, our senior management team will, directly or indirectly, control approximately      % of our outstanding common stock.

     Our strategy is to become a leading independent LNG terminal developer, owner and operator in our targeted markets. These markets, including the West Coast, are those that we believe offer: (i) attractive margins to potential LNG suppliers; (ii) fewer LNG terminal competitors; (iii) high barriers to entry; and (iv) the potential to allow us to charge competitive rates with attractive margins. We intend to implement this strategy through the following steps:

     Target LNG Terminal Sites with Attractive Margins. We are presently developing LNG terminals on the West Coast to help satisfy the region’s substantial existing and forecasted demand for natural gas with LNG supplies from Asia Pacific, Middle East, and other potential LNG producers. We believe these gas producers view the liquid, heavily-traded, creditworthy U.S. market as an attractive alternative to other Pacific Basin LNG markets. We believe the barriers to entry caused by the significant regulatory, environmental and public-concern hurdles in the West Coast market will limit the number of LNG terminals built in this market. We believe that implementation of our low cost, first-to-market strategy will give us a competitive advantage in securing TUAs with attractive margins and creditworthy counterparties and in obtaining project financing for construction of our LNG terminals.

     Disciplined Project Development. The successful development and construction of LNG terminal projects requires managing the complex interaction of legal requirements, regulatory processes, technical knowledge, political environments, public policy and construction execution. Members of our senior management team, who have developed more than 50 energy infrastructure projects with an aggregate cost of over $15 billion, have formulated a disciplined project site feasibility and pre-screening process to identify attractive terminal locations, and are adept at identifying significant issues and challenges in completing our LNG terminals that require early resolution. Once a site is selected, our senior management actively manages our project team of seasoned professionals, who are supported by leading engineering, environmental, regulatory and legal firms. Each project team strives to anticipate difficulties, define strategies and analyze the needs of each constituent group and regulatory body so as to design the project to achieve as much collaboration and widespread support as possible. By applying our disciplined project development program, we believe that we will incur lower development and capital costs and more quickly complete our projects. We believe that rapid and responsible development of low-cost LNG terminals will greatly increase our likelihood of success.

     Build Cost-Effective Terminals. Our disciplined project development strategy includes a process for completing LNG terminals whose cost-effectiveness and location should allow us to generate attractive margins from our TUAs. We have sited, and are designing and engineering our LNG terminals to be cost-effective, reducing unproductive capital investments by: (i) locating our projects in close proximity to major interstate gas transmission pipelines, thereby reducing pipeline interconnection and construction costs, (ii) maximizing use of existing infrastructure where possible, such as the existing platform for Clearwater and the existing onshore third-party natural gas storage facilities in Southern California, and (iii) selecting sites that are well-suited for LNG terminal operations such as Bradwood, whose deepwater location does not require a costly breakwater or significant dredging.

     Secure Long-Term Terminal Use Agreements. We intend to negotiate and sign firm capacity 20-year TUAs with highly rated creditworthy LNG suppliers, marketers, distribution utilities or industrial consumers for all or substantially all of our terminal base capacity. We expect that the terms of our standard TUA will include an initial fee at the time of execution of the TUA, a fixed reservation charge for the monthly throughput capacity, and a variable charge for each million British thermal unit (MMBtu) processed through the facility.

     Set forth below are descriptions of each of our current projects, including our current design plans, the permitting status and information on anticipated operations. All three of our projects are in the development stage and none have received necessary permits for construction or operation. We cannot assure you that the projects will be completed as currently planned or at all.

     The Bradwood site is located on the south bank of the Columbia River in Oregon 30 miles from the Pacific Ocean, with direct access to a deepwater channel capable of accommodating LNG carriers with sizes up to 220,000 cubic meters. We designed the Bradwood site to have an initial sustainable base capacity of 1.0 Bcf/d, a peak capacity of 1.3 Bcf/d and an on-site storage capacity of 7.0 Bcf/d provided by two 160,000 cubic meter storage tanks. The Bradwood site has also been designed to accommodate an additional 160,000 cubic meter storage tank, additional vaporization capacity and gas compression along the connecting pipeline to expand the base capacity to approximately 2.0 Bcf/d. We hold an option to purchase the site, comprised of approximately 420 acres with approximately 55 acres zoned for Marine Industrial use.

     We have agreed with Northwest Natural Gas Company (NW Natural) to coordinate the permitting of a connecting pipeline under a consulting services agreement, which also provides NW Natural with a non-exclusive option to construct and own the connecting pipeline (Bradwood Pipeline). NW Natural is headquartered in Portland, Oregon and is primarily engaged in the local distribution of natural gas to over 600,000 customers through separate systems in Oregon.

     In addition to the Bradwood Pipeline application, we have recently submitted a request for service to TransCanada and NW Natural for their open season under which they would construct, own and operate a pipeline that would connect the Bradwood terminal to Williams’ Northwest pipeline at Molalla and TransCanada’s GTN Pipeline near Madras. This will provide Bradwood and/or other shippers with gas transportation service from the LNG terminal to the pipeline systems of both the Northwest Pipeline Company and TransCanada’s GTN Pipeline, which can deliver approximately 2.0 Bcf/d into Northern California at the Malin, Oregon interconnect point.

     We estimate the total capital required for constructing Bradwood LNG terminal to be approximately $600 million, excluding interest during construction and financing fees, which we expect to fund through a combination of project financing, proceeds from this offering and proceeds from future debt or equity offerings. We estimate the remaining project development expenses to reach the construction phase to be approximately $18 million, which we intend to fund with existing cash and equivalents.

     The U.S. Pacific Northwest gas market is supplied by three main corridors: the Northwest Pipeline Corporation owned pipeline system, which runs along the Pacific coast to southwestern Oregon; the Northwest Natural Gas owned pipeline system, which runs through Western Oregon; and the Gas Transmission Northwest Corp owned pipeline which runs from Alberta’s Western Canadian Sedimentary Basin to Northern California. Together these pipelines access the Oregon, Washington, Idaho, Nevada and California gas markets, which in the aggregate averaged 8.8 Bcf/d in 2004.

     Natural gas demand in the Pacific Northwest gas market (i.e. Oregon, Northern California, Idaho, Washington and Nevada) averaged 4.5 Bcf/d in 2005. Industrial consumers accounted for over 1.3 Bcf/d of gas demand, commercial/residential consumption averaged 1.5 Bcf/d of gas demand, and natural gas fired power plants consumed an average of 1.7 Bcf/d of natural gas during this period.

     According to Wood Mackenzie, natural gas demand in the Pacific Northwest is expected to increase 1.9% annually compared to 1.5% nationally due to expanding coastal population and difficulty of getting coal power plants permitted in California. Through 2015, peak demand is expected to grow from approximately 5.5 Bcf/d in 2005 to approximately 6.4 Bcf/d in 2015.

     According to the InterContinental Exchange (ICE) the Pacific Northwest gas market is among the most liquid gas markets in the country, as illustrated by the growth in trades at key market hubs such as Malin and PG&E Citygate, where next day trades have nearly tripled between 2003 and

2005 to volumes that rival Henry Hub. Average actual trades per day for 2005 were 52 with an average of 20 parties in PG&E Citygate and 48 per day with an average of 21 parties at Malin, compared to 69 trades with an average of 30 parties for Henry Hub.

