Filed pursuant to

Rule 424(b)(1)

Registration No 333-120129

2,000,000 Shares

PRB Gas Transportation, Inc.

Common Stock

This is an initial public offering of PRB Gas Transportation, Inc. No public market currently exists for our common stock. We anticipate that the initial public offering price will be $5.50 per share.

We have applied to list our common stock for quotation on the American Stock Exchange under the proposed symbol “PRB.”

We have also registered by separate prospectus the resale by our existing stockholders of up to 3,950,000 shares of common stock issuable to them upon conversion of our preferred stock and up to 45,000 shares of common stock issuable on exercise of warrants at a price of $5.50 per share. These resale shares are subject to a lockup of up to six-months. See “Underwriting.”

Investing in our common stock involves risks that are described in the “Risk Factors” section beginning on page 6 of this prospectus.

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.

Our underwriter is offering these shares on a firm commitment basis and expects that delivery of shares will be made on or about April 15, 2005. We have granted the underwriter a 45 day option to purchase up to 300,000 additional shares from us to cover any overallotments.

Gilford Securities Incorporated

April 12, 2005

TABLE OF CONTENTS

You may rely only on the information contained in this prospectus. Neither we nor the underwriter has authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. Neither we nor the underwriter is making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted.

Until May 9, 2005, (25 days after the date of this prospectus), all dealers that buy, sell or trade these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Prospectus Summary

This summary highlights key aspects of the information contained elsewhere in this prospectus. You should read this entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements included elsewhere in this prospectus. Unless otherwise indicated, the information contained in this prospectus assumes that the underwriter does not exercise its overallotment option and further assumes that 3,950,000 outstanding shares of our preferred stock are converted into an equal number of shares of common stock as of the date of this prospectus.

PRB Gas Transportation, Inc.

General

We own and operate intrastate natural gas gathering systems. We commenced operations in January 2004 upon our acquisition of certain operating assets of TOP Gathering, LLC. We operate in the intrastate gas gathering environment, which is less regulated than interstate gas transportation, and currently plan to limit our expansion to intrastate operations. We charge the gas producer or shipper a fee for gathering, compressing and dehydrating natural gas. Our gathering systems collect gas at a producer’s wellhead or at a collection point and deliver it to a transmission line owned by a third party. We do not take ownership of gas that we gather.

Our 4.5 mile TOP system, located in Campbell County, Wyoming, services 56 wells operated by three natural gas producers in the Powder River Basin area of Wyoming. The wells serviced by this system are approximately two to three years old. The gathering system has a current throughput capacity of approximately 8 million cubic feet of gas per day and is presently averaging approximately 4 million cubic feet per day or approximately 50% of capacity.

Effective August 1, 2004, we acquired certain operating assets of Bear Paw Energy, LLC also located in Campbell County, Wyoming. The approximately 200 miles of gathering lines we acquired from Bear Paw service 12 producers of natural gas in the Powder River Basin area of Wyoming. The wells serviced by this system are approximately four to five years old. The Bear Paw gathering systems’ original capacity was approximately 60 million cubic feet of gas per day. In April 2004 a portion of the system was reconfigured to reduce the operating expenses, including compression facilities, which reduced the capacity to approximately 27 million cubic feet per day. The system is currently averaging approximately 18 million cubic feet per day or approximately 66% of the reconfigured capacity.

Natural gas wells in the Powder River Basin area typically experience sharp declines in production volume in the first several years of production. Production then stabilizes and declines more ratably over a gas well’s average life of approximately eight to 10 years. Many of the wells serviced by our TOP and Bear Paw gathering systems have reached a stable decline phase of production. We believe that undeveloped reserves in the fields serviced by these systems may provide additional production that may offset future declines and possibly exceed current gas production.

We plan to expand our present operations through a combination of:

•                  enhancing the present gathering systems through operating efficiencies and expanding to service additional wells and fields;

•                  designing and building new gathering systems; and

•                  acquiring existing gathering systems.

We currently have no agreements for the design of new systems or the acquisition of existing systems. In general, our acquisition and building criteria focus on the age of the wells serviced or to be serviced by a system and the likelihood of the producers’ continued development of their fields.

Our executive offices are located at 1401 17th Street, Suite 650, Denver, Colorado 80202 and our telephone number is
(303) 308-1330. Our website address is www.prbtrans.com and is currently under construction. Information contained on our website does not constitute a part of this prospectus. We were incorporated in Nevada on December 31, 2003.

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The Offering

(1)          Preferred stockholders may elect to convert their shares into 4,361,000 shares of common stock, the resale of 3,950,000 shares of which is being registered by a separate prospectus concurrently with this offering. Holders of 3,950,000 shares of our preferred stock have advised us that they intend to convert their preferred stock to common stock upon the effectiveness of the registration statement of which the aforementioned prospectus is a part. All of the common stock underlying our convertible preferred stock is subject to a lockup agreement with our underwriter. See “Underwriting.”

(2)          Amount gives effect to the assumed conversion of 3,950,000 shares of preferred stock to common stock on a one-to-one basis and excludes:

•                              411,000 shares of common stock issuable upon conversion of Series C preferred stock;

•                              220,000 shares of common stock issuable upon exercise of stock options;

•                              45,000 shares of common stock issuable upon exercise of warrants, the resale of which is being registered by a separate prospectus concurrently with this offering;

•                              300,000 shares of common stock issuable on exercise of the underwriter’s overallotment option; and

•                              200,000 shares of common stock issuable upon exercise of the underwriter’s warrants.

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Summary historical and pro forma financial data

The tables below present selected historical financial data of TOP Gathering, LLC, our predecessor, and our restated historical financial data and pro forma financial data with respect to the TOP and Bear Paw acquisitions, the latter restated for the year ended December 31, 2004, in each case for the periods and as of the dates indicated. We determined during June 2005 that we invoiced a customer (in respect to the Bear Paw acquisition) incorrectly for the period August 2004 through April 2005. We invoiced the customer the difference between the original invoices and the corrected invoices, approximately $304 thousand, in June 2005.  We collected the amount due from this customer during December 2005. As the Company was not previously able to determine if the $304 thousand that was invoiced to the customer during June 2005 was going to be paid or was collectible, the Company had not previously recognized the $304 thousand as revenue. As a result, we have restated our historical financial statements for the year ended December 31, 2004 to include the revenues related to the year then ended of $162,450.

We have derived the summary historical financial data for the period from inception through December 31, 2001 and the years ended December 31, 2002 and 2003 from the predecessor audited financial statements of TOP that are included in this prospectus.

We have derived the summary historical financial data for the year ended December 31, 2004 from our restated audited financial statements that are included in this prospectus and include the operating results of the assets acquired from TOP from the January 1, 2004 acquisition date, and the restated operating results of the assets acquired from Bear Paw from the August 1, 2004 acquisition date. For additional information on this matter See Note 2 - Restatement of Results, on page F-11 of the Company financial statements included herein.

We have derived the restated pro forma statement of operations data and other financial data from the restated pro forma financial statements that are included in this prospectus. They are presented for the year ended December 31, 2004 and give effect to the Bear Paw acquisition as if it occurred as of January 1, 2004 including the effect of recording the  invoice corrections noted above in the appropriate period in respect to the period January 1, 2004 through July 31, 2004. For additional information on this matter see Note 2 - Restatement of Results, on page F-45 of the restated pro forma financial statements included herein.

In the tables below we present restated earnings before interest, taxes, depreciation and amortization, or EBITDA. EBITDA is a financial measure which we use in our business but that is not calculated and presented in accordance with generally accepted accounting principles, or GAAP. See discussion regarding “Non-GAAP Financial Measure” to “Selected Historical and Pro Forma Financial Data” for a definition of EBITDA and a reconciliation of EBITDA to our income and cash flows from operating activities.

The following tables should be read together with, and are qualified in their entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The tables should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Summary historical and pro forma financial data

Statement of operations data

(1)          Excludes all shares of common stock issuable upon conversion of our preferred stock to common stock.

(2)          For a definition of EBITDA and a reconciliation of EBITDA to our income (loss) and cash flows from operating activities, see “Selected Historical and Pro Forma Financial Data - Non-GAAP Financial Measure.”

(3)   In June 2005 we determined that we incorrectly invoiced a customer for the period August 2004 to April 2005. The contract with this customer was acquired as part of our acquisition of the Bear Paw gas gathering system in August 2004. In June 2005, we invoiced the customer for the difference between the original invoices and the corrected invoices. The customer paid the difference due in December 2005 of approximately $304 thousand. As the Company was not previously able to determine if the $304 thousand that was invoiced to the customer during June 2005 was going to be paid or was collectible, the Company had not previously recognized the $304 thousand as revenue. We have restated our financial statements for the year ended December 31, 2004 to include the additional revenue for the year ending December 31, 2004 (approximately $162 thousand) that was collected in December 2005.

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Balance sheet data

The following table summarizes our audited balance sheet as of December 31, 2004 on an:

•                  actual basis; and

•                  as adjusted basis to reflect net proceeds of $9,340,000 from the sale of 2,000,000 shares of common stock offered by us at $5.50 per share in connection with this offering, after deducting the estimated underwriting discounts and commissions and offering expenses payable by us, and the retirement of the $1,500,000 bank line of credit.

(1)           See note (3) under “Statement of Operations Data.”

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Risk Factors

An investment in our common stock involves significant risks. You should carefully consider the following information about these risks, together with the other information contained in this prospectus, before investing in our common stock. If any of the risks described below develop into actual events, our results of operations and financial condition could be adversely affected which could then result in a decline in the market price of our common stock, causing you to lose all or part of your investment.