     Permitting Status

     Bradwood is the only LNG terminal project in the Pacific Northwest to have completed the Federal Energy Regulatory Commission (FERC) prefiling process, and whose formal applications to the FERC have been accepted into the application process under Sections 3 and 7 of the Natural Gas Act for authorization to construct and operate an LNG receiving terminal and pipeline. Under its current policy, the FERC will not regulate the terms and conditions of service or the rates charged for LNG terminal services by the Bradwood LNG terminal. However, the terms and conditions of services as well as the rates charged by the Bradwood Pipeline will be regulated by the FERC and service thereon will be on an open access basis. We are anticipating commencing commercial operations in the first quarter of 2011.

     Under the federal Natural Gas Act, as amended in 2005, the FERC now has exclusive authority to approve the onshore siting of LNG terminals, subject to certain state approvals required under the federal Coastal Zone Management Act, the federal Clean Air Act, and the Federal Water Pollution Control Act. In March 2005, Bradwood was accepted by the FERC into the FERC’s pre-filing process for both its LNG terminal and pipeline. In accordance with the FERC’s pre-filing process, we prepared detailed draft environmental and technical resource reports (Resource Reports), for review by the FERC staff, state and federal agencies, as well as the general public. A formal application was submitted in June 2006, successfully moving the project from pre-filing to final application stage. The FERC is the lead agency for preparation of the Environmental Impact Statement (EIS), for the project pursuant to the National Environmental Policy Act of 1969. Consistent with the FERC’s published environmental report guidelines, we have conducted numerous detailed studies required to complete the preparation of 13 Resource Reports for the LNG terminal and 12 Resource Reports for the Bradwood Pipeline, each of which covers all of the topics specified by FERC guidelines. Since acceptance into the FERC’s pre-filing process, we have successfully completed two rounds of public meetings, submitted three draft filings with the FERC of all required Resource Reports and responded to comments in an iterative process designed to ensure that a thorough and detailed analysis of all aspects of the proposed project has been conducted. We have fully addressed or are currently addressing all comments and questions that we have received from the FERC staff as part of the FERC pre-filing and the FERC authorizations process. While not necessarily required by FERC regulations, we have also sought to respond to information requests from other federal and state agencies, counties and other local jurisdictions, first responders, local residents and other interested parties. As noted, a formal application was successfully filed.

     In addition to the preparation of the Resource Reports and the responses to information requests noted above, the FERC process requires, and we have successfully completed, multiple public meetings for both the LNG terminal and the Bradwood Pipeline. These meetings have been held in Astoria, Knappa, Longview and Cathlamet, Washington, and included several pipeline routing tours and several terminal site visits and open houses for the general public and all relevant state and federal agencies. We have received comments from the public at each of these meetings and we have incorporated responses to relevant comments in our current design and the resource report filings with the FERC.

     In April 2005, we submitted a notice of intent to the Oregon Department of Energy (ODOE), which is the initial filing required to begin the ODOE’s energy facility siting process that is implemented by the Oregon Energy Facility Siting Counsel (EFSC). However, after the enactment of the federal Energy Policy Act of 2005 in the fall of 2005, which gave the FERC exclusive authority to site LNG terminals, the EFSC suspended its siting process for the LNG terminal. Since that time, the ODOE has acted to coordinate comments between the various Oregon state agencies and the FERC. We have worked collaboratively with the ODOE during this period to respond directly to the legitimate concerns of various Oregon state agencies and to encourage Oregon’s participation in, and acceptance of, the FERC process.

     We have filed applications for the principal permits and approvals required outside of the FERC authorizations, including the U.S. Army Corps joint permit application for water quality, the Oregon Air Emissions Permit, the Washington State Joint application permit for the pipeline, and the Oregon Coastal Zone Consistency determination. We have also prepared a Waterway Suitability Assessment (WSA) and submitted to the Coast Guard for its review, whose conclusions will be provided to the FERC as part of the FERC authorizations process. In connection with the WSA, we have conducted numerous information gathering meetings and work sessions with members of the Coast Guard, local police forces, fire

departments, emergency response personnel, the ODOE, port user groups and senior managers of upstream ports. We have also done extensive modeling of the river transit and berthing/unberthing maneuvers using a world class ship simulator and have had Columbia River pilots validate the adequacy of the tugs and the marine turning basin under extreme weather and river flow conditions.

     We are working closely with other state, federal and local agencies in the region in an effort to meet or exceed all environmental and safety standards, and to address any relevant concerns. We have coordinated and participated in numerous agency project meetings and permitting coordination efforts that include representatives of the Environmental Protection Agency, the U.S. Fish and Wildlife Service, the National Oceanic and Atmospheric Administration Fisheries Department, the Oregon Department of Fish and Wildlife, the Oregon Attorney Generals Office, the Washington Department of Fish and Wildlife, the Oregon Department of State Lands, the Oregon Department of Land Conservation and Development, the Washington Department of Ecology, the Oregon Department of Energy, the Oregon Department of Environmental Quality, the U.S. Army Corps of Engineers, the Oregon Department of Geological Resources, the Governor’s Regional Economic Development Team, the U.S. Coast Guard, the U.S. Department of Transportation, the Oregon Department of Transportation, the Oregon State Historic Preservation Offices, the Oregon Department of Agriculture and various other agencies with input into the permitting process. We are also coordinating closely with local county planning departments to ensure that all legitimate public and municipal concerns are addressed appropriately. Through cooperative efforts with these agencies, we believe that we have implemented a proactive approach that has fostered a positive working relationship and has allowed Bradwood to progress through the regulatory process on schedule and on budget.

     As part of the Bradwood permitting and development process, we have completed various studies, designs and engineering plans necessary for the development of the project. The results of such studies, plans and designs have been reported to the various agencies involved in the process of permitting, and have been reviewed in working sessions with various agencies.

     As part of the Bradwood permitting and development process, we are currently completing a number of further studies, designs and engineering plans, including:

     We filed Bradwood’s formal applications for the FERC authorization in June of 2006 and will have filed the remaining significant state and federal permits not included in the FERC process by the end of the fourth quarter of 2006. We are planning to obtain all permits by the third quarter of 2007.

     Pipeline Status and Access to Natural Gas Storage

     We engaged NW Natural under a consulting services agreement to assist Bradwood with, and to manage other third party consultants in, the preparation of the materials required to file the federal, state and local permits to construct and operate the Bradwood Pipeline. In June 2006, we filed an application for the Bradwood Pipeline (pursuant to Section 7c of the Natural Gas Act of 1938). Simultaneously, we are nearing completion of our negotiations with Bradwood’s pipeline partner, NW Natural, for NW Natural to construct and own the Bradwood Pipeline. If these negotiations result in a definitive agreement, we anticipate transferring to NW Natural any FERC authorizations that we may have received that are necessary for NW Natural to construct and operate the pipeline.

     NW Natural currently provides interstate natural gas storage services to third parties at its Mist storage facility. Shippers on the Bradwood Pipeline would have access to storage at NW Natural’s Mist storage facility, subject to agreement with NW Natural on storage service. The Mist storage facility currently has a maximum daily deliverability of 440,000 MMBtu/d and a total seasonal working gas capacity of 13.9 Bcf. Additionally, through NW Natural’s pipeline facilities, Bradwood’s customers could access available storage from the Jackson Prairie storage facility, located in Washington. The Jackson Prairie facility has a total maximum deliverability of approximately 884,000 MMBtu/d and a total working gas capacity of approximately 21.6 Bcf that is divided among the three facility owners. Through NW Natural transportation arrangements, gas from Bradwood will have access to TransCanada’s GTN Pipeline, which runs from Kingsgate at the Canadian border to

Malin in Northern California, as well as markets in Nevada and Idaho. LNG suppliers owning LNG terminal capacity in Bradwood will have access to 9.0 Bcf/d of natural gas demand.