Risks related to our company and the natural gas industry

We incurred a net loss of $650,538 for the year ended December 31, 2004. Our future performance is difficult to evaluate because we have a limited operating history.

Our operations commenced with our acquisition of certain assets of TOP Gathering, LLC as of January 1, 2004 and expanded with our acquisition of certain assets of Bear Paw Energy, LLC effective August 1, 2004. As a result, we have little historical financial and operating information available to help you evaluate our performance or an investment in our common stock.

To fund our future growth we will require additional capital, which may not be available or may only be available on unfavorable terms.

Our future capital requirements depend on many factors, including development and acquisition opportunities, the availability of debt financing and the cash flow from our operations. To the extent that the funds available are insufficient to meet future capital requirements, we may need to reduce our development activity. Any equity or debt financing, if available at all, may be on terms that are not favorable to us. In the case of equity financings, dilution to our stockholders could result and such securities may have rights, preferences and privileges that are senior to those of the shares offered hereby. If we cannot obtain adequate capital on favorable terms or at all, our business, operating results and financial condition could be adversely affected.

We depend on our chief executive and chief operating officers for critical management decisions and industry contacts.

We do not have employment agreements with any of these individuals and do not carry key person insurance on their lives. The loss of the services of any of these executive officers, through incapacity or otherwise, could have a material adverse effect on our business and would require us to seek and retain other qualified personnel.

Any failure to manage our growth in operations and hire additional qualified employees could materially affect our results of operations and financial condition.

The expected growth of our operations may place a significant strain on our current management resources. To manage this expected growth, we will need to improve our:

•             transaction processing methods;

•             operations and financial systems;

•             procedures and controls; and

•             training and management of our employees.

Competition for personnel is intense, and we cannot assure stockholders that we will be able to successfully attract, integrate or retain, sufficiently qualified personnel. Our failure to attract and retain the necessary personnel or to effectively manage our employee and operations growth could materially affect our results of operations and financial condition.

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A significant decrease in the supply of natural gas from our customers could materially affect our results of operations and financial condition.

Investments by our customers in the maintenance of existing wells and the further development of their reserves will affect their production rates and the volume of gas we gather. Drilling activity generally decreases as gas prices decrease. We have no control over our customers’ level of drilling activity, the amount of reserves underlying their wells and the rate at which their production from a well will decline. Drilling activity of our customers is affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital.

Any material nonpayment or nonperformance by our key customers could materially affect our results of operations and financial condition.

As of December 31, 2004 we have 13 customers, three of which represent approximately 85% of our revenues. Pennaco Energy, Inc. accounts for approximately 33% of our revenues, e2 Business Systems, Inc. accounts for approximately 34% of our revenues and United Energy Trading, LLC accounts for approximately 18% of our revenues. No other customers exceed 5% of our revenues. Some of our customers may be highly leveraged and subject to their own operating and regulatory risks. If any of these key customers default on their obligations to us, our financial results would be adversely affected.

Federal, state and local laws and regulations relating to environmental protection and operational safety could require us or our customers to make substantial expenditures and could result in material delays in building new or expanding existing gathering systems.

Our gathering systems are subject to environmental and safety laws and regulations. The U.S. Bureau of Land Management, or BLM, completed a multi-year review of potential environmental impacts from coal-bed methane development on federal lands in the Powder River Basin in Montana and Wyoming. It issued a report in April 2003 supporting increased coal bed methane development. In May 2003 environmental and other groups filed four lawsuits in the U.S. District Court for the District of Montana against the BLM alleging that its environmental impact review was not adequate. Plaintiffs seek a court order enjoining coal-bed methane development on federal lands in the Powder River Basin until the BLM conducts additional studies on the environmental impact. As the lawsuits to delay energy development in the Powder River Basin progress through the courts, the BLM continues to process permits to drill. We are uncertain as to the outcome of this litigation and if the development of methane gas in the Powder River Basin by our customers is halted or significantly impaired, it could materially and adversely affect our results of operations and financial condition.

Our operations are subject to operational hazards and unforeseen interruptions for which we may be inadequately insured or not insured.

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury or extensive property damage, as well as an interruption in our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our results of operations and financial condition.

Growing our business by constructing new gathering systems, or expanding existing ones, subjects us to construction risks.

We plan to grow our business by constructing new gathering systems and by expanding existing ones. We have no material commitments for new construction or expansion projects as of the date of this prospectus. The construction of a new gathering system or the expansion of an existing gathering system, by adding  compressor stations or by adding a second gathering line along an existing gathering line, involves numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. These projects may not be

7

completed on schedule or at all or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new gathering system, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. This could adversely affect our results of operations and financial condition.

Restrictions in credit agreements may prevent us from engaging in some beneficial transactions.

Our $1,750,000 line of credit with the Bank of Oklahoma requires that we not incur additional direct or contingent obligations in excess of $500,000 or sell any assets in excess of $100,000 without the bank’s consent. As we make acquisitions or construct or expand gathering systems, we intend to enter into additional credit agreements with financial institutions to fund a portion of the capital requirements. To obtain funds under credit agreements we may be required to accept additional operating restrictions which would impair or prevent us from future transactions we deem to be beneficial for our future growth.

If we are unable to complete this offering by the March 31, 2005 maturity date of our bank line of credit, we will be in default of this agreement unless we are able to extend the maturity date or identify an alternative source of financing.

Our $1,750,000 bank line of credit is secured by all of our gathering assets and matures the earlier of March 31, 2005 or within three days following the funding of the initial public offering. We have received a commitment from the pledgor of $1,000,000 in collateral for the bank line of credit to maintain the collateral until the initial public offering is complete or the due date of the note payable. To the extent we are unable to retire this indebtedness by the extended maturity date, or are unable to identify an alternative source of financing, we will be in default under the loan agreement and our gathering assets may be subject to foreclosure.

Risks related to our common stock and the offering

No public market for our common stock exists and you cannot be certain that an active trading market will develop or that our common stock will trade above the offering price.

Currently no public trading market exists for our common stock. An active trading market may not develop or continue upon completion of this offering. The market price of our common stock may decline below the initial public offering price and you may incur a loss on your investment in our common stock.

Our Series A and Series B preferred stockholders as a class have the right to elect three of our five directors; therefore any of our preferred stockholders that do not convert their shares into common stock will be able to control all business decisions.

In the event that any of our Series A or Series B preferred stockholders do not convert their shares into common stock, they will retain the right as a class to elect no less than 60% of the members of our board of directors and will therefore be able to continue to control all business decisions.

In the event any of our Series A or Series B preferred stockholders do not convert their preferred stock into shares of common stock, we will remain obligated to pay dividends on those shares. The dividend rate payable on our Series A preferred stock after this offering closes will be reduced from 10% to 5%, and the dividend rate payable on our Series B preferred stock after this offering closes will be reduced from 5% to 2.5%. The resulting annual dividend of $366,250 if no preferred shares are converted would represent a significant financial commitment that could adversely affect our results of operations and financial condition.

8

We may be required the rescind the sale of up to $1,233,000 of stock if our private placement of Series C preferred stock is deemed to have violated federal and state securities laws.

In December 2004 we received $1,233,000 from the sale of 411,000 shares of Series C convertible preferred stock. We paid no cash or other commissions or finders’ fees in connection with this offering. This placement might not have been eligible for an exemption from registration under the Securities Act of 1933. In the absence of such an exemption, investors could bring suit against us to rescind their stock purchases, in which event we could be liable for rescission payments to these investors of up to $1,233,000, exclusive of interest and costs.

Issuance of additional preferred stock could discourage a change in control, reduce the market price of our common stock and result in the holders of preferred stock being granted voting rights that are superior to those of the holders of common stock.

We are authorized to issue preferred stock without obtaining the consent or approval of our stockholders. The issuance of preferred stock could have the effect of delaying, deferring, or preventing a change in control. Management also has the right to grant superior voting rights to the holders of preferred stock. Any issuance of preferred stock could materially and adversely affect the market price of the common stock and the voting rights of the holders of common stock. The issuance of preferred stock may also result in the loss of the voting control of holders of common stock to the holders of preferred stock.

Concentration of share ownership among our existing executive officers, directors and principal stockholders may prevent others from influencing significant corporate decisions.

Upon completion of this offering, and assuming the conversion of all outstanding shares of preferred stock into common stock, our executive officers, directors and principal stockholders will beneficially own approximately 16.1% of our outstanding common stock. As a result, these stockholders, acting together, will have the ability to exert substantial influence over all matters requiring approval by our stockholders, including the election and removal of directors and any proposed merger, consolidation or sale of all or substantially all of our assets and other corporate transactions. This concentration of ownership could be disadvantageous to other stockholders with interests different from those of our officers, directors and principal stockholders.

Shares eligible for public sale after this offering could cause our stock price to decline.

Our officers and directors who beneficially own 1,153,500 shares of common stock, including 70,000 shares issuable upon exercise of stock options, have agreed with our underwriter not to sell their shares of common stock for 15 months from the closing of this offering without the written consent of our underwriter. Following the expiration of the lockup agreement with our underwriter, shares of our common stock held beneficially by our officers and directors will remain subject to holding period restrictions on sale or other transfer under Rule 144 of the Securities Act. We have registered the resale of 112,000 of these shares by a separate prospectus and expect to register the remaining 241,500 shares following the completion of this offering.

All other stockholders who beneficially own 4,077,500 shares of our common stock have agreed with our underwriter not to sell their common stock for six months from the closing of this offering. If the average closing price per share of our common stock exceeds $6.60 for 10 consecutive trading days during the lockup period, 3,838,000 of these shares may be sold without the consent of our underwriter. If the average closing price per share of our common stock exceeds $8.00 for 15 consecutive trading days during the lockup period, an additional 239,500 of these shares may be sold without the consent of our underwriter. We have registered the resale of 3,838,000 of these shares by a separate prospectus and expect to register the remaining 239,500 shares following the completion of this offering.

Following this offering, but in no event sooner than three months from the closing of this offering, we also intend to register all common stock that we may issue for options granted under our equity compensation plan so that these shares may also be freely traded.

Sales of a substantial number of the above shares of common stock after this offering could significantly depress the market price of our common stock.

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Special Note Regarding Forward-Looking Statements

This prospectus includes forward-looking statements. All statements other than statements of historical facts contained in this prospectus, including statements regarding our future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. The words “believe,” “may,” “estimate,” “continue,” “anticipate,” “intend,” “should,” “plan,” “expect” and similar expressions, as they relate to us, are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs. These forward-looking statements are subject to a number of risks, uncertainties and assumptions described in “Risk Factors” and elsewhere in this prospectus.

Other sections of this prospectus may include additional factors which could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and it is not possible for our management to predict all risk factors, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

We undertake no obligation to update publicly or revise any forward-looking statements. You should not rely upon forward-looking statements as predictions of future events or performance. We cannot assure you that the events and circumstances reflected in the forward-looking statements will be achieved or occur. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements.

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Use of Proceeds

We estimate that our net proceeds from the offering will be approximately $9,340,000, after deducting underwriting discounts and commissions of $880,000, our underwriter’s $330,000 non-accountable expense allowance and our estimated offering expenses of $450,000. We will receive additional net proceeds of up to $1,518,000, after deducting $132,000 in underwriting discounts and commissions, if our underwriter exercises its overallotment option to purchase up to 300,000 additional shares.

We intend to use the net proceeds of the offering and any proceeds from the exercise of our underwriter’s overallotment option to retire $1,500,000 payable under a bank line of credit arising from our acquisition of Bear Paw. The line of credit interest rate fluctuates with the JPMorgan Chase Bank prime rate and matures on March 31, 2005. The annual interest rate was 5.25% at December 31, 2004.

We expect to use the remaining proceeds for expansion of existing gathering systems, construction of new gathering systems, acquisitions, and working capital and general corporate purposes. We currently have no commitments or specific plans for expansion of existing gathering systems, constructing new gathering systems or making any new acquisition at this time, and have no current means of estimating or allocating the actual applications of the remaining proceeds. Pending our application of net proceeds as we have described, we will invest net proceeds in short term, investment grade interest bearing securities.

Dividend Policy

We have never declared or paid cash dividends on our common stock. We currently intend to retain future earnings to finance the operation, development and expansion of our business. We do not anticipate paying cash dividends on our common stock in the foreseeable future. Payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend on our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant.

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Capitalization

The following table sets forth our capitalization as of December 31, 2004. Our capitalization is presented on an:

•                  actual basis; and

•                  as adjusted basis to reflect the conversion of 3,950,000 shares of our preferred stock into common stock, the sale of 2,000,000 shares of common stock offered by us at $5.50 per share, after deducting the estimated underwriting discounts and commissions and offering expenses payable by us, and the retirement of the $1,500,000 bank line of credit.

You should read this table together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the audited and pro forma financial statements and notes thereto and other information appearing elsewhere in this prospectus. The information included herein as of December 31, 2004 has been restated as disclosed in Note 2 to the audited PRB Gas Transportation, Inc. financial statements included in this prospectus.

The information provided above excludes:

•                  220,000 shares of common stock issuable upon exercise of outstanding stock options;

•                  45,000 shares of common stock issuable upon exercise of warrants the resale of which is being registered by a separate prospectus concurrently with this offering;

•                  300,000 shares of common stock issuable on exercise of the underwriter’s overallotment option; and

•                  200,000 shares of common stock issuable upon exercise of the underwriter’s warrants.

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Dilution

Our restated pro forma net tangible book value as of December 31,2004 was $6,998,989, or $1.39 per share of common stock and common stock equivalent. Our pro forma net tangible book value per share represents our total tangible assets at December 31, 2004, less net gathering contracts of $2,145,240 which represent intangible assets, and less total liabilities, divided by the pro forma total number of shares of common stock outstanding at such date. The pro forma total number of shares of common stock outstanding assumes the conversion of all outstanding shares of preferred stock into shares of common stock. The dilution in pro forma net tangible book value per share represents the difference between the amount per share paid by purchasers of shares of our common stock in this offering and the net tangible book value per share of our common stock immediately following this offering.

After giving effect to the sale of the shares of common stock offered by us at $5.50 per share and after deducting the estimated underwriting discounts and commissions and offering expenses payable by us, our pro forma net tangible book value, as adjusted, as of December 31, 2004 would have been approximately $16,501,439 or  $2.30 per share of common stock. This amount represents an immediate increase in pro forma net tangible book value of $0.92 per share to the existing stockholders and an immediate dilution in pro forma net tangible book value of $3.19 per share to new investors purchasing shares in this offering.

The following table illustrates the dilution in pro forma net tangible book value per share to new investors.

The following table summarizes as of December 31, 2004, the number of shares of common stock purchased from us, the total consideration paid to us, and the average price per share paid by existing stockholders and new investors purchasing shares of common stock in this offering, before deducting underwriting discounts and estimated offering expenses:

The information for existing stockholders in the table above:

•                  assumes the conversion of all 4,361,000 shares of preferred stock into 4,361,000 shares of common stock; and

•                  excludes shares issuable upon exercise of outstanding stock options or warrants and exercise of the underwriter’s overallotment option.

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Selected Historical and Pro Forma Financial Data

The tables below present selected historical financial data of TOP Gathering, LLC, our predecessor, and our historical financial data and pro forma financial data with respect to the TOP and Bear Paw acquisitions, the latter restated for the year ended December 31, 2004,  in each case for the periods and as of the dates indicated. We determined during June 2005 that we invoiced a customer (in respect to the Bear Paw acquisition) incorrectly for the period August 2004 through April 2005. We invoiced the customer the difference between the original invoices and the corrected invoices, approximately $304 thousand, in June 2005.  We collected the amount due from this customer during December 2005. As the Company was not previously able to determine if the $304 thousand that was invoiced to the customer during June 2005 was going to be paid or was collectible, the Company had not previously recognized the $304 thousand as revenue. As a result, we have restated our historical financial statements for the year ended December 31, 2004 to include the revenues related to the year then ended of $162,450.

We have derived the summary historical financial data for the period from inception through December 31, 2001 and the years ended December 31, 2002 and 2003 from the predecessor audited financial statements of TOP that are included in this prospectus.

We have derived the summary historical financial data for the year ended December 31, 2004 from our audited restated financial statements that are included in this prospectus and include the operating results of the assets acquired from TOP from the January 1, 2004 acquisition date, and the operating results of the assets acquired from Bear Paw from the August 1, 2004 acquisition date. For additional information on this matter See Note 2 - Restatement of Results, on page F-11 of the Company financial statements included herein.

We have derived the restated pro forma statement of operations data and other financial data from the restated pro forma financial statements that are included in this prospectus. They are presented for the year ended December 31, 2004 and give effect to the Bear Paw acquisition as if it occurred as of January 1, 2004 including the effect of recording the  invoice corrections noted above in the appropriate period in respect to the period January 1, 2004 through July 31, 2004. For additional information on this matter see Note 2 - Restatement of Results, on page F-45 of the restated pro forma financial statements included herein.

In the tables below we present earnings before interest, taxes, depreciation and amortization, or EBITDA. EBITDA is a financial measure which we use in our business but that is not calculated and presented in accordance with generally accepted accounting principles, or GAAP. See disclosure regarding “Non-GAAP Financial Measure” to “Selected Historical and Pro Forma Financial Data” for a definition of EBITDA and a reconciliation of EBITDA to our income and cash flows from operating activities.

The following tables should be read together with, and are qualified in their entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The tables should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Selected Historical and Pro Forma Financial Data

Statement of operations data

(1)          Excludes all shares of common stock issuable upon conversion of our preferred stock to common stock.

(2)          For a definition of EBITDA and a reconciliation of EBITDA to our income (loss) and cash flows from operating activities, see “Selected Historical and Pro Forma Financial Data - Non-GAAP Financial Measure.”

(3)   In June 2005 we determined that we incorrectly invoiced a customer for the period August 2004 to April 2005. The contract with this customer was acquired as part of our acquisition of the Bear Paw gas gathering system in August 2004. In June 2005, we invoiced the customer for the difference between the original invoices and the corrected invoices. The customer paid the difference due in December 2005 of approximately $304 thousand. As the Company was not previously able to determine if the $304 thousand that was invoiced to the customer during June 2005 was going to be paid or was collectible, the Company had not previously recognized the $304 thousand as revenue. We have restated our financial statements for the year ended December 31, 2004 to include the additional revenue for the year ending December 31, 2004 (approximately $162 thousand) that was collected in December 2005.