     In addition to the Bradwood Pipeline application, we have recently submitted a request for service to TransCanada and NW Natural for their open season under which they would construct, own and operate a pipeline that would connect the terminal to Williams Northwest at Molalla and TransCanada’s GTN Pipeline near Madras. This will provide Bradwood and/or other shippers with gas transportation service from the LNG terminal to the pipeline systems of both the Northwest Pipeline Company and TransCanada’s GTN Pipeline, which can deliver approximately 2.0 Bcf/d into Northern California at the Malin, Oregon interconnect point.

     Property Status

     We hold an option to purchase the Bradwood property. The option term expires on August 15, 2008. In August 2006, we paid $200,000 to extend the option through August 15, 2007, and subsequently will be required to pay $400,000 to extend the option an additional year through August 15, 2008. The final $400,000 payment may be reduced to $200,000 provided that Bradwood agrees that an affiliate of the owners can perform all preparation work at the Bradwood site at a fair market price to be negotiated. During the option period, Bradwood has the right to use all existing licenses, permits and written reports of inspections related to the property. The exercise price for the option is $9 million prior to August 15, 2007 and $10 million thereafter.

     Community Relations

     We are engaged in developing local support in the project area. We have employed a community liaison director since mid-2005, and have solicited the support of certain local and regional union leaders and local business leaders. Our community liaison director resides in Astoria and oversees our Astoria office. In addition, we have sponsored local charitable events to develop support from individuals, businesses, political leaders, local development groups and the Port of Astoria. We have reached out to many local groups through education, distribution of information and involvement in community events.

     We designed Bradwood to have a sustainable base capacity of 1.0 Bcf/d, a peak capacity of 1.3 Bcf/d and, initially, on site storage capacity of 7.0 Bcf in the form of two 160,000 cubic meter storage tanks. The design includes a dedicated LNG carrier berthing facility capable of handling LNG carriers as large as 220,000 cubic meters with an LNG cargo unloading rate of 12,000 cubic meters per hour (m³/hr). The LNG will be transferred from the LNG carrier to the LNG storage tank using pumps on the LNG carrier and conventional LNG unloading arms located on the dock. The LNG will be held in the LNG storage tanks until needed. The design includes a vapor management system to handle the boil-off gas that forms as the LNG is unloaded and as it warms in the storage tanks. During normal operations, no vapors will be discharged to the atmosphere; instead, the LNG terminal is designed to contain and reprocess gas vapors for sale. The vapors will be pressurized by boil-off gas compressors and condensed in boil-off gas condensers. The LNG will then be removed from the storage tanks with pumps located inside the storage tanks that increase the pressure of the LNG to approximately 1,320 pounds per square inch gauge, or psig. The send out pumps are designed to transfer the LNG to submerged combustion vaporizers, which will warm the LNG to a gaseous state. Submerged combustion vaporizers are large water baths with stainless steel tubes submerged within the warm water. These vaporizers allow LNG to flow through the inside of the tubes where it is warmed by the heat transferred by the water bath. Approximately 1.5% of Bradwood’s LNG send out capacity is expected to be combusted by the vaporizers to maintain the temperature of the water bath at about 60 degrees Fahrenheit to vaporize the LNG. Natural gas will exit the vaporizers at a maximum pressure of 1,280 psig, with a minimum gas send out temperature from the LNG terminal of 35 degrees Fahrenheit.

     Following vaporization, the high-pressure gas will then pass through a metering station at the input valve of the connecting pipeline. Standard gas instrumentation will be installed to measure pressure, temperature, gas composition, gas flow volume and the energy (Btu) content.

     The natural gas from the terminal then flows into the connecting Bradwood Pipeline which will be 36 inches in diameter for approximately 19 miles through Oregon and reduced to 30 inches as it passes under the Columbia River and travels an additional approximately 17 miles through Washington. The natural gas will then be metered once more before it will pass

into the Williams NW Pipeline near Kelso, Washington, which is one of the main interstate pipelines serving the Pacific Northwest and British Columbia.

     The Bradwood project has been designed to take advantage of future opportunities for expansion of the LNG terminal, as well as supporting the expansion of the gas transportation infrastructure in the Pacific Northwest. Bradwood has not sought any authorization to expand the currently planned LNG terminal from its present design base of 1.0 Bcf/d. However, subject to receipt of all required additional permits, the LNG terminal is designed to be readily expandable to a sustainable base capacity of 2.0 Bcf/d with the addition of a third storage tank and additional vaporizers and pumps at an estimated capital cost of approximately $230 million, excluding interest during construction and financing fees, potentially making any potential expansion of Bradwood the lowest incremental LNG capacity in the Pacific Northwest. The Bradwood site layout and connecting pipeline are currently designed to accommodate such an expansion.

     Clearwater is sited 13 miles offshore of Oxnard, California and is currently anticipated to be constructed on Platform Grace, an existing oil and gas production platform currently owned by Venoco, Inc. We designed Clearwater to have a sustainable base capacity of 1.2 Bcf/d and a peak capacity of 1.4 Bcf/d. The project design includes two floating docks (mooring facilities), located approximately 400 feet from the platform, and a 36 inch diameter 13 mile sub-sea pipeline to transport natural gas from the platform to shore. The sub-sea pipeline will cross the beach via an underground horizontal directional drill and terminates at an existing operational electrical generation plant at Mandalay Beach in Oxnard, from which the gas would be transported through a 36 inch diameter onshore pipeline 14 miles to the SoCalGas trunk line system at Center Road, which will be established as a new receipt point into the SoCalGas system. The Clearwater project will not have LNG storage facilities other than those associated with our LNG carriers because there is abundant existing gas storage (122 Bcf) in the SoCalGas system and the incremental cost of developing offshore LNG storage is not justifiable. We expect all onshore pipeline segments to be constructed, owned and operated by SoCalGas as an integrated component of their gas transmission system. SoCalGas has extensive experience in building gas pipelines in Southern California and their franchise allows them to utilize any public road as a right-of-way. By maximizing the use of existing infrastructure (existing platform and gas storage facilities), the project is designed to minimize the impact of the LNG terminal on coastal resources and is expected to have a lower capital cost than competing terminals. Depending on the ultimate configuration of the facility, certain federal and/or state authorizations to construct and operate the natural gas pipelines associated with the facility may need to be obtained.

     We estimate the total capital required for constructing Clearwater to be approximately $800 million, excluding interest during construction and financing fees, which we expect to fund through a combination of project financing and proceeds from future debt or equity offerings. The advantage of using the Platform Grace existing infrastructure is that we believe our LNG terminal can be constructed in 18 to 24 months from the commencement of construction, compared with typical construction completion time for another offshore facility of four to five years. We estimate the total remaining project development expenses to reach the construction phase to be approximately $20 million, which we intend to fund with a portion of the proceeds of this offering.

     Primary supply sources to the Southern California gas market, which include both the SoCalGas and SDG&E utilities gas systems, are the Rocky Mountain region, Canada and California on- and off-shore production. The interstate pipelines that supply this market are the El Paso Natural Gas Company pipeline (El Paso), Transwestern Pipeline Company pipeline, Kern River Gas Transmission Company pipeline, Mojave Pipeline Company pipeline, Questar Southern Trails Pipeline Company pipeline and Gas Transmission Northwest pipeline via the PG&E intrastate pipeline system. The SoCalGas transmission system interconnects with El Paso at the Colorado River near Needles and Blythe, California, and with Transwestern and Southern Trails near Needles. According to SoCalGas, its gas system, is capable of delivering approximately 6.0 Bcf/d of gas into the market through a combination of storage withdrawal and pipeline deliveries. The maximum existing point capacity from existing pipeline interconnects is 3.9 Bcf/d. The historical peak demand has been 5.3 Bcf/d.

     According to Wood Mackenzie, natural gas demand in the Southern California gas market region averaged 3.7 Bcf/d in 2005. Industrial consumers account for 46% of gas demand, commercial/residential consumption averaged 32% of gas

demand, and natural gas use for power generation averaged 21% of gas demand. Gas demand is expected to grow at 1% annually.

     The Southern California gas market is among the most liquid gas markets in the country. According to the Intercontinental Exchange, or ICE, short-term physical liquidity of the SoCalGas trading hub has tripled in the past two years. Next day trade volumes for 2005 was 416,000 MMBtu compared to 516,000 MMBtu for Henry Hub, while actual trades per day were 52 with 22 parties in Southern California compared to 69 trades with an average of 30 parties for Henry Hub.

     Permitting Status

     The Clearwater application package was originally filed under the name of Clearwater’s predecessor company, Crystal Energy, LLC in February 2004. This application package included both a Deepwater Port (DWP) license application to the Coast Guard and a State Tidelands Lease Application to the California State Lands Commission (CSLC). Following an initial 30-day application completeness review completed by the Coast Guard and the CSLC, a request for additional project information was received. A response to comments package and amended application package was resubmitted to the Coast Guard and CSLC in July 2004. In addition to the initial project application materials, a Development and Production Plan (DPP), an amendment was submitted to the Minerals Management Service (MMS) to address questions raised regarding the termination of oil and gas production activities on Platform Grace. Additional comments were received on this application package and a response package was prepared and submitted in January 2005. This response package ultimately led to a May 31, 2005 comment letter from the Coast Guard (representing joint federal and California state agency positions) that provided further guidance and required four key data requirements which had to be provided before the responsible agencies could consider the application to have sufficient data to commence preparation of the draft environmental report. Completing the work required to address the specific data requirements and responding to the compendium of other agency comments has been the focus of project development activities over the past year. During that time, the project team renegotiated the Grace Platform agreement to clarify a number of site control issues, significantly expanded the detail in the platform stability analyses, obtained detailed offshore geophysical and geotechnical surveys and completed the studies of the expansion of the SoCalGas pipeline infrastructure to ensure the continuous delivery of up to 1.5 Bcf/d into the main SoCalGas trunk line system.

     In response to the Coast Guard letter of May 2005, Clearwater submitted an amended and restated Deepwater Port License, California State Lands Lease applications and DPP. The applications were submitted in June and July of 2006. Comments have been received and additional information has been provided. A solicitation package to engage a contractor to prepare the joint Draft Environmental Impact Study (DEIS) and Draft Environmental Impact Report (DEIR) for US Coast Guard and the CSLC should be released in first quarter 2007.

     The environmental review process for the proposed Deepwater Port project includes the preparation of a DEIS in accordance with the guidelines established under the National Environmental Protection Act (NEPA). Preparation of the DEIS is necessary to issue approvals for the Deepwater Port License. Under a memorandum of agreement between the Coast Guard, MMS, and Maritime Administration (MARAD), the EIS lead agency will be the Coast Guard. At the state level, environmental review is addressed under the regulations established under the California Environmental Quality Act (CEQA). A joint Environmental Impact Report/Environmental Impact Statement has been determined to meet the required documentation for approvals at both the state and federal requirements. The CSLC was designated as the state’s lead agency for preparation of the CEQA documentation. In addition, a separate Memorandum of Agreement between the Coast Guard and CSLC is in place to facilitate the cooperation of the federal and state permitting agencies, to contract and direct the preparation of the DEIS/EIR by a third party contractor.

     As part of the permitting and development process for Clearwater, various studies have been completed. Results of these studies have been reported to the various agencies involved in the process of permitting, and have been included in working sessions with the agencies to discuss permitting progress and scheduling.

     Platform Commercial Status

     On March 1, 2006, Clearwater entered into a new agreement with Venoco Inc. to secure access to and use of Platform Grace, the existing platform. Under the terms of this agreement, the third party granted Clearwater an option to either (a) lease Platform Grace and certain related assets for a period consistent with Clearwater’s regulatory approvals, or (b) purchase Platform Grace and certain related assets for a purchase price equal to the sum of (i) $1.00, (ii) an annual payment payable each year during the construction period (until the commencement of commercial operations) in the amount of $6 million for the first two years, $8 million for the third year and $10 million thereafter, (iii) the assumption of platform abandonment obligations, which have been estimated by the MMS to be less than $38 million, and (iv) following the commencement of commercial operations, the conditional obligation to pay an annual throughput fee to the third party of $0.04 per MMBtu based on gas throughput for the balance of the LNG terminal project’s commercial operations, but with a minimum payment of $11,800,000 per year based upon a contract volume of at least 800,000 MMBtu for all scheduled operating days. The actual throughput fee could be higher if throughput volumes exceed 800,000 MMBtu. The option may be exercised by us during the period commencing on January 1, 2008 and ending on March 1, 2012. To exercise the option, Clearwater must (x) certify to the owner that it has determined that it will proceed to develop and operate the LNG terminal, (y) provide certain letter of credit security for its payment and performance obligations, and (iii) obtain certain amendments to the existing MMS regulatory approvals for Platform Grace and the lease area in order to address Clearwater’s permitted use and eventual abandonment and removal of Platform Grace. Once the option is exercised, the owner has 120 days to cease oil and gas production from the platform and to remove all production related equipment. The option expires on March 1, 2012, and has an annual cost of $1,000.

     Community Relations

     As part of the development process, Clearwater provided information at the community level about the project and LNG in general. We have opened a local office in Oxnard and retained two members of the local community to act as our community liaisons directors. The community liaison efforts will continue and increase as the project progresses through the regulatory approval process.

     The principal components of our Clearwater Port LNG terminal will be an LNG carrier-to-platform cryogenic transfer system, the existing Platform Grace, LNG hubs, ambient air vaporizers, selective catalytic reduction and a sub-sea steel pipeline. The design allows for the safe and efficient vaporization of LNG with significantly lower emissions. The cryogenic LNG transfer system will unload LNG carriers at the berths and transport the LNG to the regasification platform via a sub-sea LNG pipeline utilizing shipboard pumps that will offload LNG carriers at a rate of up to 2,700 m³ per hour or 1.4 Bcf/d and consist of the following key components:

     The Orion site is strategically located about 25 miles offshore of Carlsbad, California with direct access to the Los Angeles and San Diego markets. The project natural gas interconnection provides access to Los Angles and San Diego gas demand centers near an advantageous pipeline interconnection point to the SoCalGas and SDG&E distribution systems. Orion is expected to be designed to include a concrete hull floating storage and regasification unit with a design capacity of 1.2 Bcf/d. The project design will utilize technical and environmental resources experienced with Clearwater to the greatest extent possible. By building upon offshore design experience we will enhance the value of our team’s institutional knowledge.

     Mr. Garrett and Mr. Soanes began developing an offshore LNG terminal project in early 2002 in Southern California. In October 2002, the development entity managed by Mr. Garrett and Mr. Soanes sold the rights to the project and was retained by the purchaser of those rights as project development adviser. The entity received consulting income during the period that it was project development adviser. The purchaser actively pursued the development of the project, including significant expenditures for seismic studies, permit applications, engineering, pipeline routing and environmental studies. In September 2005, the purchaser discontinued its development of the project and in accordance with the initial sales agreement, all intellectual property and intangible rights related to the project development reverted to the initial development entity. Mr. Garrett and Mr. Soanes, through this entity, began a new project offshore of Southern California using some of the intellectual property and intangible rights from the prior project. On March 7, 2006, the intellectual property and intangible rights related to the new project were sold to Orion, which we then acquired. The Orion development team has been able to capitalize on a significant portion of the engineering, research, design, permitting and regulatory work information related to the other project and completed by the development entity when designing and siting the Orion project.