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Balance sheet data

The following table summarizes our audited balance sheet as of December 31, 2004 on an:

•                  actual basis; and

•                  as adjusted basis to reflect net proceeds of $9,340,000 from the sale of 2,000,000 shares of common stock offered by us at $5.50 per share in connection with this offering, after deducting the estimated underwriting discounts and commissions and offering expenses payable by us, and the retirement of the $1,500,000 bank line of credit.

(1)           See note (3) under “Statement of Operations Data.”

Non-GAAP financial measure

EBITDA is a supplemental financial measure used by our management to conduct and evaluate our business. We define EBITDA as earnings before interest expense, income taxes, depreciation and amortization. This definition may not be comparable to similarly titled measures reported by other companies. We are presenting EBITDA because it provides an additional way to view our operations, when considered with both our GAAP results and the reconciliation to net income (loss), which we believe provides a more complete understanding of our business than could be obtained absent this disclosure. EBITDA is presented solely as a supplemental disclosure because we:

•                  believe it is a useful tool for investors to assess the operating performance of our business without the effect of non-cash depreciation and amortization expenses;

•                  believe that investors will find it useful in assessing our ability to service existing or incur additional indebtedness; and

•                  use EBITDA internally to evaluate the performance of our personnel and also as a benchmark to evaluate our operating performance or compare our performance to that of our competitors. The use of EBITDA has limitations and you should not consider EBITDA in isolation from or as an alternative to GAAP measures such as net income and cash flows.

Our operations are capital intensive, and depreciation and amortization are unavoidable, material costs of doing business. By eliminating these measures, EBITDA has material limitations as a measure of our performance.

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The following table presents a reconciliation of EBITDA to the most directly comparable GAAP financial measures on a historical basis for each of the periods indicated.

Reconciliation of EBITDA to net income (loss)

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of the financial condition and results of operations in conjunction with the financial statements of TOP, Bear Paw and our historical and pro forma financial statements included elsewhere in this prospectus. Among other things these historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information. The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of various factors, including those discussed in “Risk Factors” and elsewhere in this prospectus.

Overview

We own and operate intrastate natural gas gathering systems. We commenced operations in January 2004 upon our acquisition of certain operating assets of TOP Gathering, LLC. We operate in the less regulated intrastate gas gathering environment and currently plan to limit our expansion to intrastate operations. We charge a fee for gathering, compressing and dehydrating natural gas. Our gathering systems collect gas at a producer’s wellhead or at a collection point and deliver it to a transmission line owned by a third party. We do not take ownership of gas that we gather.

Natural gas wells in the Powder River Basin area typically experience sharp declines in production volume in the first several years of production. Production then stabilizes and declines more ratably over a gas well’s average life of approximately eight to 10 years. The majority of the wells serviced by our TOP and Bear Paw gathering systems have reached a stable decline phase of production. We believe that undeveloped reserves in the fields serviced by these systems may provide additional production that could offset future declines and possibly exceed current gas production.

We plan to expand our present operations through a combination of:

•                  enhancing the present gathering systems through operating efficiencies and expanding to service additional wells and fields;

•                  designing and building new gathering systems; and

•                  acquiring existing gathering systems.

We currently have no agreements for the design of new systems or the acquisition of existing systems. In general, our acquisition and building criteria focus on the age of the wells serviced or to be serviced by a system and the likelihood of the producers’ continued development of their fields.

Financial operations overview

Our systems gather natural gas for independent natural gas companies in the Powder River Basin area of Wyoming. Our commercial operations commenced in January 2004 with the TOP acquisition. We expanded our commercial operations in August 2004 with the Bear Paw acquisition.

The analysis of the results of operations for the three years ended December 31, 2003 reflects the pre-acquisition operations of TOP and Bear Paw. We have included a separate analysis of the results of operations for the gas gathering systems we acquired from Bear Paw for the three years ended December 31, 2003 and for the unaudited seven months ended July 31, 2005 which precede our August 1, 2004 acquisition date. The analysis of the results of operations for the year ended December 31, 2004 reflects our operations and include the results of the acquired TOP operations from January 1, 2004 and the results of the Bear Paw operations from August 1, 2004.

While we do not discuss our pro forma financial statements below, these statements, and the assumptions made therein, are presented in the unaudited pro forma financial statements included elsewhere in this prospectus. You should review our pro forma financial statements more fully to understand our results of operations.

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In June 2005 we determined that we incorrectly invoiced a customer for the period August 2004 to April 2005. The contract with this customer was acquired as part of our acquisition of the Bear Paw gas gathering system in August 2004. In June 2005 we invoiced the customer for the difference between the original invoices and the corrected invoices, The customer paid the difference due in December 2005, approximately $304 thousand. As the Company was not previously able to determine if the $304 thousand that was invoiced to the customer during June 2005 was going to be paid or was collectible, the Company had not previously recognized the $304 thousand as revenue. We have restated our financial statements for the year ended December 31, 2004 to include the additional revenue for the year ending December 31, 2004 (approximately $162 thousand) that was collected in December 2005. We also determined that Bear Paw (the previous owner) also had incorrectly invoiced this customer similarly. Accordingly, we have also restated the pro forma financial statements included herein to include the difference between what Bear Paw invoiced the customer and what could have been invoiced under the contract of approximately $115 thousand for the seven months ended July 31, 2004, through a pro forma adjustment.

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Nature of revenue  The amount of revenue we generate will primarily depend on the level of the fees we charge for gathering and the amount of throughput in our pipelines. Gathering fees are determined by negotiation with the producers or shippers involved. Our fees are not regulated by any governmental authority. We do not take ownership of the gas that we gather.

As of December 31 we have 13 customers, three of which represent approximately 85% of our revenues. Pennaco Energy, Inc. accounts for approximately 33% of our revenues, e2 Business Systems, Inc. accounts for approximately 34% of our revenues and United Energy Trading, LLC accounts for approximately 18% of our revenues. No other customers exceed 5% of our revenues. Some of our customers may be highly leveraged and subject to their own operating and regulatory risks. If any of these key customers default on their obligations to us, our financial results would be adversely affected.

We have two types of gathering contracts. Six of our contracts are currently on a volume only basis where we charge a set fee per thousand cubic feet, or Mcf, of gas gathered. The rates for these contracts vary from approximately $0.37 per Mcf to $0.70 per Mcf, with those below $0.53 per Mcf accounting for less than 4.6% of our revenues for the three months ended December 31, 2004. The balance of our gathering contracts are a combination of a $0.12 per Mcf fee based on volume and an additional fee for each compressor used on the system. These compression fees are allocated to each producer on the system based on its individual usage volumes and the total usage volumes of gas passing through the system. In December 2004 the gathering fees under this type of contract ranged from approximately $0.73 per Mcf to $0.84 per Mcf. These fees will vary monthly depending on the producers’ individual production and the system’s total throughput.

Two of our contracts have thresholds which provide for a reduction in rates. We assumed a gas gathering contract that commenced in October 2001 to gather and deliver gas for a related party for $0.89 per Mcf until such time as we received a total of 4.5 billion cubic feet, or Bcf, of gas from the shipper. Thereafter, the transportation fee will be reduced $0.05 for every 5 Bcf of gas received. The first threshold was reached in June 2004 and accordingly the rate was reduced to $0.84 per Mcf effective July 1, 2004. We estimate that the next threshold will not be reached for at least 10 years. The contract remains in effect as long as our gathering facility remains profitable. In the event the contract is unprofitable for us, we may terminate the contract with 30 days written notice. Revenues generated under this contract during the year ended December 31, 2004 were $560,138.

In addition, we assumed a 10-year gas gathering contract commencing in September 2002 to gather and deliver gas for an unrelated third party for $0.58 per Mcf until such time as the shipper has delivered 2 Bcf. Thereafter, the gathering fee will be reduced to $0.52 per Mcf. We estimate that this threshold will be reached in mid-2005. After the initial term, either party may terminate the contract with 30 days written notice. Revenues generated under this contract during the year ended December 31, 2004 were $415,218.

Gas gathering throughput in our systems is directly affected by the decline rate of the producers’ natural gas reserves. The effect of this decline rate can be offset by extension of the gathering system to additional fields and our customers’ further development of their fields. If a decline in demand for natural gas leads to reduced maintenance and development by our customers, it may adversely affect their production and our throughput. The throughput in our systems is not materially affected by seasonality.

Operating expense  Operating expenses include compression, site supervision costs, maintenance and operating supplies, property taxes, insurance, land use and surface rights payments and contract services, all of which are relatively fixed costs. Operating expenses also include transportation fees paid to others which vary with the throughput on our gathering lines.

Depreciation and amortization expense  Depreciation and amortization expense relates principally to the depreciation of the gathering systems and related contracts. These assets are depreciated or amortized over estimated useful lives.

General and administrative expense  General and administrative expense includes compensation expense, professional fees and corporate overhead. We have substantially increased salaried positions and overhead to prepare for the planned expansion of operations. We expect that initially these costs as a percentage of revenue will

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be higher than desired due to our only recently commencing operations, but as revenue increases we expect these costs to fall within industry ranges.

Interest expense   Interest expense for historical TOP (predecessor) operations relates to a $300,000 note with interest at 7% per annum which we did not acquire when we purchased the gathering system and related assets.

At September 30, 2004 we had a $1,944,480, 8% note payable to Bear Paw which we repaid in full in December 2004. In addition, we entered into a $800,000 short-term note payable on October 1, 2004 with interest at 12% per annum. This note was repaid in full in December 2004. In conjunction with the repayment of these notes, we entered into a $1,750,000 bank line of credit in December 2004 and borrowed $1,500,000 thereunder with fluctuating interest at the JPMorgan Chase Bank prime rate per annum. The annual interest rate was 5.25% at December 31, 2004. This bank line of credit matures the earlier of March 31, 2005 or within three days following the funding of the initial public offering and is secured by all of our gathering assets and a pledge of a $1,000,000 certificate of deposit by a preferred stockholder. In consideration for this $1,000,000 pledge, we have agreed to pay the preferred stockholder a monthly fee of 0.529% until the bank line of credit is retired and the pledge is released.

We intend to repay the bank line of credit in full from the proceeds of this offering. We have received assurance from the bank that it foresees no difficulty in extending the maturity date of the note if the initial public offering is not effective by the March 31, 2005 maturity date. We also received a commitment from the pledgor of $1,000,000 in collateral for the bank line of credit to maintain the collateral until the initial public offering is complete or the due date of the note payable.

We intend to utilize commercial financing when available to support our acquisition and development efforts although we have no such debt at this time. Interest rate risk exists principally with respect to any future indebtedness that will likely bear interest at floating rates.

Preferred dividend  In January 2004 we issued 2,400,000 shares of Series A 10% convertible preferred stock which pay a 10% annual dividend on a quarterly basis. Quarterly dividends on this series of preferred stock amount to $125,000.

In May 2004 we issued 1,550,000 shares of Series B 5% convertible preferred stock which pay a 5% annual dividend on a quarterly basis. Quarterly dividends on this series of preferred stock amount to $58,125.

In December 2004 we issued 411,000 shares of non-dividend bearing Series C convertible preferred stock at $3.00 per share which are convertible into an equal number of shares of common stock. For accounting purposes the difference between the share price of $3.00 and $5.50, the offering price per share in this offering, is deemed to be compensation to our executive officers and other interested parties, and a deemed dividend to other investors. We have recorded deemed compensation expense of $440,750 and a deemed dividend of $586,750 in connection with the issuance of the Series C preferred stock.

Holders of all our outstanding preferred stock have advised us that they intend to convert their preferred stock to common stock upon the effectiveness of the registration statement of which this prospectus is a part.

Income tax expense Our predecessor, TOP Gathering, LLC, was organized as a limited liability corporation and was not subject to tax at the company level. We are subject to federal and state taxation at the corporate level.

Critical accounting policies

Our discussion and analysis of our financial condition and results of operations and those for TOP and Bear Paw are based upon financial statements which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

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Revenue recognition

We recognize revenue in the period that the gas gathering and transportation services are provided. Our gas gathering and transportation contracts specify the rate that can be charged on a basis of cents per thousand cubic feet or Mcf of natural gas. Each contract has a separately negotiated rate and terms may vary. Certain of our contracts include separate charges for compression in addition to a transportation fee. Our revenues will increase or decrease in proportion to gas volume delivered over our system. There are measurement points throughout each gathering system which enable the gas to be accurately measured and allocated back to either different operators or wells.

Long-lived assets

We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as competition, regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate long-lived assets for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discounted cash flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates. We recorded no impairments of long-lived assets during the year ended December 31, 2004.

Abandonment liability

We follow Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations”. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of facilities was recorded as of the effective date of the TOP acquisition. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the compressor site. Such costs are capitalized as part of the cost of the related asset and amortized. The associated liability is classified as a long-term liability and is adjusted when circumstances change and for the accretion of expense which is recorded as a component of depreciation and amortization. We have not yet recorded an asset retirement obligation in conjunction with the assets acquired from Bear Paw because sufficient information to make a reasonable estimate of the fair value of the liability is not available.

Stock-based compensation

We account for employee stock options using the intrinsic value method in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, and provide pro forma disclosures of net income (loss) as if a fair value method had been applied in measuring compensation expense. Stock compensation expense, which is a non-cash charge, is measured as the excess, if any, of the fair value of our underlying common stock at the date of grant over the amount an employee must pay to acquire such stock. This compensation cost is amortized over the related vesting periods, generally four years, using an accelerated method. See “Recent accounting pronouncements.”

We determine the fair value of our common stock by evaluating a number of factors, including our financial condition and business prospects, our stage of development and achievement of key technical and business milestones, private and public market conditions, the terms of our private financings and the valuations of similar companies in our industry.

Contingencies

In the future, we may be subject to adverse proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We will be required to assess the likelihood of any adverse judgments or outcomes of these matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual issue. The required reserves may

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change in the future due to developments in each matter or changes in approach such as a change in settlement strategy in dealing with these potential matters.

Results of operations

The results of operations for PRB for the year ended December 31, 2004 and for TOP, its predecessor, for the period from inception through December 31, 2001, the years ended December 31, 2002 and 2003 are discussed together below. The results of operations for the Bear Paw operations for the three years ended December 31, 2003, and the unaudited seven month period ended July 31, 2004 preceding our August 1, 2004 acquisition date, are discussed separately below.

PRB and TOP (predecessor) operations

Year ended December 31, 2004 (PRB) compared to year ended December 31, 2003 (TOP predecessor operations)

The results of operations for the year ended December 31, 2003 are derived from the audited financial statements of TOP and the results of operations for the year ended December 31, 2004 are derived from our audited restated financial statements.

Revenues  Gas gathering revenues were $2,531,686 for the year ended December 31, 2004 compared with $1,998,960 for the year ended December 31, 2003, an increase of $532,726, or 27%. Revenues from the Bear Paw systems of $1,310,926 are included effective August 1, 2004 and offset the decrease of $778,200, or 39% experienced for the TOP systems. The TOP decrease was primarily attributable to lower natural gas volumes processed through the gathering system by existing producers. An additional producer began delivering gas to the system at the end of 2003 which offset some of the decline in 2004.

The decline rate for the TOP system is consistent and predictable for the age and nature of the wells and meets what we consider to be a stable decline rate. The decline rate for the Bear Paw systems involves two separate gathering systems: the Gap and Bonepile systems. The decline rate for the Gap system is consistent and predictable for the age and nature of the wells and meets what we consider to be a stable decline rate. The decline rate for the Bonepile system which accounts for approximately 10% of our total revenue has not yet reached a stable decline rate and continues to decline at an annual rate of approximately 60%. We are unable to predict when production volume for the Bonepile system will stabilize.

Operating expenses  Operating expenses totaled $1,314,392 for the year ended December 31, 2004 compared with $1,221,983 for the year ended December 31, 2003, an increase of $92,409, or 8%. Included in operating expenses for the year ended December 31, 2004 are five months of Bear Paw operating expenses which total $493,378. The decrease for this period excluding the Bear Paw expenses is $400,969, or 33%. Approximately $366,700 of this decrease is attributable to a reduction in the number of compressors leased and approximately $124,750 is due to a decrease in gas transportation fees paid based on the lower gas volumes. We reduced the number of compressors utilized due to the lower natural gas volumes being produced. Offsetting this decrease was an increase of approximately $90,500 due to the reclassification of repairs and maintenance, water hauling, site supervision, property insurance, property tax and other expenses previously classified as general and administrative expense by TOP to operating expense classification for PRB financial statements.

Depreciation and amortization Depreciation and amortization totaled $655,763 for the year ended December 31, 2004 compared with $521,945 for the year ended December 31, 2003, an increase of $133,818, or 26%. Included in depreciation and amortization expenses for the year ended December 31, 2004 are five months of Bear Paw depreciation and amortization expenses which total $318,606. The actual decrease for this period excluding the Bear Paw expenses is $184,788, or 35%. This decrease relates primarily to the differences in the estimated useful lives and depreciable bases of the assets under the different owners.

General and administrative expenses  General and administrative expenses totaled $1,183,831 for the year ended December 31, 2004 compared with $155,554 for the year ended December 31, 2003, an increase of

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$1,028,277, or 661%. The increase was primarily due to the hiring of professional management and staff that were not required for the predecessor TOP operations. Approximately $439,300 of the increase is attributable to payroll and related expense, $440,750 was deemed compensation expense resulting from the purchase of 176,300 Series C shares by officers and other interested parties, and approximately $122,000 is attributable to professional and consulting fees.

TOP predecessor operations - Year ended December 31, 2003 compared to year ended December 31, 2002

Revenue  TOP revenues were $1,998,960 for the year ended December 31, 2003 compared with $2,097,262 for the year ended December 31, 2002, a decrease of $98,302, or 5%. The decrease was the result of a combination of factors. One of the producers serviced by TOP had a decline in throughput of 39%. This decrease was offset by an increase in another producer’s volumes as well as the addition of a new producer but these higher volumes had a lower contracted gathering rate.

Operating expenses Operating expenses totaled $1,221,983 for the year ended December 31, 2003 compared with $1,536,914 for the year ended December 31, 2002, a decrease of $314,931 or 21%. The decrease was attributable to an approximately $337,500 reduction in costs associated with a terminated compressor lease which was offset by an increase in gas transportation fees of approximately $22,500 due to increased gas throughput.

Depreciation and amortization Depreciation and amortization totaled $521,945 for the year ended December 31, 2003 compared with $1,044,340 for the year ended December 31, 2002, a decrease of $522,395, or 50%. This decrease was primarily due to the write-off in 2002 of approximately $520,000 in assets associated with an anticipated reduction in compressors.

General and administrative expenses  General and administrative expenses totaled $155,554 for the year ended December 31, 2003 compared with $143,247 for the year ended December 31, 2002, an increase of $12,307 or 9%. The increase was primarily due to increased costs for accounting and legal expenses associated with an audit and preparation of sale documents.