     Preliminary project feasibility analysis has been completed and the required engineering, regulatory, legal, and public relations efforts are underway to support the filing of a Deepwater Port application with the Coast Guard and the corresponding state Tidelands Lease Application for CSLC as well as other ancillary associated permit applications. We intend to continue to pursue the development of Orion in conjunction with the approval process of our Clearwater project. A number of critical siting studies and fatal flaw analyses have been completed or are currently underway, including the following:

     Additionally we are performing a concept level mooring system design, to include a gross mooring system analysis. A number of studies and proposals are currently in progress or planned to be initiated in the second quarter of 2007.

     Our senior management team, which has participated in the development of more than 50 energy infrastructure projects worldwide with aggregate cost of over $15 billion, has been directly involved in either the development, construction or operation of nine LNG terminal projects, including involvement with our three development projects since 2002. Our senior management team provides overall management and guidance of our existing LNG terminal projects from our central headquarters in Houston, and retains the principal responsibility for project development, securing TUAs, obtaining construction financing, construction, day-to-day operations, growth of the business and profitability. Our local management teams capitalize on their considerable local and regional market knowledge, goodwill, name recognition and customer relationships to execute day to day project development activities in order to maximize project value. We have assembled a team of highly experienced and dedicated project development professionals, which includes professionals experienced in LNG development, engineering and operations, pipeline development, LNG and gas marketing, project analysis, public relations, and financial management. Each of our projects is managed by an experienced lead project developer who is dedicated to the development of the project, and is supported by a dedicated engineering resource from our in-house technical support group. The project development leads and teams meet with our senior management team routinely to review progress and ensure compliance with milestone expectations and budgets. These meetings also serve to align our corporate commercial and public relations activities with the actual progress being made in project development. We also use these project updates meetings to ensure that the projects are properly resourced as well as managed efficiently and to maximize the beneficial transfer of institutional knowledge within our development team.

     We utilize a disciplined, thorough feasibility and pre-screening study process to identify significant issues and challenges that we may face in completing development of our LNG terminals. For example, we spent over two years carefully screening potential sites along the West Coast and Canada before selecting our Bradwood site. In addition, we have conducted a detailed feasibility analysis of each project that considered, among other things, the market size, demand profiles, pipeline takeaway capacity, political environment (local, state and federal), site zoning and remoteness, geotechnical issues, waterway suitability, pipeline rights of way, wetland issues, site alternatives, dredging requirements and storage requirements. We have developed detailed permitting plans, budgets, schedules and cash commitment curves for each of our projects. We prioritize our development expenditures to address the highest risk issues as early in the development process as possible to address single-point failures, and appropriately balance project execution risk and development cost exposure. We believe that the key to successful project development is to start with well considered project fundamentals and then actively manage our project teams of seasoned, successful project professionals, supported by a team of the leading engineering, environmental, regulatory and legal firms, to work co-operatively with regulators and other stakeholders to successfully develop the project and to anticipate difficulties and define strategies that offer multiple success paths. We analyze the needs of each constituent group and regulatory entity to design each project to achieve the maximum collaboration support we believe possible. We believe that our processes will allow us to address and resolve challenges to the FERC and Coast Guard and other permitting agencies’ approval processes early by resolving undesirable project attributes before submitting our final applications.

     We expect to operate our LNG terminals as a terminal service provider and enter into long-term, firm capacity TUAs with highly rated creditworthy third parties, including LNG suppliers, natural gas marketers, distribution utilities or large-volume industrial consumers, to provide a stable and predictable cash flow to our company. We do not intend to take title or

ownership to the natural gas processed through our terminals on a firm capacity basis in order to reduce our exposure to commodity prices. The physical supply of LNG delivered to our terminals would be obtained by our customers from their own liquefaction facilities or those under contract located primarily in the Asia Pacific or Middle East regions. Customers will also arrange for delivery of LNG to our terminals. Upon delivery, we plan to process and vaporize the LNG, converting it into natural gas vapor for our customers, before the natural gas is transported through pipelines to the national gas distribution network for delivery to the ultimate consumer.

     We intend to leverage our senior management’s existing relationships with natural gas market participants and suppliers in the Asia Pacific and Middle East regions and their in-depth knowledge of the natural gas market to secure TUAs with highly rated creditworthy natural gas suppliers, marketers, distribution utilities or industrial consumers for a significant portion of our LNG terminal base capacity. We expect that these contracts for firm capacity will be for a term of 20 years and consist of a fixed payment based on the contracted firm capacity and a variable charge for each MMBtu processed through the LNG terminal. In certain instances, we may negotiate for a portion of the fixed payment to be paid by the capacity holder in advance of the commencement of commercial operations. We intend to use any such advances to further fund our development, construction, and corporate activities, and expect to pledge the future proceeds of the TUAs to obtain favorable financing to construct our LNG terminals. Depending on market circumstances, we may decide to retain a small portion of our terminals’ firm capacity or interruptible capacity to complete spot gas supply transactions to further enhance project cashflow.

     Our management is currently engaged in the formal permitting process for all of our three initial LNG terminal projects. They will be pursuing the steps necessary to construct our three initial LNG terminal projects, which are expected to include:

     Our management expects to use its breadth of experience and contacts in the LNG and natural gas markets to optimize this process.

Overview

     We currently compete primarily with companies developing other new LNG terminals on the West Coast. The FERC list of constructed, permitted or proposed LNG terminal projects in the United States, Mexico and the Bahamas as of October 19, 2006 listed 45 offshore and land-based LNG terminal projects, of which nine proposed LNG terminals are planned to be constructed on the U.S. West Coast. We believe that only a small number of these LNG terminals will be constructed.

     Competition for LNG terminal capacity takes place before an LNG terminal is built. During this time, the primary competitive factors are price of terminal service, location of facility, pipeline access to markets (including market size and value) and access to a long-term source of competitive LNG supply. Generally speaking, once the permitting process has proceeded far enough so that permission to construct the LNG terminal is probable, the developer of an LNG terminal will enter into final stage negotiations with LNG suppliers, natural gas marketers, distribution utilities or large-volume industrial consumers regarding entering into a TUA. One or more TUAs often are critical to obtaining construction financing for a project. Once all or substantially all of a LNG terminal’s base capacity has been contracted for with a third party, the LNG terminal operator is largely indifferent as to competitive market forces during the term of the TUA.

     We anticipate the following competitive forces in the LNG market:

     There are several sources of natural gas from which we may face competition which may replace the expected natural decline of natural gas production in the United States, including:

     To our knowledge, the following proposals to either study or develop LNG terminals in the Pacific Northwest have been reported in the press, as set forth in the table below. Of those, only Bradwood has completed the FERC prefiling process under sections 3 and 7 of the Natural Gas Act for authorization to construct and operate a terminal and pipeline. Of our other competitors, Port Westward LNG submitted a prefiling application in April of 2005 which was not accepted by the FERC and has not been refilled with the FERC. Jordan Cove submitted a prefiling application to the FERC in April 2006 and is actively pursuing its project.

     The following table identifies each of the LNG terminals known to us proposed to be constructed in the Pacific Northwest and sets forth, to the extent known by us, their location, distance to the nearest natural gas pipeline, estimated population density within a two-mile radius of the project site, financial sponsors and development status.

     Oregon Projects

     While there have been a number of proposed projects in California and Baja, only four projects in California have filed permit applications and there is just one active project under construction in Baja (ChevronTexaco announced that it has placed its Coronado Island project on indefinite hold because of high capital costs). A large portion of the gas from Sempra’s Costa Azul Phase I project in Baja is expected to be consumed in Mexico. Costa Azul completed a Phase II “open season” to determine the interest of potential capacity holders in taking positions in an expanded LNG Terminal. Based upon information included in the LNG Terminal “open season” filing and the preliminary estimated recourse rate for the North Baja LNG pipeline expansion “open season,” we estimate a tariff (including pipeline transportation) in excess of $0.90/MMBtu will be required to deliver natural gas to the Southwestern U.S. market (1.0 Bcf/d capacity). In testimony before the California Public Utility Commission (CPUC), SoCalGas has estimated the cost of incremental system upgrades required to receive 1.0 Bcf/d at Otay Mesa (Mexican-United States border) to be $677 million.

     We believe the cost to expand the SDG&E gas pipeline system to receive large volumes at Otay Mesa will cause the bulk of deliveries from any Baja LNG terminal expansion to be diverted to the California/Arizona border (Blythe receipt point). The capacity into the SoCalGas transmission system through the Blythe receipt point is limited, and gas will flow eastward, away from the southern California market. We believe there are no plans to increase capacity into SoCalGas through Blythe as the recent CPUC Firm Access Rights proceeding states Baja gas will displace existing supplies. The net result is that no new incremental volumes will be delivered into the SoCalGas system from this receipt point.

     Clearwater, however, would deliver incremental gas into the SoCalGas system through a new receipt point to be constructed at Center Road. In testimony before the CPUC, SoCalGas has estimated the cost of required incremental system upgrades to receive 1.5 Bcf/d at Center Road at $259 million.

     The following table gives information regarding Esperanza, Pacific Gateway and the LNG terminals identified by FERC which are proposed to be constructed in California and Baja California and sets forth, to the extent known by us, their location, estimated population density within a two-mile radius of the project site, financial sponsors and development status (distance to the nearest natural gas pipeline has not been included in this table since it is not a differentiating factor).

     Southern California and Baja California Projects

     As of November 15, 2006 we had 23 employees. None of our employees are members of any labor union and we are not party to any collective bargaining or similar agreement with our employees. We believe that our relationship with our employees is good.

     Our future success will depend, in part, on our ability to continue to attract, retain and motivate qualified employees. We focus our recruiting efforts for our key positions on identifying and retaining persons with proven industry knowledge and experience. We periodically review market compensation and benefit data to ensure that we are competitive with other industry employers and we intend to establish “best practices” throughout our operations to ensure that all employees comply with our established safety standards, those of our insurance carriers’ and all laws and regulations.

     Currently, the primary risks associated with our operations are bodily injury, property damage and injured workers’ compensation. We presently maintain liability insurance for bodily injury and third-party property damage and workers’ compensation coverage which we consider sufficient to insure against these risks, subject to self-insured amounts. We currently maintain and intend to continue maintaining workers’ compensation insurance policies that provide “first dollar” coverage.

     The construction and operation of our proposed LNG terminals and pipelines will be subject to the inherent risks normally associated with these types of operations, including accidents, pollution, earthquakes and adverse weather conditions in the Pacific Ocean and other hazards, each of which could result in a significant delay in the timing of commencement of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations face possible risks associated with acts of aggression or terrorism on our facilities and the facilities and LNG carriers of third parties on which our operations are dependent.

     In accordance with customary industry practices, we intend to maintain insurance against some, but not all, of these risks and losses; however, we may not be able to maintain insurance (as our project lenders may require) in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, results of operations, financial condition and prospects.

     On August 18, 2006, an LNG supplier, Woodside Energy Inc. (WEI), filed a complaint against Clearwater Port Holdings LLC in the Supreme Court of the State of New York, County of New York, alleging that WEI is entitled to repayment in full of the $6.0 million long-term advance payable recorded in our financial statements included in this prospectus as a result of

the acquisition by us of all of the equity in Clearwater Holdings and the issuance by us of the convertible notes in May 2006. We have filed our answer to the claim and dispute WEI’s allegations, and we believe that payment of the $6.0 million long-term advance has not been triggered at this time.

     We continue to evaluate, and may develop, additional sites that we believe may be commercially desirable locations for LNG terminals. We will opportunistically consider expansion into other geographic markets, either organically or through acquisition. By expanding into these markets, we believe that we could reduce our local market risk exposure, enhance our attractiveness to customers, and generate efficiencies through economies of scale. We will evaluate new project site candidates using the same criteria used in selecting our current LNG terminal project portfolio, including:

General

     The siting, construction and operation of our liquefied natural gas (LNG) terminal and interstate natural gas pipeline projects are subject to extensive regulation under federal, state and local laws and regulations. We are required by various governmental and quasi-governmental agencies to obtain permits, licenses, certificates and approvals for, and complete various consultations with respect to these activities. This regulatory burden increases the cost of constructing and operating our LNG terminals and failure to comply with such requirements could result in substantial penalties, delays in the project schedule or the inability to obtain necessary approvals for the projects. Because these laws and regulations change frequently, we cannot predict the ultimate cost of compliance or their impact on our business. Additional laws and regulations may be adopted that could limit our ability to do business or increase the cost of our doing business and may materially adversely affect our business, results of operations, financial condition, and prospects.

     The costs that we incur to obtain Federal Energy Regulatory Commission (FERC), Coast Guard and other governmental approvals authorizing us to commence construction of our proposed LNG terminals and to comply with the ongoing regulation of such terminals could be significant and have a material adverse effect on our business, results of operations, financial condition, and prospects. We have no control over the outcome of the review and approval process. Delay in receipt of FERC, Coast Guard or other required governmental authorizations could cause substantial delays in the commencement of construction or operations of our LNG terminals or even result in the cessation of construction or operations in some circumstances. If we are unable to obtain and maintain the necessary permits and approvals, we may not be able to recover our investment in the projects. Our failure to obtain and maintain any required permits and approvals from government and regulatory agencies could have a material adverse effect on our business, results of operations, financial condition and prospects.

     Further, any interstate natural gas pipeline transmission system connected to our LNG terminals would be subject to FERC regulation under Section 7 of the NGA. Such regulation may restrict the ability of our customers to deliver to and transport gas from our LNG terminals, which could have a material adverse effect on our business, results of operations, financial condition, and prospects. While it does not currently do so, the FERC has in the past regulated the prices at which natural gas could be sold. Federal reenactment of price controls on the sale of gas or increased regulation of the transport of natural gas could have a material adverse effect on our business, results of operations, financial condition and prospects.

     Our LNG terminal development operations also are subject to extensive federal, state and local laws and regulations that regulate the design, construction and operation of LNG import and regasification terminals, LNG vessel transit operations, and the release of materials into the environment, or that otherwise relate to the protection of the environment. These laws and regulations may restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and impose substantial liabilities for pollution or releases of hazardous substances. Failure to comply with these laws and regulations may result in substantial penalties and harm our business. Present and future legislation and regulations could cause additional expenditures, restrictions and delay of the commencement of our operations, the extent of which cannot be predicted and which may require us to substantially limit, delay or cease construction or operations in some circumstances.