TOP predecessor operations - Year ended December 31, 2002 compared to period from inception through December 31, 2001

Revenues  TOP revenues were $2,097,262 for the year ended December 31, 2002. As the TOP system was constructed in late 2001 and began operations in February 2002, there were no revenues in 2001. The system serviced two producers during 2002, with one producer being responsible for approximately 94% of the throughput.

Operating expenses  Operating expenses totaled $1,536,914 for the year ended December 31, 2002. Compression lease expense was approximately $1,207,000 with the balance made up of gas transportation fees. There was minimal expense of $2,269 recorded in 2001.

Depreciation and amortization  Depreciation and amortization totaled $1,044,340 for the year ended December 31, 2002. This included the write-off of some assets related to the anticipated reduction in compression of approximately $520,000.

General and administrative expenses  General and administrative expenses totaled $143,247 for the year ended December 31, 2002. This included payroll expense of approximately $63,000, insurance expense of approximately $32,000 and other corporate overhead items. There was no general and administrative expense recorded in 2001.

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Bear Paw Energy, LLC - Gap, Bone Pile, Antelope Valley and South Kitty operations

We have included a separate analysis of the results of operations for the gas gathering systems we acquired from Bear Paw for the three years ended December 31, 2003 and for the unaudited restated seven months ended July 31, 2004 which precede our August 1, 2004 acquisition date. The gas gathering systems we acquired from Bear Paw were not operated as a separate division or company. Accordingly, the financial statements included in this prospectus for these systems only include revenues of the acquired systems and related direct operating expenditures.

Period ended July 31, 2004 (unaudited) compared to period ended July 31, 2003 (unaudited)

Revenues  Subsequent to July 31, 2004, Bear Paw operations are included in PRB operations. Gas gathering revenues were $1,533,332 for the seven months ended July 31, 2004 compared with $2,433,870 for the seven months ended July 31, 2003, a net decrease of $900,538 or 37%. The Gap system generated $535,348 of this decrease which represents a 29% decrease in revenue from the same period for the preceding year. The Bonepile system generated $365,190 of this decrease which represents a 60% decrease in revenues from the same period for the preceding year. The decrease in Gap revenues was partially offset by the renegotiation of certain contracts in May 2004. Terms of the majority of the Gap gathering contracts were revised from a fixed 10 year term to life of production contracts. The majority of the Gap contracts are also now on a two tier rate system where customers are charged a fee for compressor utilization and a separate fee based on volume throughput. Compression fees are allocated based on the ratio of each producer’s volume to total system throughput volume for the month. Previously, all contracts were charged only on a volume basis at rates averaging from $0.36 to $0.58 per Mcf. The actual rate on the revised terms varies each month based on a producer’s throughput relative to total throughput. In November 2004 rates ranged from $0.70 to $0.89 per Mcf.

The decline rate for the Gap system is consistent and predictable for the age and nature of the wells and meets what we consider to be a stable decline rate. The decline rate for the Bonepile system which accounts for approximately 10% of our total revenue has not yet reached a stable decline rate and continues to decline at an annual rate of approximately 60%. We are unable to predict when production volume for the Bonepile system will stabilize.

Depreciation  Depreciation totaled $796,823 for the seven months ended July 31, 2004 compared with $1,352,033 for the seven months ended July 31, 2003, a decrease of $555,210, or 41%. This decrease was primarily due to an impairment analysis of natural gas gathering and processing assets which was performed in September

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2003 as a result of lower throughput volumes for gas gathering operations. As a result of this analysis, a charge of $42,146,970 was recorded during the third quarter of 2003 to reduce the carrying cost of these assets to their net realizable value. Beginning October 1, 2003, the estimated depreciable life of the assets was also reduced from 30 years to 15 years. The effect of the reduction in depreciable cost, as adjusted, exceeded the effect of reducing the depreciable life by 50%.

 Labor related expenses   Labor related expenses totaled $306,677 for the seven months ended July 31, 2004 compared with $354,832 for the seven months ended July 31, 2003, a decrease of $48,155, or 14%. This decrease was primarily due to reconfiguration of the systems that reduced the number of compressors and resulted in a lower allocation of labor costs.

Property taxes  Property tax expense totaled $172,662 for the seven months ended July 31, 2004 compared with $181,294 for the seven months ended July 31, 2003, a decrease of $8,632, or 5%.

Right-of-way expenses  Right-of-way expenses totaled $90,214 for the seven months ended July 31, 2004 compared with $102,252 for the seven months ended July 31, 2003, a decrease of $12,038, or 12%.

Other operating expenses  Other operating expenses totaled $598,454 for the seven months ended July 31, 2004 compared with $621,965 for the seven months ended July 31, 2003, a decrease of $23,511, or 4%.

Year ended December 31, 2003 compared to year ended December 31, 2002

Revenues  Revenues totaled $3,750,375 for the year ended December 31, 2003 as compared with $6,373,579 for the year ended December 31, 2002, a decrease of $2,623,204 or approximately 41%. The Gap system generated $1,334,392 of this decrease which represents a 32% decrease in revenue from the same period for the preceding year. The Bonepile system generated $1,288,812 of this decrease which represents a 59% decrease in revenue from the same period for the preceding year.

One Gap customer who flowed gas on the system on an as-needed basis with a rate significantly lower than the gathering rates, had a decrease of approximately 26% of the overall volume decline. Other than due to this customer the decline rate for the Gap system is consistent and predictable for the age and nature of the wells and meets what we consider to be a stable decline rate. The decline rate for the Bonepile system which accounts for approximately 10% of our total revenues has not yet reached a stable decline rate and continues to decline at an annual rate of approximately 60%. We are unable to predict when production volume for the Bonepile system will stabilize.

Depreciation/Asset impairment  Depreciation totaled $2,088,694 for the year ended December 31, 2003 compared with $2,322,046 for the year ended December 31, 2002, a decrease of $233,352, or 10%. This decrease was primarily due to the recording of impairment charges as a result of lower throughput volumes experienced and anticipated for gas gathering operations. In addition to the impairment charge of $42,146,970 during the third quarter of 2003 to reduce the carrying cost of these assets to their net realizable value, beginning October 1, 2003, the estimated depreciable life of the assets was reduced from 30 years to 15 years. The effect of the reduction in depreciable cost, as adjusted, exceeded the effect of reducing the depreciable life by 50%.

Labor related expenses   Labor related expenses totaled $661,218 for the year ended December 31, 2003 compared with $441,932 for the year ended December 31, 2002, an increase of $219,286, or 50%. This increase was primarily due to a reduction in contract labor and corresponding addition in full time personnel.

Property taxes  Property tax expense totaled $310,790 for the year ended December 31, 2003 compared with $647,592 for the year ended December 31, 2002, a decrease of $336,802, or 52%. This decrease was primarily due to renegotiating property values with the taxing authority.

Right-of-way expenses  Right-of-way expenses totaled $174,516 for the year ended December 31, 2003 compared with $182,120 for the year ended December 31, 2002, a decrease of $7,604, or 4%.

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Other operating expenses  Other operating expenses totaled $1,158,257 for the year ended December 31, 2003 compared with $1,241,671 for the year ended December 31, 2002, a decrease of $83,414, or 7%.

Year ended December 31, 2002 compared to year ended December 31, 2001

Revenues  Revenues totaled $6,373,579 for the year ended December 31, 2002 as compared with $10,858,189 for the year ended December 31, 2001, a decrease of $4,484,610 or 41%. Volumes decreased approximately 7,000,000 Mcf or 32%. The Gap system generated $3,023,275 of this decrease which represents a 42% decrease in revenue from the same period for the preceding year. The Bonepile system generated $1,461,335 of this decrease which represents a 40% decrease in revenue from the same period for the preceding year.

The decline rate for the Gap system is consistent and predictable for the age and nature of the wells and meets what we consider to be a stable decline rate. The decline rate for the Bonepile system which accounts for approximately 10% of our total revenue has not yet reached a stable decline rate and continues to decline at an annual rate of approximately 60%. We are unable to predict when production volume for the Bonepile system will stabilize.

Depreciation Depreciation totaled $2,322,046 for the year ended December 31, 2002 compared with $2,194,116 for the year ended December 31, 2001, an increase of $127,930, or 6%. The increase was principally due to capital additions during the year.

Labor related expenses   Labor related expenses totaled $441,932 for the year ended December 31, 2002 compared with $394,450 for the year ended December 31, 2001, an increase of $47,482, or 12%. This increase was primarily due to a reduction in contract labor and corresponding addition in full time personnel.

Property taxes  Property tax expense totaled $647,592 for the year ended December 31, 2002 compared with $318,031 for the year ended December 31, 2001, an increase of $329,561, or 104%. This increase was primarily due to capital additions during the year.

Right-of-way expenses  Right-of-way expenses totaled $182,120 for the year ended December 31, 2002 compared with $187,306 for the year ended December 31, 2001, a decrease of $5,186, or 3%.

Other operating expenses  Other operating expenses totaled $1,241,671 for the year ended December 31, 2002 compared with $2,227,271 for the year ended December 31, 2001, a decrease of $985,600, or 44%. This decrease was primarily due to a $460,000 reduction in tools and special equipment purchases and a $359,000 reduction in outside labor costs.

General trends and outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our expectations may vary materially from actual results.

U.S. Gas Supply and Outlook. We believe that current natural gas prices will continue to result in relatively high levels of demand for natural gas by both the residential and commercial markets. In 2003, the Bureau of Land Management forecasts that over 80,000 new wells will be drilled in the Rocky Mountain region by end of 2008. There are approximately 15,000 authorized drilling permits to be issued by the BLM in the State of Wyoming. We believe that an increase in U.S. drilling activity and additional sources of supply such as liquefied natural gas, or LNG, imports will be required for the natural gas industry to meet the expected increased demand for, and compensate for the slowing production of, natural gas in the United States.

Rising Interest Rate Environment. The credit markets recently have experienced 50-year record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten further, resulting in

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higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to pay for acquisitions. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Liquidity and capital resources

Cash flows and capital expenditures

At December 31, 2004, we had $320,150 in cash and cash equivalents. Since our inception, we have principally financed our operating cash flow needs through private offerings of our equity securities.

We believe that the proceeds from this offering will be sufficient to fund operations for at least the next 18 months. We intend to utilize debt financing for development commitments when economically feasible and available. Except as described in this prospectus, we have no plans for any future issuance of equity securities other than in conjunction with compensation plans, warrants and conversion of our preferred stock.

Our $1,750,000 bank line of credit matures the earlier of March 31, 2005 or within three days following the funding of the initial public offering. We have received assurance from the bank that it foresees no difficulty in extending the maturity date of the note if the initial public offering is not effective by March 31, 2005. We also received a commitment from the pledgor of $1,000,000 in collateral for the bank line of credit to maintain the collateral until the initial public offering is complete or the due date of the note payable. To the extent we are unable to retire this indebtedness by the extended maturity date, we will be in default under the loan agreement and our gathering assets may be subject to foreclosure.

We are currently negotiating to extend the February 27, 2005 due date of the final payment to TOP of $200,000. We have sufficient funds available on our line of credit to repay this amount before our initial public offering is completed if necessary.

Cash flow used in operations Cash provided by operating activities was $72,354 for the year ended December 31, 2004. The net loss from operating activities of $650,538 was reduced by $650,963 in depreciation and amortization, $4,800 in accretion expense and by $440,750 in deemed compensation expense which do not use cash and was increased by $373,621 due to a net increase in accounts receivable, prepaid expenses and other assets over accounts payable and other accrued liabilities.

Cash provided by operating activities was $654,587 for the year ended December 31, 2003. The net income from operating activities of $78,616 was increased by $521,945 in depreciation and amortization which do not use cash and decreased by $54,026 due to a net increase in accounts receivable, prepaid expenses and other assets over accounts payable and other accrued liabilities.

Cash flow from investing activities  Cash used in investing activities was $10,647,402 for the year ended December 31, 2004. The funds were principally used for the acquisition of the TOP and Bear Paw assets and for purchasing computer equipment. See discussion of TOP and Bear Paw acquisitions below.

Cash used in investing activities was $14,112 for the year ended December 31, 2003. The funds were used for purchasing equipment.

Cash flow from financing activities  Cash provided by financing activities was $10,895,198 for the year ended December 31, 2004. These funds represent the net proceeds from the sales of our common and preferred stock and other financing activities as follows:

•                  In January 2004 we sold 1,600,000 shares of common stock to our two founders for net proceeds of $20,000;

•                  In January 2004 we sold 2,400,000 shares of Series A 10% convertible preferred stock at $2.083 per share which are convertible into an equal number of shares of common stock. Net proceeds from this private placement were $4,987,025. We paid no commissions or finders’ fees;

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•                  In May 2004 we sold 1,550,000 shares of Series B 5% convertible preferred stock at $3.00 per share which are convertible into an equal number of shares of common stock. Net proceeds from this private placement were $4,640,579. We paid no commissions or finders’ fees;

•                  In September 2004 we acquired 800,000 shares of common stock from Kevin P. Norris for $800,000 in cash. Mr. Norris, our former director from December 2003 to May 2004, is the manager of TOP Gathering, LLC whose assets we acquired as of January 2004;

•                  In October 2004 we borrowed $800,000 from a preferred stockholder pursuant to a 12% per annum promissory note;

•                  In December 2004 we issued 411,000 shares of non-dividend bearing Series C convertible preferred stock at $3.00 per share which are convertible into an equal number of shares of common stock. Net proceeds from this private placement were $1,231,296. Our chief executive officer and his wife purchased 163,500 shares in this offering. Our president and our vice president of finance purchased 3,000 and 5,000 shares in this offering, respectively. We paid no cash or other commissions or finders’ fees in connection with this offering. For accounting purposes the difference between the share price of $3.00 and $5.50, the offering price per share in this offering, is deemed to be compensation to our executive officers and other interested parties, and a deemed dividend to other investors. We have recorded deemed compensation expense of $440,750 and a deemed dividend of $586,750 in connection with the issuance of the Series C preferred stock. This placement might not have been eligible for an exemption from registration under the Securities Act of 1933. In the absence of such an exemption, investors could bring suit against us to rescind their stock purchases, in which event we could be liable for rescission payments to these investors of up to $1,233,000, exclusive of interest and costs;

•                  In December 2004 we repaid notes payable related to the Bear Paw acquisition of $1,944,480 and an $800,000 short-term note. To retire this debt we borrowed $1,500,000 under a $1,750,000 bank line of credit bearing a fluctuating interest rate equal to the JPMorgan Chase Bank prime rate. The annual interest rate was 5.25% at December 31, 2004. This bank line of credit matures the earlier of March 31, 2005 or within three days following the funding of the initial public offering and is secured by all of our gathering assets and a pledge of a $1,000,000 certificate of deposit by a preferred stockholder. In consideration for this pledge, we have agreed to pay the preferred stockholder a monthly fee of approximately $5,300, or 0.529% of the amount of the certificate of deposit, until the bank line of credit is retired and the pledge is released. We intend to pay the bank line of credit in full from the proceeds of this offering;  and

•                  During the year ended December 31, 2004 we paid dividends of $428,750 and deferred costs related to our initial public offering of $254,952.

Cash used by financing activities was $500,000 for the year ended December 31, 2003 which represents distributions to members of the TOP Gathering, LLC.

Acquisition of certain operating assets of TOP Gathering, LLC

Effective January 1, 2004, we purchased the gas gathering assets of TOP Gathering, LLC, located in Campbell County Wyoming, for $3,184,873, including direct costs of $65,794, cash of $2,774,440, a compressor disposal liability of $144,639 and a payable to TOP of $200,000 that was due February 27, 2005. We are currently negotiating to extend this due date. We have sufficient funds available on our line of credit to repay this amount before our initial public offering is completed if necessary.

The results of operations related to these acquired assets have been included in our financial statements since January 1, 2004. The acquisition was accounted for using the purchase method of accounting. In conjunction with the asset acquisition, we have recorded the fair value of a liability for an asset retirement obligation in the amount of $60,004 and increased the value of the related assets. The purchase consideration, including legal fees and other professional fees incurred, has been allocated among the following assets based on the estimated fair value of the assets acquired:

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Acquisition of certain operating assets of Bear Paw Energy, LLC

Effective August 1, 2004, we purchased certain gas gathering assets from Bear Paw Energy, LLC, located in Campbell County Wyoming, for $7,646,581, including direct costs of $146,581. Included in the assets is approximately 200 miles of pipeline, related equipment such as buildings, launchers and receivers and other equipment,  12 gas gathering contracts and over 600 right-of-way and surface lease contracts. We did not record an asset retirement obligation relating to obligations under certain of these contracts because a reasonable estimate of the useful lives of the underlying assets cannot currently be made. The purchase and sale agreement was executed on September 30, 2004 and the closing occurred on October 6, 2004; therefore, all acquisition costs were deferred at September 30, 2004. We paid $5,500,000 in cash at closing and recorded a note payable of $1,944,480 which was the balance due of $2,000,000 reduced by adjustments of $55,520 that included August 2004 revenue net of expenses, plus prepaid rights of way and property taxes. The note was to be paid in two installments; $1,500,000 plus interest calculated at 8% per annum on December 15, 2004 and the balance plus interest on February 15, 2005. We paid the note in full on December 15, 2004.

The results of operations related to these acquired assets have been included in our financial statements since the effective date of August 1, 2004. The acquisition was accounted for using the purchase method of accounting. The purchase consideration, including legal fees and other professional fees incurred, has been allocated among the following assets based on the estimated fair value of the assets acquired:

In conjunction with this purchase, we signed an operating agreement effective August 1, 2004 with Bear Paw Energy to operate these assets. The contract has an initial term of two years with an automatic renewal for up to two terms of one year each thereafter until and unless terminated by us upon 30 days notice. The contract calls for monthly payments by us of $71,000 and for us to be responsible for any repair or replacement that is greater than $5,000 per occurrence, excluding compressor overhauls which are the responsibility of Bear Paw. We are also responsible for any overtime outside of regular business hours. All other expenses associated with ownership of the acquired assets are the responsibility of PRB including property taxes, rights of way payments and insurance.

Preferred stock dividends

Although they are under no commitment to do so, holders of all of our outstanding preferred stock have advised us that they intend to convert their preferred stock to common stock upon the closing of this offering.

In the event that any of our Series A and Series B preferred stockholders do not convert their preferred stock into shares of common stock, we will remain obligated to pay dividends on those shares. The dividend rate payable on our Series A preferred stock after this offering closes will be reduced from 10% to 5% and the dividend rate payable on our Series B preferred stock after this offering closes will be reduced from 5% to 2.5%. The resulting annual dividend of $366,250 if no preferred shares are converted would represent a significant financial commitment that could adversely affect our results of operations and financial condition.