     Federal laws such as Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), the Clean Air Act (CAA), the Clean Water Act (CWA), the Endangered Species Act (ESA) and the Coastal Zone Management Act, as well as analogous or additional state and local laws, have regularly imposed increasingly strict requirements for water and air pollution control, hazardous and solid waste management, species and other resource protection and strict financial responsibility and remedial response obligations. Existing environmental laws and regulations may be revised or new laws and regulations may be adopted or become applicable to us. Revised or additional laws and regulations could result in increased compliance costs or additional operating restrictions. The cost of complying with existing and future environmental legislation could be significant and have a material adverse effect on our business, results of operations, financial condition and prospects.

     In order to site, construct and operate our proposed onshore LNG terminal, we must receive and maintain authorization from the FERC under Section 3 of the NGA. The FERC authorization process under Section 3 of the NGA includes the following minimum elements:

     In addition to FERC authorization under Sections 3 and 7 of the NGA, our construction and operation of an onshore LNG terminal and pipelines are subject to additional federal permits, approvals and consultations required by certain other federal agencies, principal among which are:

     Our LNG terminal and pipelines also will be subject to U.S. Department of Transportation siting requirements, while our terminal will be subject to Coast Guard regulations regarding the safety and security of port areas. Moreover, our LNG terminal and pipeline projects also will be subject to certain state and local laws and regulations.

     The siting, construction and operation of our proposed Bradwood project in Oregon will require authorization under Section 3 of the NGA. On February 23, 2005, we requested authorization to use the FERC’s NEPA pre-filing review process in conjunction with the Bradwood project. On March 3, 2005, the FERC granted our request to use the NEPA pre-filing process and designated Docket No. PF05-10-000 as the pre-filing docket for the Bradwood project. We have completed the FERC pre-filing review process and, on June 5, 2006, we submitted Bradwood’s NGA Section 3 application for authorization to site, construct and operate the Bradwood terminal in Docket No. CP06-365-000. We anticipate the FERC issuing the DEIS by March 2007. We have targeted the third quarter of 2007 for receipt of Bradwood’s FERC authorization and starting of construction of the LNG terminal once all other federal, state and local authorizations necessary to commence construction also have been obtained. We anticipate placing the LNG terminal in service during the first quarter of 2011.

     Concurrently with the NGA Section 3 application for authorization to site, construct and operate the Bradwood LNG terminal, we filed the NGA Section 7 application in Docket No. CP06-366-000 to construct and operate the Bradwood Pipeline, an interstate natural gas pipeline facility that connects the terminal to the interstate pipeline grid. The Bradwood Pipeline is subject to the FERC’s regulation under NGA Section 7, including open access and tariff requirements. The FERC’s exercise of jurisdiction over interstate gas pipelines pursuant to NGA Section 7 and would continue as long as this pipeline is operated in interstate commerce.

     In order to own, construct and operate our proposed Clearwater and Orion offshore LNG terminals, we must receive deepwater port licenses under the Deepwater Port Act (DWPA). The DWPA empowers the Secretary of Transportation to license and regulate deepwater ports beyond the territorial limits of the United States. The Secretary of Transportation delegated the responsibility for processing deepwater port applications to the Maritime Administration (MARAD), and the Coast Guard. MARAD has the authority and responsibility to issue deepwater port licenses. The process for obtaining a deepwater port license includes:

     A series of legally mandated deadlines, totaling a maximum of 356 calendar days from the date that the application is filed, governs the DWPA license review process.

     All together, these various periods of time involve a total of 356 calendar days from the date that an application is submitted to the Coast Guard, though certain extensions of the time period may apply.

     MARAD, in consultation with the Coast Guard, issues a record of decision on the deepwater port license application. The record of decision approves, denies or approves with conditions a license. MARAD bases the record of decision primarily on the conditions for license issuance set forth in the DWPA, as amended by the Maritime Transportation Security Act of 2002. A summary of some of the more significant conditions follows:

     While not presently proposed, to the extent that we construct and operate natural gas pipeline facilities for Clearwater or Orion that connect to the interstate pipeline grid, we also must obtain authorization from the FERC pursuant to Section 7 of the NGA to construct and operate these pipeline facilities, which will be subject to the FERC’s regulation under NGA Section 7, including open access and tariff requirements.

     Permits from the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and the State of California also are required to construct certain related port facilities, such as pipelines and onshore facilities, for our LNG terminals. The Coast Guard must abide by the requirements of NEPA and must prepare an EIS that describes in detail the nature and extent of the environmental impacts of the proposed action and alternatives, discusses appropriate mitigation measures for any adverse impacts and recommends whether to approve, approve with conditions or deny the project. Moreover, our LNG terminals also will be subject to local and state laws, rules and regulations, such regulation by the CSLC under CEQA.

     The CSLC has the authority and responsibility to manage and protect natural and cultural resources on public lands within California, including tidal and submerged lands. With respect to the deepwater ports, the Lands Commission must consider whether or not to grant a lease for the sub-sea pipelines. The lease also may include conditions relating to the parts of the project not located in state waters. CEQA requires the Lands Commission to issue an Environmental Impact Report (EIR), for deepwater ports. The environmental review requirements of NEPA and CEQA are similar. The Coast Guard and the Lands Commission have agreed to issue a single, combined EIS/EIR.

     Construction and operation of all our LNG terminals are subject to numerous federal, state and local laws and regulations governing the treatment, storage, disposal, transportation, discharge, emission, and other management of chemicals, wastes, and other materials and otherwise relating to the protection of the environment. These laws and regulations may require us to obtain governmental authorizations before we may construct or operate our facilities or regulate the conduct of certain activities (such as treating, storing, or disposing of hazardous waste, discharging wastewaters or releasing air emissions into the environment). Obtaining such government approvals can be time consuming and expensive. Often such activities require detailed and multiple submissions, incorporating complex calculations and computer modeling, prepared by outside experts. Applicable environmental laws also may require us to limit or abstain from certain activities that could adversely affect endangered, threatened, or protected species, or environmentally sensitive areas. These environmental laws frequently restrict the types, quantities and concentrations of various wastes and other substances that can be released into the environment, and they may require the installation of expensive pollution control equipment and/or the use of costly treatment measures. The cost of complying with applicable environmental requirements can be significant. Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, and/or criminal penalties, the imposition of investigation and remediation costs and other obligations, or the issuance of injunctive relief.

     Environmental laws and regulations are complex. Environmental laws and regulations historically have been subject to frequent change and have tended to become more stringent over time. Changing regulatory interpretation can also make compliance more difficult and costly. Consequently, we are unable to predict future costs associated with environmental compliance or other future impacts of environmental regulation on our operations.

     Environmental laws and regulations typically provide for public notice and comment periods in connection with proposed environmental permitting and other governmental decisions necessary under environmental laws. Many members of the public continue to be focused on environmental protection issues. Recently, environmental organizations and other citizen groups, with some success, have opposed and/or sought to delay the progress of projects similar to our offshore and onshore LNG terminal projects. Such groups are expected to continue to be involved in environmental permitting and standard-setting issues, and such involvement would be expected to affect our operations both generally and on a site-specific basis. Third-party challenges may be filed with respect to specific environmental authorizations issued for the projects and third parties also may challenge the issuance of FERC, Coast Guard, and other federal authorizations for the projects on the basis of the potential environmental impacts associated with the projects. Such challenges may delay the construction or operation of our projects or result in additional conditions on our projects.

     As with the industry generally, compliance with environmental laws increases our overall cost of doing business. While these laws affect our capital expenditures and earnings, we believe they do not affect our competitive position in the industry

because our competitors are similarly affected. The principal environmental laws that may affect our operations include, but are not limited to, the following:

  CERCLA

     CERCLA, certain provisions of which are referred to as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain categories of persons who are considered responsible for the spill or release of hazardous substances into the environment. Potentially responsible persons under CERCLA include the owner or operator of the site where the spill or release occurred and persons who disposed or arranged for disposal of hazardous substances at the site. Under CERCLA, responsible persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, mitigating the effects of contamination, damages to natural resources, and the costs of certain health studies.