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Qualitative and Quantitative Disclosures about Market and Credit Risk

We are exposed to certain market risks inherent within the intrastate natural gas gathering industry. We intend to manage our operations in a manner designed to minimize our exposure to such market risks.

Credit risk

Credit risk is the risk of loss resulting from non-performance of contractual obligations by a customer or joint venture partner. A substantial portion of our accounts receivable are expected to be with customers in the energy industry and are subject to normal industry credit risk. We intend to assess the financial strength of our customers through regular credit reviews in order to minimize the risk of non-payment.

Market risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Because we do not own the natural gas that is shipped on our gathering lines or processed in our facilities, we are not directly exposed to natural gas commodity price risk.

Interest rate risk

Interest rate risk will exist principally with respect to any future indebtedness that bears interest at floating rates. At December 31, 2004 we had $1,500,000 in bank indebtedness with a fluctuating interest rate equal to the JPMorgan Chase Bank prime rate. This line of credit matures the earlier of March 31, 2005 or within three days following the funding of the initial public offering.

Contractual obligations and commitments

We lease two compressors under non-cancelable operating leases. One lease expires in December 2005 and the other expires in December 2006. Total compressor rent expense for the year ended December 31, 2004 was approximately $391,800.

In February 2004 we entered into a six month apartment lease for our Chief Executive Officer which was renewed in August 2004 for one year. Rent expense for the year ended December 31, 2004 under this lease was approximately $15,860.

We entered into a vehicle lease for our Chief Executive Officer that will expire in April 2007. Rent expense for the year ended December 31, 2004 was approximately $3,860.

Our contractual obligations include accrued acquisition costs, operating leases and asset retirement obligations. The following table lists our contractual obligations as of December 31, 2004:

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Recent accounting pronouncements

In December 2004 the Financial Accounting Standards Board issued SFAS No. 123R (revised 2004), “Share-Based Payment”. SFAS No. 123R replaced SFAS No. 123 and superseded APB 25. SFAS No. 123R will require compensation cost related to share-based payment transactions to be recognized in financial statements. As permitted by SFAS No. 123, we elected to follow the guidance of APB 25, which allowed companies to use the intrinsic value method of accounting to value their share-based payment transactions with employees. Based on this method, we did not recognize compensation expense in our financials statements as the stock options granted had an exercise price equal to the fair market value of the underlying common stock on the date of the grant. SFAS No. 123R requires measurement of the cost of share-based payment transactions to employees at the fair value of the award on the grant date and recognition of expense over the requisite service or vesting period. SFAS No. 123R requires implementation using a modified version of prospective application, under which compensation expense for the unvested portion of previously granted awards and all new awards will be recognized on or after the date of adoption. SFAS No. 123R also allows companies to adopt SFAS No. 123R by restating previously issued financial statements, basing the amounts on the expense previously calculated and reported in their pro forma footnote disclosures required under SFAS No. 123. We have not decided which adoption method will be used. The provisions of SFAS No. 123R will be adopted by us effective July 1, 2005. The effect of the adoption of SFAS No. 123R is expected to be comparable to that disclosed on a pro forma basis as a result of applying the current fair value recognition provisions of SFAS No. 123.

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Business

Our business

We own and operate intrastate natural gas gathering systems. We commenced operations in January 2004 upon our acquisition of certain operating assets of TOP Gathering, LLC. We operate in the intrastate gas gathering environment, which is less regulated than interstate gas transportation, and currently plan to limit our expansion to intrastate operations. We charge the gas producer or shipper a fee for gathering, compressing and dehydrating natural gas. Our gathering systems collect gas at a producer’s wellhead or at a collection point and deliver it to a transmission line owned by a third party. We do not take ownership of gas that we gather.

Our 4.5 mile TOP system, located in Campbell County, Wyoming, services 56 wells operated by three natural gas producers in the Powder River Basin area of Wyoming. The gathering system has a current throughput capacity of approximately 8 million cubic feet of gas per day and is presently averaging approximately 4 million cubic feet per day or approximately 50% of capacity.

Effective August 1, 2004, we acquired certain operating assets of Bear Paw Energy, LLC also located in Campbell County, Wyoming. The approximately 200 mile gathering lines we acquired from Bear Paw service 12 producers of natural gas in the Powder River Basin area of Wyoming. The Bear Paw gathering systems’ original capacity was approximately 60 million cubic feet of gas per day. Recently there was a reconfiguration of a portion of the system to reduce the operating expenses, including compression facilities, which reduced the capacity to approximately 27 million cubic feet per day. The system is currently averaging approximately 18 million cubic feet per day or approximately 66% of the reconfigured capacity.

At December 31, 2004 we had 13 customers, three of which represent approximately 86% of our revenues. Pennaco Energy, Inc. accounts for approximately 37% of our revenues, e2 Business Systems, Inc. accounts for approximately 32% of our revenues and United Energy Trading, LLC accounts for approximately 17% of our revenues. No other customers exceed 5% of our revenues. None of our gas gathering and transportation agreements is with related parties.

We have two types of gathering contracts. Six of our contracts are currently on a volume only basis where we charge a set fee per thousand cubic feet, or Mcf, of gas gathered. One of our contracts includes a monthly minimum billing provision. The rates for these contracts vary from approximately $0.37 per Mcf to $0.70 per Mcf, with those below $0.53 per Mcf accounting for less than 4.6% of our revenues for the three months ended December 31, 2004. The balance of our gathering contracts are a combination of a $0.12 per Mcf fee based on volume and an additional fee for each compressor used on the system. These compression fees are allocated to each producer on the system based on its individual usage volumes and the total usage volumes of gas passing through the system. In November 2004 the gathering fees under this type of contract ranged from approximately $0.70 per Mcf to $0.89 per Mcf. These fees will vary monthly depending on the producers’ individual production and the system’s total throughput.

Two of our contracts have thresholds which provide for a reduction in rates. We assumed a gas gathering contract that commenced in October 2001 to gather and deliver gas for a related party for $0.89 per Mcf until such time as we received a total of 4.5 billion cubic feet, or Bcf, of gas from the shipper. Thereafter, the transportation fee will be reduced $0.05 for every 5 Bcf of gas received. The first threshold was reached in June 2004 and accordingly the rate was reduced to $0.84 per Mcf effective July 1, 2004. We estimate that the next threshold will not be reached for at least 10 years. The contract remains in effect as long as our gathering facility remains profitable. In the event the contract is unprofitable for us, we may terminate the contract with 30 days written notice. Revenues generated under this contract during the year ended December 31, 2004 were $560,138.

In addition, we assumed a 10-year gas gathering contract commencing in September 2002 to gather and deliver gas for an unrelated third party for $0.58 per Mcf until such time as the shipper has delivered 2 Bcf. Thereafter, the gathering fee will be reduced to $0.52 per Mcf. We estimate that this threshold will be reached in mid-2005. After the initial term, either party may terminate the contract with 30 days written notice. Revenues generated under this contract during the year ended December 31, 2004 were $415,218.

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Natural gas wells in the Powder River Basin area typically experience sharp declines in production volume in the first several years of production. Production then stabilizes and declines more ratably over a gas well’s average life of approximately eight to 10 years. Many of the wells serviced by our TOP and Bear Paw gathering systems have reached a stable decline phase of production. We believe that undeveloped reserves in the fields serviced by these systems may provide additional production that may offset future declines and possibly exceed current gas production. The throughput in our systems is not materially affected by seasonality.

Business strategy

We currently operate in the Powder River Basin and plan to limit our expansion to the less regulated intrastate environment, initially within the states of Wyoming, Colorado, Kansas, Oklahoma, North Dakota and Montana. We do not take ownership of the gas that we transport.

We plan to grow our present operations by:

•                  enhancing the present gathering systems through operating efficiencies and servicing additional wells and fields;

•                  designing and building new gathering systems; and

•                  acquiring existing gathering systems.

We consider gathering systems serving gas producers to represent good development or acquisition opportunities. A recent ruling by the Wyoming Supreme Court prohibits the deduction of gathering expenses in the calculation of net revenues on which royalties are paid if the producer owns the gathering system. This is advantageous for us since it is now more attractive to the producers to have gathering companies build and/or acquire their systems, thereby enabling the producers to deduct gathering fees paid to others for the purpose of calculating royalties due to landowners.

We currently have no agreements for the design of new systems or the acquisition of existing systems.

We believe that the current high level of drilling activity in the entire Rocky Mountain region presents a significant opportunity for gathering service providers.

Operations overview

We use a variety of tools to manage our business.

Flow and transaction monitoring systems. Our TOP operations receive information from a third party that utilizes a proprietary system to track commercial activity for the gathering system, including monitoring the daily flow of natural gas on the system. The Bear Paw operations utilize a proprietary system developed by Bear Paw that generates reports to us pursuant to our Operations Agreement with Bear Paw. If required we can obtain all information necessary to manage our systems directly and without either of the above proprietary systems.

Producer activity evaluation and reporting. We monitor the producer drilling and completion activity in our areas of operation to identify anticipated changes in production and potential new well attachment opportunities. The continuing attachment of new natural gas production to our pipeline systems is critical to our business and will directly impact our financial performance.

Imbalance monitoring and control. We continually monitor volumes received and volumes delivered on behalf of our third party producers to ensure they remain within acceptable imbalance limits during each calendar month. We do not take title to the gas and, therefore, are not exposed to imbalance payments; however, we are responsible for reporting imbalance limits to each of our customers.