     When a release of hazardous substances occurs that is regulated by CERCLA, the responsible person must provide immediate notice to the government. Failure to do so can lead to penalties. In addition to statutory liabilities arising under CERCLA for releases of hazardous substances, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly resulting from the spill or release of hazardous substances. Although CERCLA currently excludes petroleum, natural gas, natural gas liquids, and liquefied natural gas from its definition of “hazardous substances,” we would be expected to generate, manage, and dispose of certain materials in our operations that are “hazardous substances” for purposes of CERCLA. Our activities involving hazardous substances could expose us to CERCLA liability if our hazardous substances are released or disposed of improperly.

     Many state governments have enacted their own statutes modeled on the federal Superfund statute. The availability of exclusions for petroleum and natural gas, and the potential scope of liability and damages, varies under the different state statutes.

  RCRA

     The federal Resource Conservation and Recovery Act (RCRA) and comparable state and local statutes, govern the management from “the cradle to the grave” of “hazardous wastes.” Those statutes also regulate solid wastes. In the event any hazardous wastes are generated in connection with our LNG operations, we would be subject to the very detailed and rigorous regulatory requirements affecting the handling, transportation, treatment, storage, disposal and cleanup of such wastes. In addition, some of our wastes may be subject to the less stringent, solid waste provisions in the RCRA statute, or applicable state and local counterparts. In many cases, states administer the RCRA requirements with federal oversight. States also are free to impose additional and more stringent requirements governing waste management practices.

  Clean Water Act

     Our operations that discharge wastewaters will be subject to the CWA and analogous state and local laws. The U.S. Environmental Protection Agency has adopted regulations governing discharges of wastewater and storm water that would be applicable to wastewater discharges from our operations. States frequently administer the CWA program under federal oversight. States also are free to impose additional and more stringent requirements governing wastewater discharges. These programs require covered facilities to obtain authorization for their discharges through limits established by appropriate discharge permits. The nature of the discharge and the scope of the relevant regulatory program will determine whether individual permits, group permits, or general permits will be required. The permits frequently impose limitations on the types and the amounts of contaminants that may be discharged via wastewater and impose other conditions that must be satisfied before wastewater may be discharged into the environment. Such requirements and limits may affect our future operations and require us to incur substantial capital expenditures.

     In addition, our operations, including construction of LNG terminals and support facilities, in areas deemed to be wetlands, or which otherwise involve the discharges of dredge or fill material into the navigable waters of the United States, may be subject to the U.S. Army Corps of Engineers’ permitting requirements under the CWA and, for certain construction activities in or affecting rivers and streams, the federal Rivers and Harbors Act.

     Similar permits would be required at the state and local levels. In some cases, state and local governments impose requirements on developments on or near waterbodies that are more stringent than their federal counterparts.

  Clean Air Act

     Our operations will be subject to the federal CAA and comparable state and local laws that restrict the emission of air pollutants and require the installation of various types of pollution-control equipment. New facilities may be required to obtain construction permits before beginning work to install new equipment or build new facilities, and existing facilities may be required to obtain construction permits before modifying their existing equipment or adding new equipment. In addition, both new and existing facilities would be subject to operating permit requirements that would need to be satisfied before they can operate their facilities. Typically, these permits are issued on an individual basis and can require the installation and use of pollution-control equipment, testing of emissions and equipment, and related pollution-control activities. The United States Congress adopted amendments to the CAA in 1990 that contain provisions potentially resulting in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. Consequently, we may be required to incur capital expenditures in the future for air pollution control equipment in connection with obtaining or maintaining permits and approvals addressing air emission-related issues. Also, EPA has developed and continues to develop more stringent regulations governing emissions of toxic air pollutants. In addition, the projects may require completion of a general federal conformity determination.

  Protected Species

     Our operations may be restricted by requirements under the ESA and comparable state and local laws. These laws seek to ensure that human activities do not jeopardize endangered, threatened, or similarly protected animal, fish, or plant species, or destroy or adversely modify their critical habitats. Proposed projects must be evaluated to determine whether they are likely to have such effects. If so, the planned projects could be halted, delayed, or altered, or their costs could be increased significantly.

  National Environmental Policy Act

     NEPA and comparable state and local laws and regulations require formal assessments of the potential environmental effects of proposed government actions. Major federal actions may require the preparation of a fairly comprehensive Environmental Impact Statement (EIS). The EIS evaluates the potential impacts and any feasible alternatives to the proposal. The EIS also identifies appropriate mitigation measures for any adverse impacts. This review process is coordinated with several federal, state and analogous agencies and is open to public comment. The results of the assessments and consideration of alternatives and potential environmental impacts may affect our ability to obtain the necessary government authorizations for the construction and operation of our terminals. They also could increase our costs or delay our projects. Several states, including California, have enacted statutes modeled on the federal NEPA law. Because our projects are expected to be subject to such environmental assessment obligations, they may affect our ability to site and develop our LNG terminals as planned.

  Occupational Safety And Health Act

     The Occupational Safety and Health Act (OSHA), and comparable state statutes, regulate the protection of worker health and safety. In addition to the OSHA requirements governing physical safety issues, OSHA also regulates worker health and safety issues arising from hazardous chemicals. In some cases, specific standards limit worker exposure to hazardous chemicals. In addition, the Hazard Communication Standard issued pursuant to OSHA requires labeling of hazardous chemicals in the workplace, the use of material safety data sheets to provide workers with hazard warning information about particular chemicals, and training of workers about hazardous chemicals, associated safety measures, and related topics.

  Community Right-To-Know

     Various statutes such as the Emergency Planning and Community Right-To-Know Act (EPCRA) require companies that use chemicals to provide detailed information to the appropriate federal, state, and local officials about the chemicals that are present at their facilities. In addition, EPCRA requires companies to file reports concerning releases of chemicals to the environment. These obligations impose significant recordkeeping obligations, and the failure to comply can lead to imposition of penalties.

  Land Use Limitations

     Federal, state and local laws regulating the development of coastal areas, sovereign submerged lands, or private property, also may prevent, affect or limit our ability to construct and operate our LNG terminals and supporting facilities as currently planned.

  Coastal Zone Management Act

     Under the Coastal Zone Management Act, states have the authority to review the potential impacts of a proposed action to the state’s coastal resources and made a determination whether the project and its potential impacts are consistent with the state’s coastal zone management plan (CZMP). FERC requires an applicant for an authorization under Section 3 of the NGA or CPCN under Section 7 of the NGA to obtain from the relevant state(s), if applicable, a determination of the project’s consistency with the state’s CZMP. Such a state determination typically may impose additional requirements or conditions upon the construction and operation phases of a project.

     Our officers have extensive experience and a strong track record in the development and realization of large capital projects. Most have held senior executive or management positions in large energy companies, with over 150 years of combined experience in the development, financing, construction and operation of energy projects such as power plants (gas, coal and nuclear), gas pipelines, LNG facilities, and gas gathering and liquids separation systems. Collectively, our senior management team has been involved in either the development, construction or operation of more than 50 energy infrastructure projects with an aggregate cost of $15 billion. In addition to our permanent management team, we also engage consultants for certain matters including legal and regulatory, engineering, environmental and public relations matters.

     The following table sets forth the names, ages and positions for each of our directors and executive officers as of December 12, 2006: