S-1/A 1 d475659ds1a.htm FORM S-1/A Form S-1/A
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on May 6, 2013

Registration No. 333-187595

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 3

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Tallgrass Energy Partners, LP

(Exact Name of Registrant as Specified in its Charter)

 

 

 

Delaware   4922   46-1972941
(State or other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
  (IRS Employer
Identification Number)

6640 W. 143rd Street, Suite 200

Overland Park, Kansas 66223

(913) 928-6060

(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

 

 

George E. Rider

6640 W. 143rd Street, Suite 200

Overland Park, Kansas 66223

(913) 928-6060

(Address, including zip code, and telephone number, including area code, of Agent for service)

 

 

Copies to:

 

Laura Lanza Tyson

Baker Botts L.L.P.

98 San Jacinto Center, Suite 1500

Austin, Texas 78701

(512) 322-2500

 

David Palmer Oelman

Sarah K. Morgan

Vinson & Elkins L.L.P.

First City Tower

1001 Fannin, Suite 2500

Houston, Texas 77002-6760

(713) 758-2222

 

 

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  ¨     Accelerated filer  ¨
Non-accelerated filer  x   (Do not check if a smaller reporting company)   Smaller reporting company  ¨

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of Securities
to be Registered
 

Proposed
Maximum
Aggregate

Offering
Price(1)(2)

 

Amount of

Registration Fee
(3)

Common units representing limited partner interests

  $345,172,500   $47,082

 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
(3) The total registration fee includes $42,988 that was previously paid for the registration of $315,157,500 of proposed maximum aggregate offering price in the filing of the Registration Statement on March 28, 2013 and $4,094 for the registration of an additional $30,015,000 of proposed maximum aggregate offering price registered hereby.

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

 

 

 


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Index to Financial Statements

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted

 

 

Subject to Completion, dated May 6, 2013

PROSPECTUS

 

 

 

LOGO

Tallgrass Energy Partners, LP

13,050,000 Common Units

Representing Limited Partner Interests

 

 

This is the initial public offering of our common units representing limited partner interests. We are offering 13,050,000 common units in this offering. We currently expect that the initial public offering price will be between $21.00 and $23.00 per common unit. Prior to this offering, there has been no public market for our common units. We have been approved to list our common units on the New York Stock Exchange under the symbol “TEP,” subject to official notice of issuance.

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 25.

These risks include the following:

 

 

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

 

 

If we are unable to renew or replace expiring customer contracts at favorable rates or on a long-term basis, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders will be adversely affected.

 

 

Our operations are subject to extensive regulation by federal, state and local regulatory authorities.

 

 

Our general partner and its affiliates, including Tallgrass GP Holdings, which owns our general partner and the general partner of Tallgrass Development, LP, have conflicts of interest with us and limited duties to us and our unitholders.

 

 

Affiliates of our general partner are not limited in their ability to compete with us and have limited obligations to offer us the opportunity to acquire additional assets or businesses.

 

 

You will experience immediate dilution in net tangible book value of $12.24 per common unit.

 

 

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

 

Holders of our common units have limited voting rights and are not entitled to select our general partner or elect members of its board of directors.

 

 

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

 

 

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

In addition, we qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933 and, as such, are allowed to provide in this prospectus more limited disclosures than an issuer that would not so qualify. Furthermore, for so long as we remain an emerging growth company, we will qualify for certain limited exceptions from investor protection laws such as the Sarbanes Oxley Act of 2002 and the Investor Protection and Securities Reform Act of 2010. Please read “Risk Factors” and “Prospectus Summary—Implications of Being an Emerging Growth Company.”

 

     Per Common Unit      Total  

Public Offering Price

   $                                $                

Underwriting Discount(1)

   $         $     

Proceeds to Tallgrass Energy Partners, LP (Before Expenses)

   $         $     

 

(1) Excludes a structuring fee of an aggregate of 0.50% of the gross offering proceeds payable to Barclays Capital Inc. and Citigroup Global Markets Inc. Please read “Underwriting.”

To the extent that the underwriters sell more than 13,050,000 common units in this offering, the underwriters have the option to purchase up to an additional 1,957,500 common units from Tallgrass Energy Partners, LP at the initial public offering price less underwriting discounts.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units to purchasers on or about                     , 2013, through the book-entry facilities of The Depository Trust Company.

 

 

 

Barclays    Citigroup   BofA Merrill Lynch   Deutsche Bank Securities

 

 

 

Credit Suisse    Morgan Stanley   RBC Capital Markets   Wells Fargo Securities
Baird            Stifel

Prospectus dated                     , 2013


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Index to Financial Statements

LOGO


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     25   

USE OF PROCEEDS

     65   

CAPITALIZATION

     66   

DILUTION

     68   

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     70   

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

     90   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

     104   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     108   

INDUSTRY OVERVIEW

     129   

BUSINESS

     136   

MANAGEMENT

     158   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     165   

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     166   

CONFLICTS OF INTEREST AND DUTIES

     171   

DESCRIPTION OF THE COMMON UNITS

     180   

THE PARTNERSHIP AGREEMENT

     182   

UNITS ELIGIBLE FOR FUTURE SALE

     195   

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

     197   

INVESTMENT IN TALLGRASS ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS AND IRAS

     214   

UNDERWRITING

     216   

VALIDITY OF THE COMMON UNITS

     224   

EXPERTS

     224   

WHERE YOU CAN FIND MORE INFORMATION

     224   

FORWARD-LOOKING STATEMENTS

     226   

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF TALLGRASS ENERGY PARTNERS, LP

     A-1   

APPENDIX B—GLOSSARY OF TERMS

     B-1   

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus includes industry data and forecasts that we obtained from industry publications and surveys, public filings and internal company sources. We did not commission any of the third-party industry publications or surveys from which we obtained the industry data and forecasts included in this prospectus.

 

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including “Risk Factors” and the historical and pro forma financial statements and the notes to those financial statements included elsewhere in this prospectus. Unless indicated otherwise, the information presented in this prospectus assumes (1) an initial public offering price of $22.00 per common unit (the midpoint of the price range set forth on the cover page of this prospectus), (2) that the underwriters do not exercise their option to purchase additional units (resulting in an additional 1,957,500 common units shown as issued to Tallgrass Development) and (3) that at the completion of the transactions described in this prospectus (including the issuance of the units subject to the underwriters’ option to purchase additional units) our general partner will own a 2.0% general partner interest in us. We include a glossary of some of the terms used in this prospectus as Appendix B. References in this prospectus to “Tallgrass,” “we,” “our,” “us” or like terms when used in a historical context refer to the businesses and assets of Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC, each of which Tallgrass Development, LP is contributing to Tallgrass Energy Partners, LP in connection with this offering. When used in the present tense or prospectively, those terms refer to Tallgrass Energy Partners, LP and its subsidiaries. References to our “general partner” are to Tallgrass MLP GP, LLC, a Delaware limited liability company and our general partner. References to “Kelso” are to Kelso & Company and its affiliated investment funds and other entities under its control, and references to “EMG” are to The Energy & Minerals Group, its affiliated investment funds and other entities under its control. References to “Tallgrass GP Holdings” are to Tallgrass GP Holdings, LLC, a Delaware limited liability company owned by Kelso, EMG and certain members of our management team. Tallgrass GP Holdings is the sole owner of both our general partner and of the general partner of Tallgrass Development, LP. References in this prospectus to “Tallgrass Development” are to Tallgrass Development, LP and its subsidiaries and affiliates, other than our general partner and us. Please read “—Formation Transactions and Partnership Structure.”

Tallgrass Energy Partners, LP

Overview

We are a growth-oriented Delaware limited partnership formed by Tallgrass Development to own, operate, acquire and develop midstream energy assets in North America. We currently provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through our Tallgrass Interstate Gas transportation system (referred to in this prospectus as the TIGT System) and provide processing services for customers in Wyoming through our Casper and Douglas natural gas processing and West Frenchie Draw natural gas treating facilities (collectively referred to in this prospectus as the Midstream Facilities). We intend to leverage our relationship with Tallgrass Development and utilize the significant experience of our management team to execute our growth strategy of acquiring midstream assets from Tallgrass Development and third parties, increasing utilization of our existing assets and expanding our systems through organic growth projects.

For the period from January 1, 2012 to November 12, 2012, we reported net income of approximately $51.5 million. For the period from November 13, 2012 to December 31, 2012, we incurred a net loss of approximately $1.4 million. For the year ended December 31, 2012, we generated Adjusted EBITDA of approximately $76.4 million. Adjusted EBITDA is a non-GAAP financial measure. For more information regarding Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable GAAP measure, please read “Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

In November 2012, Tallgrass Development acquired from Kinder Morgan Energy Partners, L.P. (NYSE: KMP), or Kinder Morgan, a portfolio of midstream energy assets having an enterprise value of approximately $3.3 billion (based on the cash purchase price paid and Tallgrass Development’s proportionate share of the

 

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indebtedness of the acquired entities). Tallgrass Development will contribute the TIGT System and the Midstream Facilities to us in connection with this offering and will continue to own and manage all of the other assets acquired from Kinder Morgan, which we refer to as the Retained Assets, including a substantial organic growth project that we refer to as the Pony Express Project, as described in more detail below under “—Tallgrass Development.” Tallgrass Development’s decision to contribute the TIGT System and the Midstream Facilities to us was driven primarily by its belief that the contributed assets are mature assets with established stable cash flow generation profiles. In contrast, each of the Retained Assets will require additional development before such assets will be suitable to serve our business objectives. For example, the Pony Express Project (described below) is currently under development and not expected to be placed into service until the second half of 2014. Upon the closing of this offering, we will enter into an omnibus agreement pursuant to which Tallgrass Development will grant us a right of first offer to acquire certain assets, including each of the Retained Assets. Other than these omnibus agreement provisions, Tallgrass Development is under no obligation to offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy the Retained Assets or any such additional assets or pursue any such joint acquisitions. It is uncertain if or when Tallgrass Development will make acquisition opportunities available to us, however, given the significant economic interest in us held by Tallgrass Development and its affiliates, we believe Tallgrass Development will be incentivized to offer us the opportunity to acquire each of the Retained Assets as each matures into an operating profile more conducive to our principal business objective of increasing the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. Please read “—Our Relationship with Tallgrass Development.”

Following the completion of this offering and the contribution by Tallgrass Development of the TIGT System and Midstream Facilities to us, we will conduct our business in two segments:

Gas Transportation and Storage. The TIGT System is a FERC-regulated natural gas transportation and storage system with approximately 4,645 miles of varying diameter transportation pipelines in Wyoming, Colorado, Kansas, Missouri and Nebraska. Following the Pony Express Abandonment described below under “—Pony Express Abandonment,” the TIGT System will have capacity to transport up to approximately 938 MMcf/d and will be powered by 22 transportation and storage compressor stations with approximately 136,608 horsepower of installed compression. The TIGT System also includes the Huntsman natural gas storage facility, located in Cheyenne County, Nebraska, which is operated at approximately 35.1 Bcf of storage capacity, of which approximately 15.1 Bcf is working gas, with approximately 210 MMcf/d of peak withdrawal capability. As of December 31, 2012, approximately 72% of our pipeline transportation capacity and 74% of our working gas storage capacity on the TIGT System was committed under firm contracts that obligate our customers to pay a fixed monthly reservation or demand charge, which is owed regardless of the actual pipeline or storage capacity used by a customer. Additionally, our customers pay a nominal usage fee based on actual volumes transported or stored. As of December 31, 2012, the firm contracts with respect to our transportation and storage services had a weighted average remaining life of approximately four years and two years, respectively.

The TIGT System primarily provides transportation and storage services to on-system customers such as local distribution companies, or LDCs, and other industrial users, including ethanol plants, and irrigation and grain drying operations, which depend on the TIGT System’s interconnections to their facilities to meet their demand for natural gas and a majority of whom pay FERC-approved recourse rates. Over the past several years, a number of our transportation and storage customers have opted not to renew their contracts for service on the TIGT System, which was the primary cause of the decrease in transportation services revenues from $142.4 million for the year ended December 31, 2010 to $106.3 million for the year ended December 31, 2012. These former customers are generally large producers that primarily used the TIGT System to access interstate pipelines for ultimate delivery to consuming markets outside our areas of operations, as opposed to our current customer base, which is primarily comprised of on-system regional customers, such as LDCs. For the year ended December 31, 2012, approximately 65% of our transportation and storage revenue was generated from contracts

 

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with on-system customers. In addition, nearly half of our remaining transportation and storage revenue during the year ended December 31, 2012 was generated by an off-system customer contracted through 2017. As a result, we believe the TIGT System is positioned to maintain a relatively stable, on-system customer base going forward.

The table below sets forth certain information regarding our gas transportation and storage segment as of December 31, 2012:

 

     Capacity    Total Firm
Contracted
Capacity(1)
   % of Capacity
Subscribed under
Firm Contracts
    Weighted Average
Remaining Firm
Contract Life(2)
 

Transportation

   938 MMcf/d    678 MMcf/d      72     4 yrs   

Storage

   15.1 Bcf (3)    11.1 Bcf      74     2 yrs   

 

(1) Reflects total capacity reserved under firm contracts, which require the customer to pay a fixed monthly charge to reserve an agreed upon amount of transportation or storage capacity regardless of the actual amount of transportation or storage capacity used by the customer during each month.
(2) Weighted by contracted capacity.
(3) Represents working gas storage capacity.

Adjusted EBITDA associated with our gas transportation and storage segment represented approximately 72% of our total Adjusted EBITDA for the year ended December 31, 2012. For more information regarding Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable GAAP measure, please read “Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

Pony Express Abandonment. We have filed an application with the FERC to take out of gas service approximately 430 miles of natural gas pipeline, rights-of-way and related equipment and assets that are currently part of the TIGT System, which we refer to as the Pony Express Assets, and to sell those assets to a subsidiary of Tallgrass Development in connection with Tallgrass Development’s Pony Express Project, as described in greater detail under “—Our Relationship with Tallgrass Development” below. This abandonment and sale is conditioned upon receipt of the required FERC approvals and completion of the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System, which we refer to as the Replacement Gas Facilities, and is currently expected to occur in the fourth quarter of 2013. For a more detailed description of the FERC application and the proposed abandonment and sale, see “Certain Relationships and Related Transactions—Contracts with Affiliates—Pony Express Abandonment.” In this prospectus, we refer to (i) the abandonment of the Pony Express Assets, (ii) the construction of the Replacement Gas Facilities and incremental costs of continuing existing service and related contractual reimbursements, (iii) the sale of the Pony Express Assets to a subsidiary of Tallgrass Development and (iv) reimbursements for costs incurred to construct the Replacement Gas Facilities and to transport gas on third party pipelines to enable continuation of service to customers who previously received gas transported on the abandoned portion of the TIGT System, collectively as the “Pony Express Abandonment.” Although the Pony Express Abandonment will not take place until after the completion of this offering, we have excluded the Pony Express Assets and included the Replacement Gas Facilities in our descriptions of the physical characteristics of the TIGT System above and throughout this prospectus, as we believe this treatment provides a more meaningful depiction of our assets as they will exist on a going-forward basis. However, the historical financial information included in this prospectus does include results related to the Pony Express Assets, although we do not believe the Pony Express Abandonment will have a material impact on our financial results going forward.

Processing. The Midstream Facilities are comprised of natural gas processing plants in Casper and Douglas, Wyoming, and a natural gas treating facility in West Frenchie Draw, Wyoming. The Casper and Douglas plants currently have combined capacity of 138.5 MMcf/d. Currently, 100% of our existing capacity at our Midstream

 

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Facilities has been reserved. In exchange for these reservations, we typically receive a fee, acreage dedication or, in some cases, an agreement to pay for a minimum amount of throughput. However, the majority of our cash flow generated in this segment is based on the volumes actually processed.

We are currently undertaking an expansion of the Casper and Douglas plants to increase their combined capacity by approximately 50 MMcf/d and expect the project to be completed in the second half of 2013. The Casper and Douglas plants are the only natural gas processing plants that currently provide straddle processing of natural gas flowing into the TIGT System out of the Niobrara shale. In addition, the Casper plant has a natural gas liquid, or NGL, fractionator with a capacity of approximately 2,000 barrels per day as of December 31, 2012. Our Casper NGL fractionator is undergoing an expansion in connection with the Casper and Douglas plant expansion project referred to above, and we expect that this expansion, which is anticipated to be completed in the second half of 2013, will increase our NGL fractionator’s capacity by approximately 1,500 barrels per day. NGLs produced by the Casper and Douglas plants are either sold into local markets consisting primarily of retail propane dealers and oil refiners or sold to Phillips 66 Company via its Powder River NGL pipeline.

The table below sets forth certain information regarding our processing segment as of December 31, 2012, or for the periods indicated:

 

     Existing
Capacity
Under
Contract
  Weighted
Average
Remaining
Contract
Term(3)
   Approximate Average Inlet
Volumes for

(MMcf/d)
 

Plant Capacity (MMcf/d)(1)

        Year Ended
December 31,
2011
     Three-Month
Period Ended
December 31,
2012
 

Existing

  

Expansion(2)

          

138.5

   188.5    100%   5 yrs      117         128   

 

(1) The West Frenchie Draw natural gas treating facility treats natural gas before it flows into the Casper and Douglas plants and therefore does not result in additional inlet capacity.
(2) Reflects estimated total capacity following completion of the ongoing expansion of our Casper and Douglas plants, which is expected to be completed in the second half of 2013.
(3) Based on the average annual reservation capacity for each such contract’s remaining life.

Adjusted EBITDA associated with our processing segment represented approximately 28% of our total Adjusted EBITDA for the year ended December 31, 2012. For more information regarding Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable GAAP measure, please read “Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

Tallgrass Development

Following the completion of this offering and Tallgrass Development’s contribution of the TIGT System and the Midstream Facilities to us, Tallgrass Development will continue to own and manage a substantial portfolio of midstream assets, including the following assets to which Tallgrass Development has granted us a right of first offer:

 

   

a substantial organic growth project referred to in this prospectus as the Pony Express Project, which upon completion will consist of an approximately 690 mile oil pipeline connecting the Bakken Shale to Cushing, Oklahoma. The Pony Express Project will primarily consist of (i) the purchase of the Pony Express Assets by a subsidiary of Tallgrass Development and the conversion of the Pony Express Assets into an oil pipeline serving the Bakken Shale and other nearby oil producing basins and (ii) the construction of an approximately 260-mile southward extension of the converted oil pipeline to provide deliveries to Cushing, Oklahoma. The converted pipeline and related expansion pipeline forming the Pony Express Project is expected to be placed in service in the second half of 2014.

 

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the Trailblazer Pipeline, an approximately 439-mile interstate pipeline with a capacity of up to 862 MMcf/d, that transports natural gas from southeastern Wyoming to interconnections with the Natural Gas Pipeline Company of America and Northern Natural Gas Company pipeline systems in Nebraska; and

 

   

a 50% interest in, and operation of, the Rockies Express Pipeline, or the REX Pipeline, a modern approximately 1,698-mile natural gas pipeline with a long-haul design capacity of up to 1.8 Bcf/d, that extends from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio.

Tallgrass Development will also own an approximately 66% limited partner interest in us. In addition, Tallgrass Development is controlled by its general partner, Tallgrass Development GP, LLC, which is wholly-owned by Tallgrass GP Holdings, the sole owner of our general partner, which will own our 2% general partner interest and all of our incentive distribution rights, or IDRs. Upon the closing of this offering, we will enter into an omnibus agreement pursuant to which Tallgrass Development will grant us a right of first offer to acquire certain assets, including each of the Retained Assets. Other than these omnibus agreement provisions, Tallgrass Development is under no obligation to offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy the Retained Assets or any such additional assets or pursue any such joint acquisitions. However, given the significant economic interest in us held by Tallgrass Development and its affiliates following this offering, we believe Tallgrass Development will be incentivized to offer us the opportunity to acquire any additional midstream assets that it owns.

Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. We expect to achieve this objective through the following business strategies:

 

   

Growing our business by pursuing accretive acquisitions from Tallgrass Development and third parties. We intend to pursue acquisitions from Tallgrass Development that we expect will be sourced both from Tallgrass Development’s existing portfolio of midstream assets and from additions to its portfolio from expansion projects or acquisitions that it undertakes in the future. In addition, we will review acquisition opportunities from third parties as they become available.

 

   

Capitalizing on organic expansion opportunities. We continually evaluate economically attractive, organic expansion opportunities in existing or new areas of operation that will allow us to leverage our market position and other competitive strengths. We intend to pursue high-value accretive growth projects in growing areas that will provide diversification and economies of scale.

 

   

Maintaining and growing stable cash flows supported by long-term, fee-based contracts. We will seek to generate the majority of our cash flows pursuant to multi-year, firm contracts with creditworthy customers. We will continue to pursue opportunities to increase the fee-based component of our contract portfolio to minimize our direct commodity price exposure through contract renewal negotiations, acquisitions or other growth projects.

 

   

Maintain a conservative and flexible capital structure in order to pursue acquisition and expansion opportunities and lower our overall cost of capital. We intend to target credit metrics consistent with the profile of investment grade midstream energy companies. We intend to maintain a conservative and balanced capital structure which, when combined with our stable, fee-based cash flows, will afford us efficient access to the capital markets at a competitive cost of capital.

 

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Competitive Strengths

We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

 

   

Stable cash flows supported by attractive contract mix and customer profile. A substantial majority of our revenue is produced under long-term contracts with high-quality customers. We believe this profile, along with our contract mix, gives us the ability to maintain a stable cash flow and thereby provides operating visibility and flexibility.

 

   

Strategic infrastructure with close proximity to demand markets and supply sources. We believe our assets represent an important link to end-user markets in the Midwest and are well positioned to continue to capture growing natural gas volumes in the Denver-Julesburg Basin and the Niobrara and Mississippi Lime shale formations. The TIGT System primarily provides transportation and storage services to on-system customers such as LDCs and other industrial users, including ethanol plants, and irrigation and grain drying operations, which depend on the TIGT System’s interconnections to their facilities and a majority of whom pay FERC-approved recourse rates. In addition, we believe the substantial number of interconnections with other energy infrastructure assets contributes to making the TIGT System a strategic part of the flow of natural gas in the Midwest.

 

   

Relationship with Tallgrass Development. We believe that Tallgrass Development and its affiliates, as the owners of a 66% limited partnership interest in us, a 2% general partner interest in us and all of our IDRs are motivated to promote and support the successful execution of our principal business objective and to pursue projects that directly or indirectly enhance the value of our assets through, for example, the right of first offer with respect to the Retained Assets, providing other acquisition opportunities and an executive team with significant industry and management expertise.

 

   

Financial flexibility to pursue expansion and acquisition opportunities. We believe our cash flows, unused borrowing capacity, and access to debt and equity capital markets will provide us financial flexibility to competitively pursue acquisition and expansion opportunities. At the consummation of this offering, we expect to have approximately $275 million of available borrowing capacity under our revolving credit facility to fund acquisitions, expansions and working capital needs.

 

   

Incentivized management team. Members of our management team are strongly incentivized to grow our business and cash flows through their indirect 25% interest in our general partner, which will own our 2.0% general partner interest and all of our IDRs following this offering.

Risk Factors

An investment in our common units involves risks associated with our business, our regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus before deciding whether to invest in our common units.

Risks Related to Our Business

 

   

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

 

   

The assumptions underlying the forecast of cash available for distribution that we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant risks and uncertainties that could cause actual results to differ materially from those forecasted.

 

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Index to Financial Statements
   

If we are not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, our financial condition, results of operation, cash flows and ability to make cash distributions to our unitholders will be adversely affected.

 

   

If we are unable to make acquisitions on economically acceptable terms from Tallgrass Development or third parties, our future growth may be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

 

   

We are exposed to direct commodity price risk with respect to the majority of our processing revenues, and our exposure to direct commodity price risk may increase in the future.

 

   

Our operations are subject to extensive regulation by federal, state and local regulatory authorities.

 

   

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures that could exceed our current expectations.

Risks Inherent in an Investment in Us

 

   

Our general partner and its affiliates, including Tallgrass GP Holdings, which owns our general partner and the general partner of Tallgrass Development, have conflicts of interest with us and limited duties to us and our unitholders.

 

   

Affiliates of our general partner are not limited in their ability to compete with us and have limited obligations to offer us the opportunity to acquire additional assets or businesses.

 

   

Holders of our common units have limited voting rights and are not entitled to select our general partner or elect members of its board of directors.

 

   

If you are not an Eligible Taxable Holder, your common units may be subject to redemption.

Tax Risks to Common Unitholders

 

   

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

 

   

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis.

 

   

Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

Our Relationship with Tallgrass Development

One of our principal strengths is our relationship with Tallgrass Development, a leading provider of midstream energy services in the United States. In November 2012, Tallgrass Development acquired a portfolio of midstream energy assets from Kinder Morgan having an enterprise value of approximately $3.3 billion (based on the cash purchase price paid and Tallgrass Development’s proportionate share of the indebtedness of the acquired entities).

Following the completion of this offering and Tallgrass Development’s contribution of the TIGT System and the Midstream Facilities to us, Tallgrass Development will continue to own and manage a substantial portfolio of midstream assets, including the Pony Express Project (following the Pony Express Abandonment), the Trailblazer Pipeline and a 50% interest in the REX Pipeline.

 

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Tallgrass Development is controlled by its general partner, Tallgrass Development GP, LLC, which is wholly-owned by Tallgrass GP Holdings, the sole owner of our general partner. Tallgrass Development is led by its President and Chief Executive Officer, David G. Dehaemers, Jr., and a management team with significant midstream energy experience. Additionally, a significant portion of the Kinder Morgan employees formerly involved in the operation of the assets acquired by Tallgrass Development are now employed by Tallgrass Management, LLC, an affiliate of the general partner of Tallgrass Development, which we refer to in this prospectus as Tallgrass Management. We also share a management team with Tallgrass Development and, as a result, will have access to strong commercial relationships throughout the energy industry and a broad operational, commercial, technical, risk management and administrative infrastructure.

In exchange for the assets contributed to the Partnership by Tallgrass Development, we will (i) issue to Tallgrass Development 11,250,000 common units and 16,200,000 subordinated units, representing a 66% limited partner interest in us (62% if the underwriters exercise in full their option to purchase additional common units), (ii) assume from Tallgrass Development $400 million of indebtedness and (iii) pay to Tallgrass Development $85.5 million in cash as reimbursement for a portion of the capital expenditures made by Tallgrass Development to purchase the contributed assets. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public and the net proceeds from such sale will be distributed to Tallgrass Development and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Tallgrass Development at the expiration of the option period. Our general partner will also receive its 2% general partner interest and the IDRs in exchange for the contribution of membership interests in Tallgrass MLP Operations, LLC to us.

At the completion of this offering, Tallgrass Development will own a 66% limited partner interest in us and its affiliates will own a 2% general partner interest in us and all of our IDRs. Given the significant ownership interests in us that will be retained by Tallgrass Development and its affiliates following this offering, we believe that they will be motivated to promote and support the successful execution of our business strategies, including through our potential acquisition of additional midstream assets from Tallgrass Development over time and the facilitation of accretive acquisitions from third parties, although Tallgrass Development is under no obligation to offer any assets or business opportunities to us, other than the obligation under the omnibus agreement to offer us certain assets, including the Retained Assets, pursuant to the right of first offer, or accept any offer for its assets that we may choose to make.

At the closing of this offering, we will enter into an omnibus agreement with Tallgrass Development and our general partner that will govern our relationship with them regarding our right of first offer to acquire certain assets, including the Retained Assets, as well as certain expense reimbursement and indemnification matters, among other things. Please read “Certain Relationships and Related Transactions—Agreements with Affiliates—Omnibus Agreement.”

Our Relationship with EMG and Kelso

EMG and Kelso collectively own 75% of Tallgrass GP Holdings, the owner of our general partner. Members of our management team own the remaining 25% interest in Tallgrass GP Holdings. EMG and Kelso acquired membership interests in Tallgrass Development GP as well as limited partner interests in Tallgrass Development in August 2012 in order to fund a portion of the cash purchase price paid by Tallgrass Development in connection with the acquisition of assets from Kinder Morgan. In connection with the closing of this offering, the members of Tallgrass Development GP formed Tallgrass GP Holdings to act as a holding company for Tallgrass Development GP and our general partner and will contribute their membership interests in Tallgrass Development GP to Tallgrass GP Holdings in exchange for identical membership interest percentages in Tallgrass GP Holdings.

 

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EMG is the management company for a series of specialized private equity funds. EMG focuses on investing across various facets of the global natural resource industry including the upstream and midstream segments of the energy complex. EMG has approximately $6.2 billion of total investor commitments (including co-investments) with in excess of $3.1 billion deployed across the energy sector since inception.

Kelso is one of the oldest and most established firms specializing in private equity. Since 1980, Kelso has invested in over 115 companies in a broad range of industry sectors, including over $2.0 billion of equity invested in energy-related companies.

Management of Tallgrass Energy Partners, LP

We are managed and operated by the board of directors and executive officers of our general partner. Tallgrass GP Holdings is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to select our general partner or elect the members of the board of directors of our general partner. All of the executive officers and the directors of our general partner are also officers and/or directors of Tallgrass GP Holdings. For information about the executive officers and directors of our general partner, please read “Management.” Upon completion of this offering, our general partner will have six directors, one of which will have been appointed to the audit committee of the board of directors of our general partner. Under the listing requirements of the New York Stock Exchange, or NYSE, the board of directors of our general partner will be required to have an audit committee consisting of at least three independent directors meeting the NYSE’s independence standards within one year following the date our common units are listed for trading on the NYSE.

In order to maintain operational flexibility, our operations are conducted through, and our operating assets are owned by wholly-owned operating subsidiaries. However, neither we nor any of our wholly-owned operating subsidiaries have any employees. Although all of the employees that conduct our business are employed by Tallgrass Management, we sometimes refer to these individuals in this prospectus as our employees.

Neither our general partner nor Tallgrass Development’s general partner and its affiliates will receive any management fee or other compensation in connection with the management of our business, but we will reimburse our general partner for all expenses it incurs and payments it makes on our behalf pursuant to our partnership agreement. In addition, we will reimburse Tallgrass Development’s general partner and its affiliates for all expenses they incur and payments they make on our behalf pursuant to the omnibus agreement, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain corporate, general and administrative services in each case to the extent properly allocable to us. Our partnership agreement provides that our general partner will determine in good faith which expenses are appropriately allocable to us. These expenses will vary with the size and scale of our operations, among other factors. We currently anticipate that reimbursable expenses will be approximately $46.8 million for the twelve months ended June 30, 2014 based on our current operations. Neither our partnership agreement nor our omnibus agreement limits the amount of expenses for which our general partner and its affiliates may be reimbursed. All reimbursements to our general partner and Tallgrass Development’s general partner and its affiliates will be made prior to cash distributions to our common unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever economically practical, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it.

Following the completion of this offering, our general partner will own 826,531 general partner units representing a 2.0% general partner interest in us, which will entitle it to receive 2.0% of all the distributions we make. Our general partner will also own all of our IDRs, which will entitle it to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.3048 per unit per quarter after the closing of our initial public offering. Please read “Certain Relationships and Related Transactions.”

 

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Summary of Conflicts of Interest and Duties

General

Our general partner has a duty to manage us in a manner it believes is in the best interests of our partnership and our unitholders. However, the officers and directors of our general partner also have a duty to manage the business of our general partner in a manner they believe is in the best interests of its owner, Tallgrass GP Holdings. All of the officers and directors of our general partner are also officers and/or directors of Tallgrass GP Holdings, which is owned by members of our management team, Kelso and EMG. As a result, conflicts of interest may arise in the future between us and holders of our common units, on the one hand, and Tallgrass GP Holdings and our general partner, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units and subordinated units, which in turn has an effect on whether our general partner receives incentive cash distributions. For a more detailed description of the conflicts of interest of our general partner, please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties—Conflicts of Interest.”

Partnership Agreement Replacement of Fiduciary Duties

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each common unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

Kelso, EMG and Tallgrass Development May Compete Against Us

Although our relationships with Kelso, EMG and Tallgrass Development are valuable assets to us, they are also a source of potential conflict. For example, our partnership agreement does not prohibit Kelso, EMG, Tallgrass Development or any of their respective affiliates, other than our general partner, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Tallgrass Development may acquire, construct or dispose of additional midstream or other assets in the future, with limited obligations to offer us the opportunity to acquire any of those assets. For example, Tallgrass Development will retain its ownership of Trailblazer Pipeline, its 50% ownership interest in the REX Pipeline and, following the Pony Express Abandonment, the Pony Express Project. These assets will not be part of the assets that Tallgrass Development will contribute to us in connection with the closing of this offering, or, in the case of the Pony Express Project, will be sold to a subsidiary of Tallgrass Development shortly following this offering. Upon the closing of this offering, we will enter into an omnibus agreement pursuant to which Tallgrass Development will grant us a right of first offer to acquire certain assets, including each of the remaining Retained Assets. Other than the right of first offer in the omnibus agreement, Tallgrass Development is under no obligation to offer to sell us any of the Retained Assets or any additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any of the Retained Assets or such additional assets or pursue any such joint acquisitions.

For a more detailed description of the conflicts of interest and the duties of our general partner, please read “Conflicts of Interest and Duties.” For a description of other relationships with our affiliates, please read “Certain Relationships and Related Transactions.”

 

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Formation Transactions and Partnership Structure

At or prior to the completion of this offering, the following transactions, which we refer to as the formation transactions, will occur:

 

   

Tallgrass Development will contribute 100% of the membership interests in each of Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC to us;

 

   

we will (i) issue to Tallgrass Development 11,250,000 common units and 16,200,000 subordinated units, representing a 66% limited partner interest in us (62% if the underwriters exercise in full their option to purchase additional common units), (ii) assume from Tallgrass Development $400 million of indebtedness and (iii) pay to Tallgrass Development $85.5 million in cash as reimbursement for a portion of the capital expenditures made by Tallgrass Development to purchase the contributed assets;

 

   

we will issue to our general partner 826,531 general partner units, representing its initial 2.0% general partner interest in us, and all of our IDRs;

 

   

we will issue 13,050,000 common units to the public in this offering, representing a 32% limited partner interest in us (36% if the underwriters exercise in full their option to purchase additional common units), and will use the proceeds of this offering to pay expenses associated with this offering and to retire approximately $264.4 million of the debt assumed from Tallgrass Development;

 

   

we will enter into a new $500 million revolving credit facility, as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility,” and will borrow approximately $225 million, the proceeds of which will be used to repay the remaining approximately $135.6 million of debt assumed from Tallgrass Development, to pay origination fees related to our new revolving credit facility and to pay $85.5 million to Tallgrass Development as reimbursement for a portion of the capital expenditures made by Tallgrass Development to purchase the contributed assets, which Tallgrass Development acquired together with the Retained Assets for $1.8 billion; and

 

   

we will enter into an omnibus agreement with Tallgrass Development, its general partner and our general partner, which will address, among other things, our right of first offer to acquire certain assets, including the Retained Assets, from Tallgrass Development, the provision of and the reimbursement for, general and administrative and operating services and indemnification of certain items by Tallgrass Development.

The number of common units to be issued to Tallgrass Development includes 1,957,500 common units that will be issued at the expiration of the underwriters’ option to purchase additional common units, assuming that the underwriters do not exercise their option. Any exercise of the underwriters’ option to purchase additional units would reduce the common units shown as issued to Tallgrass Development by the number to be purchased by the underwriters in connection with such exercise. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public and the net proceeds from such sale will be distributed to Tallgrass Development and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Tallgrass Development at the expiration of the option period.

 

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Ownership of Tallgrass Energy Partners, LP

The following diagram depicts our simplified organizational and ownership structure after giving effect to the formation transactions and this offering.

 

Public Common Units(1)

     31.6

Tallgrass Development

  

Common Units(1)

     27.2

Subordinated Units

     39.2

General Partner Units

     2.0
  

 

 

 

Total

     100.0
  

 

 

 

 

(1) Assumes no exercise of the underwriters’ option to purchase additional common units. Please read “—Formation Transactions and Partnership Structure” for a description of the impact of an exercise of the option on the common unit ownership percentages.

 

LOGO

 

(1) Tallgrass Holdings, LLC, an affiliate of EMG, owns approximately 38%. KIA VIII (Rubicon), L.P. and KEP VI AIV (Rubicon), LLC, affiliates of Kelso, own approximately 37%. Tallgrass KC, LLC, an entity owned by members of management, owns approximately 25%. Certain other investors own a de minimis percentage.
(2) Tallgrass Holdings, LLC, an affiliate of EMG, owns approximately 39%. KIA VIII (Rubicon), L.P. and KEP VI AIV (Rubicon), LLC, affiliates of Kelso, own approximately 49%. MTP Energy KMAA LLC, an entity affiliated with Magnetar Capital, owns approximately 10%. A trust owned and controlled by our chief executive officer, David G. Dehaemers, Jr., owns approximately 2%. Certain other investors own a de minimis percentage.

 

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Principal Executive Offices and Internet Address

Our principal executive offices are located at 6640 W. 143rd Street, Suite 200, Overland Park, Kansas 66223, and our telephone number is (913) 928-6060. Our website is located at www.tallgrassenergy.com and will be activated immediately following this offering. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Implications of Being an Emerging Growth Company

We qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other regulatory requirements for up to five years that are otherwise applicable generally to public companies. These provisions include:

 

   

a requirement to present only two years of audited financial statements and only two years of related Management’s Discussion and Analysis;

 

   

exemption from the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act;

 

   

exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and

 

   

reduced disclosure about executive compensation arrangements in our periodic reports.

We have elected to take advantage of all applicable JOBS Act provisions. Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to take advantage of this extended transition period for complying with new or revised accounting standards.

We will cease to be an emerging growth company prior to the fifth anniversary of this offering if we have more than $1.0 billion in annual revenues, have more than $700 million in market value of our limited partner interests held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

 

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The Offering

 

Common units offered to the public

13,050,000 common units, or 15,007,500 common units if the underwriters exercise their option to purchase additional common units in full.

 

Units outstanding after this offering

24,300,000 common units and 16,200,000 subordinated units, representing a 59% and 39% limited partner interest in us, respectively. If the underwriters do not exercise their option to purchase additional common units, we will issue an additional 1,957,500 common units to Tallgrass Development at the expiration of the option for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public and the net proceeds will be distributed to Tallgrass Development, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Tallgrass Development at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Our general partner will own 826,531 general partner units, representing a 2.0% general partner interest in us.

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $264.4 million from this offering (assuming an initial public offering price of $22.00 per common unit, the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts, the structuring fee and offering expenses payable by us of approximately $22.7 million, to retire approximately $264.4 million of the indebtedness assumed from Tallgrass Development.

 

  At the closing of this offering, we intend to enter into a new $500 million revolving credit facility, as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility,” and to borrow approximately $225 million, the proceeds of which will be used to:

 

   

retire the remaining approximately $135.6 million of indebtedness assumed from Tallgrass Development;

 

   

pay approximately $5.2 million in revolving credit facility origination fees; and

 

   

pay $85.5 million to Tallgrass Development as reimbursement for a portion of the capital expenditures made by Tallgrass Development to purchase the contributed assets, which Tallgrass Development acquired together with the Retained Assets for $1.8 billion.

 

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  The indebtedness assumed from Tallgrass Development was used by Tallgrass Development to acquire certain assets from Kinder Morgan, including the assets being contributed to us in connection with this offering, in November 2012. Please read “Prospectus Summary—Our Relationship with Tallgrass Development.” Certain of the underwriters are lenders under the senior secured term loan under which the debt assumed from Tallgrass Development was initially borrowed and, in that respect, will indirectly receive a portion of the net proceeds from this offering. Please read “Underwriting.”

 

  If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $40.4 million. The net proceeds from any exercise of such option will be distributed to Tallgrass Development.

 

  Please read “Use of Proceeds.”

 

Cash distributions

We intend to pay the minimum quarterly distribution of $0.2875 per unit ($1.15 per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement, a copy of which is included in this prospectus as Appendix A. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”

 

  We will adjust the amount of our distribution for the period from the completion of this offering through June 30, 2013, based on the actual length of that period.

 

  Our partnership agreement requires us to distribute available cash each quarter in the following manner:

 

   

first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.2875 plus any arrearages from prior quarters;

 

   

second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.2875; and

 

   

third, 98.0% to all common and subordinated unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.3048.

 

 

If cash distributions to our unitholders exceed $0.3048 per unit in any quarter, our general partner, as the holder of our IDRs, will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in

 

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excess of that amount. We refer to these distributions as “incentive distributions” because they incentivize our general partner to increase distributions to our unitholders. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

  Prior to making distributions, we will reimburse our general partner and Tallgrass Development’s general partner and its affiliates for their provision of certain general and administrative services and any additional services we may request from them (including certain incremental costs and expenses we will incur as a result of being a publicly traded partnership) pursuant to our partnership agreement and the omnibus agreement. Please read “The Partnership Agreement— Reimbursement of Expenses” and “Certain Relationships and Related Transactions—Omnibus Agreement.”

 

  Pro forma cash available for distribution generated during the year ended December 31, 2012 was approximately $54.2 million. The amount of available cash we will need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and general partner units to be outstanding upon completion of this offering will be approximately $47.5 million (or an average of approximately $11.9 million per quarter). As a result, we would have generated available cash sufficient to pay the full minimum quarterly distribution of $0.2875 per unit per quarter ($1.15 per unit on an annualized basis) on all of our common, subordinated and general partner units for the year ended December 31, 2012. Please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Adjusted Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012.”

 

  We believe that, based on the financial forecasts and related assumptions included under the caption “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve-Month Period Ending June 30, 2014,” we will have sufficient cash available for distribution to make cash distributions for the twelve-month period ending June 30, 2014, at the minimum quarterly distribution rate of $0.2875 per unit per quarter ($1.15 per unit on an annualized basis) on all common units, subordinated units and general partner units. However, we do not have a legal obligation to pay quarterly distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement. There is no guarantee that we will distribute quarterly cash distributions to our unitholders in any quarter. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

Tallgrass Development will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of

 

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available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. If we do not pay distributions on our subordinated units, our subordinated units will not accrue arrearages for those unpaid distributions.

 

Conversion of subordinated units

The subordination period will end on the first business day after June 30, 2016 on which we have earned and paid at least $1.15 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit, subordinated unit and general partner unit for each of three consecutive, non-overlapping four-quarter periods, provided that there are no arrearages on our common units at that time.

 

  Notwithstanding the foregoing, the subordination period will end on the first business day after we have earned and paid at least $1.725 (150% of the minimum quarterly distribution on an annualized basis) on each outstanding common, subordinated and general partner unit, and the related distribution on the IDRs, for any four-quarter period ending on or after June 30, 2014, provided that there are no arrearages on our common units at that time. In addition, the subordination period will end (i) with respect to 50% of the subordinated units, on the first business day after we have earned and paid at least $0.3306 (115% of the minimum quarterly distribution) on each outstanding common, subordinated and general partner unit, and the related distribution on the IDRs, for any full quarter ending on or after December 31, 2014 and (ii) with respect to 100% of the subordinated units, on the first business day after we have earned and paid at least $0.3594 (125% of the minimum quarterly distribution) on each outstanding common, subordinated and general partner unit, and the related distribution on the IDRs, for any full quarter ending on or after December 31, 2014, in each case provided that there are no arrearages on our common units at that time.

 

  The subordination period also will end with respect to a holder of subordinated units upon the removal of our general partner other than for cause if no subordinated units or common units held by such holder of subordinated units or its affiliates are voted in favor of such removal.

 

  When the subordination period ends, all subordinated units not previously converted will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions—Subordination Period.”

 

Our general partner’s right to reset the target distribution levels

Our general partner, as the initial holder of our IDRs, has the right, at any time when there are no subordinated units outstanding, if it has received incentive distributions at the highest level to which it is

 

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Index to Financial Statements
 

entitled (48.0%) for the prior four consecutive whole fiscal quarters, and the amount of the total distribution of available cash for each quarter did not exceed adjusted operating surplus for such quarter, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. If our general partner transfers all or a portion of our IDRs in the future, then the holder or holders of a majority of our IDRs will be entitled to exercise this right. The following assumes that our general partner holds all of the IDRs at the time that a reset election is made. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution as the current target distribution levels.

 

  If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units, as well as a number of general partner units necessary to maintain its general partner interest in us immediately prior to the reset election. The number of common units to be issued to our general partner will equal the number of common units that would have entitled the holder to an average aggregate quarterly cash distribution in the two quarters prior to the reset election equal to the average of the distributions to our general partner on the IDRs in such two quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our limited partners. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Partnership Interests.”

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to select our general partner or elect members of its board on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. At the completion of this offering, Tallgrass Development will own an aggregate of approximately 68% of our common and subordinated units. This will give Tallgrass Development the ability to prevent the involuntary removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all, but not less than all,

 

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of the remaining common units at a price not less than the then-current market price of the common units, as calculated in accordance with our partnership agreement.

 

Redemption of ineligible holders

The general partner at any time can request that a unitholder certify that such unitholder is an eligible taxable holder. Eligible taxable holders are:

 

   

individuals or entities subject to U.S. federal income taxation on the income generated by us; or

 

   

entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation.

 

  We will have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common units of any holder (other than affiliates of our general partner) that is not an eligible taxable holder or that has failed to certify or has falsely certified that such holder is an eligible taxable holder. The redemption price would be equal to the then-current market price of the common units, as calculated in accordance with our partnership agreement. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. In addition, the units subject to redemption will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2015, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.”

 

Material federal income tax consequences

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Federal Income Tax Consequences.”

 

Directed Unit Program

At our request, the underwriters have reserved up to 10% of the common units being offered by this prospectus for sale at the initial public offering price to the officers, directors and employees of our general partner and its affiliates and certain other persons with relationships with us and our affiliates, as designated by us. For further information regarding our directed unit program, please read “Underwriting.”

 

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New York Stock Exchange listing

We have been approved to list our common units on the New York Stock Exchange under the symbol “TEP,” subject to official notice of issuance.

Summary Historical and Pro Forma Financial and Operating Data

The following table shows summary historical financial and operating data of Tallgrass Midstream, LLC and Tallgrass Interstate Gas Transmission, LLC, which we refer to collectively as the Predecessor Entities. The combined financial statements of Tallgrass Midstream, LLC and Tallgrass Interstate Gas Transmission, LLC represent a carve-out financial statement presentation of two wholly-owned subsidiaries that were historically owned by Kinder Morgan. These entities were transferred to Tallgrass Development in connection with its acquisition of a portfolio of midstream assets from Kinder Morgan in November 2012 and will be contributed to us in connection with this offering. We refer to the Predecessor Entities as Tallgrass Energy Partners Pre-Predecessor, or TEP Pre-Predecessor, for periods prior to their acquisition by Tallgrass Development from Kinder Morgan on November 13, 2012, and as Tallgrass Energy Partners Predecessor, or TEP Predecessor, beginning on November 13, 2012. For more information, please read Note 1 to our historical audited combined financial statements included elsewhere in this prospectus.

The summary historical financial data of the Predecessor Entities presented as of and for the year ended December 31, 2011 and the period from January 1, 2012 to November 12, 2012 and the period from November 13, 2012 to December 31, 2012 are derived from the historical audited combined financial statements that are included elsewhere in this prospectus. The following table should be read together with, and is qualified in its entirety by reference to, the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The summary pro forma financial data presented as of and for the year ended December 31, 2012 was derived from the audited combined financial statements of our Predecessor included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain formation transactions to be effected at the completion of this offering had taken place at December 31, 2012, in the case of the pro forma balance sheet, and as of January 1, 2012 in the case of the pro forma statements of operations. Our unaudited pro forma financial statements give pro forma effect to the following items, among others:

 

   

contribution of assets from Tallgrass Development accounted for as transactions between entities under common control. The adjustments reflect the fair value recognized at Tallgrass Development at the time of its acquisition of the Predecessor Entities on November 13, 2012;

 

   

Tallgrass Development’s contribution of 100% of the membership interests in each of Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC to us;

 

   

our issuance of 11,250,000 common units and 16,200,000 subordinated units to Tallgrass Development, representing a 66% limited partner interest in us (62% if the underwriters exercise in full their option to purchase additional common units) and our assumption from Tallgrass Development of $400 million of indebtedness;

 

   

the issuance to our general partner of 826,531 general partner units, representing its initial 2.0% general partner interest in us, and all of our IDRs;

 

   

the issuance of 13,050,000 common units to the public in this offering, representing a 32% limited partner interest in us (36% if the underwriters exercise in full their option to purchase additional common units) and the use of the proceeds of this offering to pay expenses associated with this offering and to retire $264.4 million of the debt assumed from Tallgrass Development, as described in “Use of Proceeds,” and

 

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the closing of our new $500 million revolving credit facility under which we expect to borrow approximately $225 million at the closing of this offering, to pay origination fees related to our new revolving credit facility, to repay the remaining approximately $135.6 million of debt assumed from Tallgrass Development and to pay $85.5 million to Tallgrass Development as reimbursement for a portion of capital expenditures made by Tallgrass Development to purchase the contributed assets, which Tallgrass Development acquired together with the Retained Assets for $1.8 billion.

The pro forma combined financial data do not give effect to the estimated $2.5 million in incremental annual general and administrative expenses that we expect to incur as a result of being a publicly traded partnership. In addition, the proposed pro forma statements do not give effect to the Pony Express Abandonment which we currently expect to occur in the fourth quarter of 2013. For additional information on the Pony Express Abandonment, please see “Certain Relationships and Related Transactions—Contracts with Affiliates—Pony Express Abandonment.”

 

     TEP Pre-Predecessor          TEP Predecessor     Pro Forma  
     Year Ended
Dec 31,
2011
    Period From
Jan 1

to Nov 12,
2012
         Period From
Nov  13
to Dec 31,
2012
    Year Ended
December 31,
2012
 
                            (unaudited)  
     (in thousands, except per unit and operating data)  

Statements of Operations Data:

            

Revenues

   $ 307,043      $ 220,292          $ 35,288      $ 255,580   

Operating costs and expenses:

            

Cost of sales and transportation services

     146,069        98,585            17,711        116,296   

Operations and maintenance

     37,345        32,768            3,940        36,708   

Depreciation and amortization

     22,726        20,647            4,086        27,575   

General and administrative(1)

     16,044        11,318            7,133        18,451   

Taxes, other than income taxes

     9,360        6,861            1,107        7,968   
  

 

 

   

 

 

       

 

 

   

 

 

 

Total operating costs and expenses

     231,544        170,179            33,977        206,998   
  

 

 

   

 

 

       

 

 

   

 

 

 

Operating income

     75,499        50,113            1,311        48,582   

Other income (expense), net(2)

     203        1            482        483   

Interest income (expense), net(3)

     2,101        1,661            (3,201     (9,733
  

 

 

   

 

 

       

 

 

   

 

 

 

Income (loss) before income taxes

     77,803        51,775            (1,408     39,332   

Texas margin taxes(4)

     296        279            —           —     
  

 

 

   

 

 

       

 

 

   

 

 

 

Net Income (loss) to member/partners

   $ 77,507      $ 51,496          $ (1,408   $ 39,332   
  

 

 

   

 

 

       

 

 

   

 

 

 

Net income per limited partners’ unit:

            

Common units

             $ 0.95   

Subordinated units

             $ 0.95   

Balance Sheet Data (at period end):

            

Property, plant and equipment, net

   $ 719,009      $ 717,488          $ 669,476      $ 669,476   

Total assets

     772,896        767,683            1,035,814        1,027,640   

Long-term debt

     —          —              390,491        225,000   

Other long-term liabilities and deferred credits

     1,032        1,535            1,635        1,635   

Total members’ equity/partners’ capital

     736,808        727,479            571,834        733,351   

Cash Flow Data:

            

Net cash provided by (used in):

            

Operating activities

   $ 90,505      $ 81,335          $ 10,705     

Investing activities

     (9,960     (21,692         (12,687  

Financing activities

     (80,545     (57,661         —        

 

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     TEP Pre-Predecessor          TEP Predecessor      Pro Forma  
     Year Ended
Dec 31,
2011
     Period From
Jan 1

to Nov 12,
2012
         Period From
Nov  13
to Dec 31,
2012
     Year Ended
December 31,
2012
 
                              (unaudited)  
     (in thousands, except per unit and operating data)  

Other Financial Data: (unaudited)

              

Adjusted EBITDA(5)

     98,428         70,761            5,606         76,367   

Capital Expenditure and Operating Data

              

Capital Expenditures:

              

Maintenance capital expenditures(6)

     13,443         6,218            2,845      

Expansion capital expenditures(7)

     9,345         13,322            9,786      

Operating Data: (MMcf/d)

              

Transportation firm contracted capacity

     795         762            702      

Natural gas processing inlet volumes

     117         122            127      

 

(1) Pro forma general and administrative expenses do not give effect to annual incremental general and administrative expenses of approximately $2.5 million that we expect to incur as a result of being a publicly traded partnership.
(2) Consists of gain or loss on sale of assets and other minor items.
(3) Pro forma interest expense is related to commitment fees on, and the amortization of origination fees incurred in connection with, our new revolving credit facility, as well as interest expense on expected borrowings at the closing of this offering.
(4) Our Predecessor incurred Texas margin taxes because it was a part of an affiliated group that generated sales in the State of Texas. Upon our acquisition by Tallgrass Development in November 2012, we ceased being subject to Texas margin taxes and are not currently subject to any other entity-level income-based taxes.
(5) For a discussion of the non-GAAP financial measure Adjusted EBITDA, please read “—Non-GAAP Financial Measure” below.
(6) Maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity over the long term.
(7) Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

Non-GAAP Financial Measure

We define Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments and non-cash long-term compensation expense.

Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

 

   

our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or financing methods;

 

   

the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;

 

   

our ability to incur and service debt and fund capital expenditures; and

 

   

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA in this prospectus provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA may be defined differently by other

 

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companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Prior to November 13, 2012, TEP Pre-Predecessor elected to designate derivative instruments in the Gas Transportation and Storage segment as cash flow hedges. As a result, TEP Pre-Predecessor did not record any non-cash income or loss related to derivative instruments. Effective November 13, 2012, TEP Predecessor de-designated these cash flow hedges, resulting in the recognition of non-cash income and losses related to derivative instruments in periods beginning on November 13, 2012. There are no derivative instruments in the Processing segment for any of the periods presented.

The Predecessor Entities have not incurred any non-cash long-term compensation expense prior to the expected closing of this offering. Prior to the closing of this offering, we will adopt a long-term incentive plan that will result in the recording of non-cash long-term compensation expense that will be excluded from Adjusted EBITDA.

 

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The following table presents a reconciliation of Adjusted EBITDA to (i) net income and net cash provided by operating activities and (ii) to segment operating income, the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

     TEP Pre-Predecessor           TEP Predecessor     Pro Forma  
     Year Ended
Dec 31,
    Period From
Jan 1

to Nov 12,
          Period From
Nov 13

to Dec 31,
    Year Ended
December 31,
 
     2011     2012           2012     2012  

Reconciliation of Adjusted EBITDA to Net Income

             

Net income

   $ 77,507      $ 51,496           $ (1,408   $ 39,332   

Add:

             

Interest (income) expense, net

     (2,101     (1,661          3,201        9,733   

Depreciation and amortization expense

     22,726        20,647             4,086        27,575   

Non-cash income related to derivative instruments

                        (273     (273

Texas margin tax

     296        279                      
  

 

 

   

 

 

        

 

 

   

 

 

 

Adjusted EBITDA

   $ 98,428      $ 70,761           $ 5,606      $ 76,367   
 

Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities

             

Net cash provided by operating activities

   $ 90,505      $ 81,335           $ 10,705     

Add:

             

Interest (income) expense, net

     (2,101     (1,661          3,201     

Income taxes paid

     296        279                 

Other, including changes in operating working capital

     9,728        (9,192          (8,300  
  

 

 

   

 

 

        

 

 

   
 

Adjusted EBITDA

   $ 98,428      $ 70,761           $ 5,606     
 

Reconciliation of Adjusted EBITDA to Operating Income in the Gas Transportation and Storage Segment

             

Operating income

   $ 52,910      $ 34,563           $ (610  

Add:

             

Depreciation expense

     19,751        17,895             3,263     

Non-cash income related to derivative instruments

                        (273  

Other income (expense)

     203        1             482     
  

 

 

   

 

 

        

 

 

   
 

Segment Adjusted EBITDA

   $ 72,864      $ 52,459           $ 2,862     
 

Reconciliation of Adjusted EBITDA to Operating Income in the Processing Segment

             

Operating income

   $ 22,589      $ 15,550           $ 1,921     

Add:

             

Depreciation expense

     2,975        2,752             823     
  

 

 

   

 

 

        

 

 

   
 

Segment Adjusted EBITDA

   $ 25,564      $ 18,302           $ 2,744     

 

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RISK FACTORS

Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.

Risks Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

In order to pay the minimum quarterly distribution of $0.2875 per unit, or $1.15 per unit on an annualized basis, we will require available cash of approximately $11.9 million per quarter, or $47.5 million per year, based on the number of common, subordinated and general partner units to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

   

the level of firm transportation and storage capacity sold and the volume of natural gas we transport, store and process;

 

   

the level of production of oil and natural gas and the resultant market prices of natural gas and NGLs;

 

   

regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-user markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm transportation, storage and processing agreements;

 

   

regulatory action affecting the supply of, or demand for, natural gas, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility

 

   

changes in the fees we charge for our services;

 

   

the effect of seasonal variations in temperature on the amount of natural gas that we transport, store, process and treat;

 

   

the relationship between natural gas and NGL prices and resulting effect on processing margins;

 

   

the realized pricing impacts on revenues and expenses that are directly related to commodity prices;

 

   

the level of competition from other midstream energy companies in our geographic markets;

 

   

the creditworthiness of our customers;

 

   

the level of our operating and maintenance costs;

 

   

damages to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism;

 

   

outages at our processing facilities;

 

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leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise; and

 

   

prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

 

   

the level and timing of capital expenditures we make;

 

   

the level of our general and administrative expenses, including reimbursements to our general partner and its affiliates, including Tallgrass Development, for services provided to us;

 

   

the cost of acquisitions, if any;

 

   

our debt service requirements and other liabilities;

 

   

fluctuations in our working capital needs;

 

   

our ability to borrow funds and access capital markets;

 

   

restrictions contained in our debt agreements;

 

   

the amount of cash reserves established by our general partner; and

 

   

other business risks affecting our cash levels.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The assumptions underlying the forecast of cash available for distribution that we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve-month period ending June 30, 2014. We estimate that our total cash available for distribution for the twelve-month period ending June 30, 2014 will be approximately $56.7 million, as compared to approximately $54.2 million for the year ended December 31, 2012 on a pro forma basis. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. We expect that any significant variances between actual revenues during the forecast period and forecasted revenues will be primarily driven by differences between (i) actual and forecasted firm contracted capacity on the TIGT System, (ii) actual and forecasted processing volumes at the Midstream Facilities and (iii) actual and forecasted commodity prices. To the extent that our forecasted transportation and storage firm capacity or our forecasted processing volumes are significantly less than forecasted or the commodity price environment is less favorable than forecasted, our actual results could differ materially from those projected in our forecast. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

 

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If we are not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, our financial condition, results of operation, cash flows and ability to make cash distributions to our unitholders will be adversely affected. We have experienced decreases in revenues as compared to historical periods resulting from decreased renewals of long-haul firm capacity contracts with off-system customers over the last few years. If this trend continues, our ability to make cash distributions to our unitholders may be materially impacted.

We transport, store and process a substantial majority of the natural gas on our systems under long-term contracts with terms of various durations. For the year ended December 31, 2012, approximately 81% of our transportation and storage revenues were generated under firm transportation and storage contracts. Our firm transportation and storage contracts have a weighted average maturity of approximately four years and two years, respectively as of December 31, 2012. As of December 31, 2012, the weighted-average duration of our processing contracts was over four years. As these contracts expire, we may be unable to obtain new contracts on terms similar to those of our existing contracts, or at all. If we are unable to promptly resell capacity from expiring contracts on equivalent terms, our revenues may decrease and our ability to make cash distributions to our unitholders may be materially impaired.

For example, over the past several years, a number of our transportation and storage customers have opted not to renew their contracts for service on the TIGT System. We believe those non-renewals have been caused both by increased competition from large diameter long-haul pipeline systems that are more efficient and cost effective at transporting natural gas over long distances as well as reduced drilling activity for dry gas in the Rocky Mountain region. These former customers are generally large producers that primarily used the TIGT System to access interstate pipelines for ultimate delivery to consuming markets outside our areas of operations, as opposed to our current customer base, which is primarily comprised of on-system regional customers, such as LDCs. The non-renewal of these transportation contracts has resulted in decreases in firm contracted capacity on the TIGT System and related decreases in total revenue. For example, our average firm contracted capacity decreased from 842 MMcf/d for the year ended December 31, 2010 to 754 MMcf/d for the year ended December 31, 2012 and transportation services revenue decreased from $142.4 million to $106.3 million over the same period, primarily due to the loss of revenue from the non-renewal of transportation contracts. For more information, please read “Selected Historical and Pro Forma Financial and Operation Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

We also may be unable to maintain the long-term nature and economic structure of our current contract portfolio over time. Depending on prevailing market conditions at the time of a contract renewal, transportation, storage and processing customers with fee-based contracts may desire to enter into contracts under different fee arrangements, and our potential customers may be generally unwilling to enter into long-term contracts. To the extent we are unable to renew or replace our existing contracts on terms that are favorable to us or successfully manage the long-term nature and economic structure of our contract mix over time, our revenues and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected. In addition, if an existing customer terminates or breaches its long-term firm transportation, storage or processing contract, we may be subject to a loss of revenue if we are unable to promptly resell the capacity to another customer on substantially equivalent terms.

Our ability to renew or replace our expiring contracts on terms similar to, or more attractive than, those of our existing contracts is uncertain and depends on a number of factors beyond our control, including:

 

   

the level of existing and new competition to provide transportation, storage and processing services to our markets;

 

   

the macroeconomic factors affecting natural gas gathering economics for our current and potential customers;

 

   

the balance of supply and demand for natural gas, on a short-term, seasonal and long-term basis, in the markets we serve;

 

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the extent to which the customers in our markets are willing to contract on a long-term basis; and

 

   

the effects of federal, state or local regulations on the contracting practices of our customers.

Furthermore, we do not have firm contracts in place for the additional capacity associated with the expansion of our Casper and Douglas processing plants, which is scheduled to be completed in the second half of 2013. If we are not able to enter into processing contracts at favorable rates or on a long term basis with respect to this expanded capacity or otherwise utilize the capacity, our financial condition, results of operation, cash flows and ability to make cash distributions to our unitholders will be adversely affected.

Increased competition from other companies that provide natural gas transportation, storage and processing services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could materially and adversely affect our financial results.

Our ability to renew or replace our existing contracts at rates sufficient to maintain current revenues and current cash flows could be adversely affected by the activities of our competitors. Some of our competitors have greater financial, managerial and other resources than we do and control substantially more transportation, storage and processing capacity than we do. In addition, some of our competitors have assets in closer proximity to natural gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. For example, several pipelines access many of the same basins as the TIGT System and transport gas to customers in the Rocky Mountain and Midwest regions of the United States. Our competitors may expand or construct new transportation, storage or processing systems that would create additional competition for the services we provide to our customers, or our customers may develop their own transportation, storage and processing facilities in lieu of using ours. The potential for the construction of new processing facilities in our areas of operation is particularly acute due to the unregulated nature of the processing industry. Furthermore, Tallgrass Development and its affiliates are not limited in their ability to compete with us. Please read “Conflicts of Interest and Duties.”

If our competitors were to substantially decrease the prices at which they offer their services, we may be unable to compete effectively and our cash flows and ability to make distributions to our unitholders may be materially impaired.

Further, natural gas as a fuel competes with other forms of energy available to users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for our services.

All of these competitive pressures could make it more difficult for us to renew our existing long-term, firm transportation, storage and processing contracts when they expire or to attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets we serve, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

If we are unable to make acquisitions on economically acceptable terms from Tallgrass Development or third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including Tallgrass Development. Other than Tallgrass Development’s obligation to offer us certain assets, including the Retained Assets, pursuant to the right of first offer under the omnibus agreement, we have no contractual arrangement with

 

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Tallgrass Development that would require it to provide us with an opportunity to offer to acquire midstream assets that it may sell. Accordingly, while we note elsewhere in this prospectus that we believe Tallgrass Development will be incentivized pursuant to its economic relationship with us to offer us opportunities to purchase midstream assets, there can be no assurance that any such offer will be made, and there can be no assurance we will reach agreement on the terms with respect to the Retained Assets or any other acquisition opportunities offered to us by Tallgrass Development. Furthermore, many factors could impair our access to future midstream assets, including a change in control of Tallgrass Development or a transfer of the IDRs by our general partner to a third party. A material decrease in divestitures of midstream energy assets from Tallgrass Development or otherwise would limit our opportunities for future acquisitions and could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

If we are unable to make accretive acquisitions from Tallgrass Development or third parties, whether because, among other reasons, (i) Tallgrass Development elects not to sell or contribute additional assets to us or to offer acquisition opportunities to us, (ii) we are unable to identify attractive third-party acquisition opportunities, (iii) we are unable to negotiate acceptable purchase contracts with Tallgrass Development or third parties, (iv) we are unable to obtain financing for these acquisitions on economically acceptable terms, (v) we are outbid by competitors or (vi) we are unable to obtain necessary governmental or third-party consents, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

Any acquisition involves potential risks, including, among other things:

 

   

mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;

 

   

an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities;

 

   

an inability to integrate successfully the assets or businesses we acquire;

 

   

the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

 

   

the diversion of management’s and employees’ attention from other business concerns;

 

   

unforeseen difficulties operating in new geographic areas or business lines; and

 

   

a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to finance an acquisition.

If any acquisition eventually proves not to be accretive to our distributable cash flow per unit, it could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase.

In order to expand our asset base through acquisitions or capital projects, we may need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We will be required to use cash from our operations or incur borrowings or sell additional common units or other limited partner interests in order to fund our expansion capital expenditures. Using cash from operations will reduce cash available for distribution to our common unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial

 

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condition at the time of any such financing or offering as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

We do not have any commitment with our general partner or other affiliates, including Tallgrass Development, to provide any direct or indirect financial assistance to us following the closing of this offering.

We are exposed to direct commodity price risk with respect to the majority of our processing revenues, and our exposure to direct commodity price risk may increase in the future.

Our processing segment operates under two types of contractual arrangements that expose our cash flows to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds and keep-whole arrangements. As of December 31, 2012, approximately two-thirds of the reserved capacity in our processing segment was contracted under percent of proceeds or keep whole arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers and retain from the sale an agreed percentage of pipeline-quality gas and NGLs resulting from our processing activities at market prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under keep-whole arrangements, we are required to replace a contractually specified percentage of the Btu content of the inlet wet gas that we process with a combination of NGLs that we produce and dry natural gas, some of which we must purchase at market prices. Under these types of arrangements our revenues and our cash flows increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGLs prices, it is more profitable for us to process natural gas under keep-whole arrangements. When natural gas prices are high relative to NGLs prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed at some of our plants. In addition, NGL prices have historically been correlated to the market price of oil and as a result any significant changes in oil prices could also indirectly impact our operations. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Contract Mix and Volumes—Processing.” NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. We do not currently hedge the commodity exposure in our processing contracts and, as a result, our revenues, financial condition and results of operations could be adversely impacted by fluctuations in the prices of natural gas and NGLs. As a result of our commodity price exposure, significant prolonged changes in natural gas and NGL prices could have a material adverse effect on our financial condition, results of operations and our ability to make cash distributions to our unitholders.

If third-party pipelines or other midstream facilities interconnected to our systems become partially or fully unavailable, or if the volumes we transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and our ability to make distributions to our unitholders could be adversely affected.

Our natural gas transportation, storage and processing facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as Phillips 66 Company and others. For example, a substantial majority of the NGLs we process are transported on the Powder River pipeline owned by Phillips 66 Company, and therefore, any downtime on this pipeline as a result of maintenance or force majeure would adversely affect us. The continuing operation of such third-party pipelines, processing plants and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity,

 

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regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from weather events or other operational hazards. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes we transport or process do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and our ability to make quarterly cash distributions to our unitholders could be adversely affected.

Our ability to abandon and sell the Pony Express Assets to Tallgrass Development in connection with the Pony Express Abandonment is subject to the timing and receipt of governmental approvals.

The abandonment and sale of the Pony Express Assets to Tallgrass Development in connection with the Pony Express Abandonment requires approval from the FERC, which is uncertain and beyond our control. Although our business strategy includes the abandonment and sale of the Pony Express Assets, we may not be able to obtain all required governmental approvals for such abandonment within our currently anticipated schedule or at all, which could result in sustained under-utilization of the Pony Express Assets and a failure to capture anticipated improvements in the cost of operations on the TIGT System. We have also forecasted a reduction in interest expense during the twelve-month period ending June 30, 2014 of $2.3 million as a result of using the anticipated proceeds from our initial sale of the Pony Express Assets to reduce outstanding borrowings under our new revolving credit facility, which would not be realized if we are unable to consummate the Pony Express Abandonment. In addition, the failure to abandon and transfer the Pony Express Assets to Tallgrass Development would prevent Tallgrass Development from developing these assets into an oil pipeline, and would eliminate the possibility of us acquiring the Pony Express Project from Tallgrass Development in the future.

Our operations are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, and results of operations.

Our transportation and storage operations are regulated by the FERC, under the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EP Act 2005. The TIGT System operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms and terms and conditions of service to our customers. Generally, the FERC’s authority extends to:

 

   

rates, operating terms and conditions of service;

 

   

the form of tariffs governing service;

 

   

the types of services we may offer to our customers;

 

   

the certification and construction of new, or the expansion of existing, facilities;

 

   

the acquisition, extension, disposition or abandonment of facilities;

 

   

creditworthiness and credit support requirements;

 

   

the maintenance of accounts and records;

 

   

relationships among affiliated companies involved in certain aspects of the natural gas business;

 

   

depreciation and amortization policies; and

 

   

the initiation and discontinuation of services.

Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust and unreasonable or unduly discriminatory. The maximum recourse rate that we may charge for our transportation and storage services is established through the FERC’s ratemaking process. The maximum applicable recourse rate and terms and conditions for service are set forth in our FERC-approved tariff.

 

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Pursuant to the NGA, existing interstate transportation and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) “recourse rates” (i.e., the maximum cost-based rates an interstate pipeline may charge for its services under its tariff); (ii) “discount rates” which are offered by the pipeline to shippers within the cost-based maximum and minimum rate levels in effect from time to time; and (iii) “negotiated rates” which are fixed between the pipeline and the shipper for the contract term and do not vary with changes in the level of cost-based “recourse rates,” provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. When capacity is available and offered for sale at other than negotiated rates, the rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) are pursuant to those rates provided in our tariff, which is subject to regulatory approval and oversight. In those circumstances, regulators and customers on the TIGT System would have the right to protest or otherwise challenge the rates that we charge under a process prescribed by applicable regulations. The FERC may also initiate reviews of our rates. We may also engage in more general disputes with customers on our pipeline system regarding terms and conditions of our agreements, as well as proper interpretation and application of our tariff, among other things. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition and results of operations.

Our gas compressor fuel costs and the cost of lost and unaccounted for gas, together referred to as Fuel Retention Factors, are recovered by retaining a fixed percentage of natural gas throughput on our transportation and storage facilities. These Fuel Retention Factors were the subject of a Section 5 proceeding initiated by the FERC that we resolved with customers by a settlement approved by the FERC in September 2011. See “Business—Regulatory Environment—Federal Energy Regulatory Commission—2011 Section 5 Fuel Settlement.”

The FERC’s jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to, acquisitions, facility maintenance, expansions, and abandonment of facilities and services. Prior to commencing construction of significant new or existing interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or file to amend its existing certificate, from the FERC. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any refusal by an agency to issue authorizations or permits for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Such refusal or modification could materially and negatively impact the additional revenues expected from these projects.

FERC conducts audits to verify that the websites of interstate pipelines accurately provide information on the operations and availability of services on the pipeline. FERC regulations also require uniform terms and conditions for service, as set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the standard form of service agreements set forth in the pipeline’s FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.

The FERC has promulgated rules and policies covering many aspects of our business, including regulations that require us to provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers, provide internet access to current information about our available pipeline capacity and other relevant information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. FERC regulations also restrict interstate

 

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natural gas pipelines from sharing transportation or customer information with marketing affiliates and require that interstate natural gas pipelines function independently of their marketing affiliates. As Tallgrass Midstream, LLC’s operations are currently structured, Tallgrass Midstream, LLC engages in non-exempt sales for resale of natural gas in interstate commerce for which it uses transportation capacity on the TIGT System.

The FERC may not continue to pursue its approach of pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Failure to comply with applicable provisions of the NGA, the NGPA, the EP Act of 2005 and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to $1,000,000 per day, per violation.

In addition, new laws or regulations or different interpretations of existing laws or regulations applicable to our pipeline system could have a material adverse effect on our business, financial condition, results of operations and prospects. We may face challenges to our rates or terms of service in the future. Any successful challenge could materially adversely affect our future earnings and cash flows.

If the tariff governing the services we provide is successfully challenged, we could be required to reduce our tariff rates, which could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

Any of our shippers, the FERC, or other interested stakeholders, such as state regulatory agencies, may challenge the maximum recourse rates or the terms and conditions of service included in our tariff. We do not have an agreement in place that would prohibit these parties from challenging our tariff. If any challenge were successful, among other things, the rates that we charge on our systems could be reduced. For example, we were subject to a Section 5 proceeding initiated by our shippers relating to our Fuel Retention Factors, which generally are recovered by retaining a fixed percentage of natural gas throughput on our transportation and storage facilities. We resolved these issues with customers by a settlement approved by the FERC in September 2011, which resulted in a 27% reduction in the Fuel Retention Factors billed to shippers effective June 1, 2011, causing a decrease in transportation and storage revenue. The Section 5 Settlement also provided for a second stepped reduction, resulting in a total 30% reduction in the Fuel Retention Factors billed to shippers and effective January 1, 2012, for certain segments of the former Pony Express pipeline system. See “Description of Business—Regulatory Matters—Federal Energy Regulatory Commission—2011 Section 5 Fuel Settlement.” Successful challenges could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial and operating results.

Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, our long-term firm transportation and storage contracts obligate our customers to pay demand charges regardless of whether they transport or store natural gas on our facilities, except when we are unable to schedule the customer’s nomination for service due to capacity constraints caused by maintenance or a force majeure event lasting more than 10 days. As a result, during the term of our long-term firm transportation and storage contracts and absent an event of force majeure, our revenues will generally depend on our customers’ financial condition and their ability to pay rather than upon the amount of natural gas transported. Further, our contract counterparties may not perform or adhere to our existing or future contractual arrangements. Any material nonpayment or nonperformance by our

 

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contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

The procedures and policies we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our procedures and policies prove to be inadequate, our financial and operational results may be negatively impacted.

Some of our counterparties may be highly leveraged or have limited financial resources and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices might have an impact on many of our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us and may also increase the magnitude of these obligations.

Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.

Any significant decrease in available supplies of natural gas in our areas of operation, or redirection of existing natural gas supplies to other markets, could adversely affect our business and operating results.

Our business is dependent on the continued availability of natural gas production and reserves. Production from existing wells and natural gas supply basins with access to our transportation, storage and processing facilities will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, stored and treated on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas.

However, the development of additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, storage, transportation and other facilities that permit natural gas to be produced and delivered to our transportation, storage and processing facilities. In addition, low prices for natural gas, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could have a material adverse effect on the development and production of additional reserves, as well as storage, pipeline transportation, and import and export of natural gas supplies. Furthermore, competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply available for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported on our systems and cash flows associated with our operations, our customers must compete with others to obtain adequate supplies of natural gas.

If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, if natural gas supplies are diverted to serve other markets, or if environmental regulators restrict new natural gas drilling, the overall demand for transportation, storage and processing services on our systems would decline, which could have a material adverse effect on our ability to renew or replace our current customer contracts when they expire and on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

 

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Constructing new assets subjects us to risks of project delays, cost overruns and lower-than-anticipated volumes of natural gas once a project is completed. Our operating cash flows from our capital projects may not be immediate or meet our expectations.

One of the ways we may grow our business is by constructing additions or modifications to our existing facilities. We also may construct new facilities, either near our existing operations or in new areas. For example, we are currently undergoing an expansion of our Casper and Douglas plants to increase processing capacity and upgrade compression. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of which are beyond our control. These projects also involve numerous economic uncertainties, including the impact of inflation on project costs and the availability of required resources. For example, we currently are party to a lawsuit in Fremont County, Wyoming arising out of the construction of the West Frenchie Draw amine treating plant. For more information, please read “Business—Legal Proceedings.”

We may be unable to complete construction projects on schedule, at the budgeted cost, or at all, which could have a material adverse effect on our business and results of operations. Moreover, we may not receive any material increase in operating cash flow from a project for some time. For instance, if we expand a pipeline or processing facility, the construction expenditures may occur over an extended period of time, yet we will not receive any material increases in cash flow until the project is completed and fully operational. In addition, our cash flow from a project may be delayed or may not meet our expectations. Our project specifications and expectations regarding project cost, timing, asset performance, investment returns and other matters usually rely in part on the expertise of third parties such as engineers, technical experts and construction contractors. These estimates may prove to be inaccurate because of numerous operational, technological, economic and other uncertainties.

We rely in part on estimates from producers regarding of the timing and volume of anticipated natural gas production. Production estimates are subject to numerous uncertainties, all of which are beyond our control. These estimates may prove to be inaccurate, and new facilities may not attract sufficient volumes to achieve our expected cash flow and investment return.

Our success depends on the supply and demand for natural gas.

The success of our business is in many ways impacted by the supply and demand for natural gas. For example, our business can be negatively impacted by sustained downturns in supply and demand for natural gas in the markets that we serve, including reductions in our ability to renew contracts on favorable terms and to construct new infrastructure. One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. One of the major factors impacting natural gas supplies has been the significant growth in unconventional sources such as shale plays. The supply and demand for natural gas and therefore the future rate of growth of our business will depend on these and many other factors outside of our control, including, but not limited to:

 

   

adverse changes in general global economic conditions;

 

   

adverse changes in domestic regulations;

 

   

technological advancements that may drive further increases in production and reduction in costs of developing natural gas shales;

 

   

the price and availability of other forms of energy;

 

   

prices for natural gas;

 

   

increased costs to explore for, develop, produce, gather, process and transport natural gas;

 

   

weather conditions, seasonal trends and hurricane disruptions;

 

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the nature and extent of, and changes in, governmental regulation, for example greenhouse gas legislation and taxation; and

 

   

perceptions of customers on the availability and price volatility of our services and natural gas prices, particularly customers’ perceptions on the volatility of natural gas prices over the longer-term.

We are subject to numerous hazards and operational risks.

Our operations are subject to all the risks and hazards typically associated with the transportation, storage and processing of natural gas. These operating risks include, but are not limited to:

 

   

damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires or other adverse weather conditions and other natural disasters and acts of terrorism;

 

   

inadvertent damage from construction, vehicles, farm and utility equipment;

 

   

uncontrolled releases of natural gas and other hydrocarbons. For example, on May 4, 2013, we experienced a release of gas from a segment of pipeline in Kimball County, Nebraska resulting in damage to a small section of the TIGT pipeline that will need to be replaced;

 

   

leaks, migrations or losses of natural gas as a result of the malfunction of equipment or facilities;

 

   

outages at our processing facilities;

 

   

ruptures, fires and explosions; and

 

   

other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain segments of our pipeline system in or near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, could increase the level of damages resulting from these risks. Despite the precautions we have taken, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with existing services. We could be required by regulatory authorities to test or undertake modifications to our systems, operations or both that could result in a material adverse impact on our business, financial condition and results of operations. Such circumstances could also materially and adversely impact our ability to meet contractual obligations and retain customers, with a resulting material adverse impact on our business and results of operations and our ability to make quarterly cash distributions to our unitholders. Some or all of our costs arising from these operational risks may not be recoverable under insurance, contractual indemnification or increases in rates charged to our customers.

Tallgrass Development will have limited indemnity obligations to us for liabilities arising out of the ownership and operation of our assets prior to the closing of this offering.

Upon the closing of this offering, we will enter into an omnibus agreement (the “Omnibus Agreement”) with Tallgrass Development, its general partner and our general partner that will govern, among other things, Tallgrass Development’s obligation to indemnify us for certain liabilities associated with the entities and assets being contributed to us in connection with this offering. Under the Omnibus Agreement, Tallgrass Development will be required (i) to indemnify us and our subsidiaries for any federal, state and local income tax liabilities

 

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attributable to the ownership and operation of our assets and the assets of our subsidiaries prior to the closing of this offering until 60 days after the applicable statute of limitations, (ii) to reimburse us and our subsidiaries for any amounts paid by us or our subsidiaries pursuant to any settlement agreement or judgment related to or resulting from the proceeding pending in state court in Douglas County, Nebraska, entitled Cornhusker Energy Lexington, LLC and National Union Fire Insurance Company of Pittsburgh, Pennsylvania vs. Kinder Morgan Interstate Gas Transmission, now known as Tallgrass Interstate Gas Transmission, which we refer to as the Cornhusker Claim, that exceeds $3.9 million, in the amount by which such settlement or damage award actually exceeds $3.9 million and (iii) to use commercially reasonable efforts to obtain indemnification from Kinder Morgan for losses suffered or incurred by us with respect to the assets being contributed to us in connection with this offering to the extent that Kinder Morgan is obligated to indemnify Tallgrass Development for such losses under the purchase and sale agreement (the “Kinder Morgan Purchase Agreement”) pursuant to which Tallgrass Development acquired the assets being contributed to us in connection with this offering and to remit any proceeds received from Kinder Morgan pursuant to such indemnification obligations to us. Accordingly, other than with respect to pre-closing income tax liabilities or a settlement agreement or judgment amount related to the Cornhusker Claim to the extent such amount exceeds $3.9 million, Tallgrass Development will be required to indemnify us for liabilities arising out of the ownership and operation of our assets prior to the closing of this offering only to the extent that Tallgrass Development is entitled to, and is successful in obtaining, indemnification for such losses from Kinder Morgan. The indemnities that Kinder Morgan has agreed to provide to Tallgrass Development under the Kinder Morgan Purchase Agreement, and consequently our ability to obtain recourse from Tallgrass Development, may be inadequate to fully compensate us for losses we may suffer or incur as a result of liabilities arising out of the ownership and operation of our assets prior to the closing of this offering, which such losses may include, among other things, environmental remediation liabilities relating to conditions existing prior to the closing of this offering and any losses we may incur as a result of the legal proceedings described under “Business—Legal Proceedings.” There is no guarantee that Kinder Morgan will provide indemnification to Tallgrass Development for any losses for which Tallgrass Development might make indemnity claims under the Kinder Morgan Purchase Agreement in a timely fashion, or at all. The occurrence of any losses that are neither indemnified for under the Omnibus Agreement nor covered under our insurance plans could have a material adverse effect on our business, financial condition, results of operations and cash flows. Please read, “—Our insurance coverage may not be adequate.”

Our insurance coverage may not be adequate.

We are not fully insured against all risks inherent to our business, including environmental accidents that might occur. For example, we do not maintain business interruption insurance in the type and amount to cover all possible risks of loss. In addition, we do not carry insurance for certain environmental exposures, including but not limited to potential environmental fines and penalties, business interruption, named windstorm or hurricane exposures and, in limited circumstances, certain political risk exposures. Further, in the event there is a total or partial loss of our pipeline system and/or processing facilities, any insurance proceeds that we may receive in respect thereof may not be sufficient in any particular situation to effect a restoration of our pipeline system and/or processing facilities to the condition that existed prior to such loss. In addition, we do not have insurance coverage on the two legal proceedings described in “Business—Legal Proceedings.” The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates, and we may elect to self insure a portion of our asset portfolio. As a result of market conditions, premiums and deductibles for certain types of insurance policies may substantially increase, and in some instances, certain types of insurance could become unavailable or available only for reduced amounts of coverage. Accordingly, any insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses.

 

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Our pipeline integrity program may impose significant costs and liabilities on us, while increased regulatory requirements relating to the integrity of our pipeline system may require us to make additional capital and operating expenditures to comply with such requirements.

We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal requirements set by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration, or PHMSA, for pipeline companies in the areas of pipeline design, construction, and testing, the qualification of personnel and the development of operations and emergency response plans. The rules require pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as High Consequence Areas, or HCAs.

Our interstate pipeline operations are subject to pipeline safety regulations administered by PHMSA. These regulations, among other things, include requirements to monitor and maintain the integrity of our pipeline system and determine the pressures at which our pipeline system can operate. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the Pipeline Safety Act of 2011, enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002, or the Pipeline Safety Act of 2002, in a number of significant ways, including:

 

   

reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines;

 

   

requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities;

 

   

requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days; and

 

   

requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those requirements to areas outside of HCAs.

PHMSA published an advanced notice of proposed rulemaking in August 2011 to solicit comments on the need for changes to its safety regulations, including whether to revise integrity management requirements. On August 13, 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties from $100,000 to $200,000 per violation per day of violation and from $1,000,000 to $2,000,000 as a maximum amount for a related series of violations as well as changing PHMSA’s enforcement process.

The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of the costs to comply with the rules are associated with pipeline integrity testing and the repairs found to be necessary. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs can have a significant impact on the costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. For example, PHMSA issued an Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the maximum allowable operating pressure for each section of their pipeline and that the records must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of verifiable pressures, could significantly increase our costs. Additionally, failure to locate such

 

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records or verify maximum pressures could require us to operate at reduced pressures, which would reduce available capacity on our pipeline system. There can be no assurance as to the amount or timing of future expenditures required to comply with pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial position, results of operations and prospects.

In addition, we may be subject to enforcement actions and penalties for failure to comply with pipeline regulations. On August 29, 2012, PHMSA notified Tallgrass Interstate Gas Transmission, LLC that a report from an audit conducted in 2010 indicated a probable violation for failing to perform a periodic review of personnel responses to certain abnormal operations. Specifically, PHMSA cited to the operation of a relief valve on March 3, 2010. If we are not able to successfully defend this alleged violation, Tallgrass Interstate Gas Transmission, LLC may be required to change its operating procedures, which could increase operating costs. Tallgrass Interstate Gas Transmission, LLC responded to the notice of probable violation and requested a hearing in a response filed with PHMSA on October 1, 2012. A hearing was held on January 15, 2013. The matter is ongoing.

Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for us.

Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases, or GHGs. Various laws and regulations exist, or are under development that seek to regulate the emission of such GHGs, including United States Environmental Protection Agency, or the EPA, programs to control GHG emissions and state actions to develop statewide or regional programs. In recent years, the U.S. Congress has considered, but not adopted, legislation to reduce emissions of GHGs.

The EPA published in December 2009 its findings that emissions of GHGs present an endangerment to human health and the environment. Pursuant to this endangerment finding and other rulemakings and interpretations, the EPA concluded that stationary sources would become subject to federal permitting requirements under the Clean Air Act, or the CAA, starting in 2011. In 2010, the EPA issued a final rule, known as the “Tailoring Rule,” that defines regulatory emission thresholds at which certain new and modified stationary sources are subject to permitting and other requirements for GHG emissions under the CAA’s Prevention of Significant Deterioration, or PSD, and Title V programs. The EPA has indicated in rulemakings that it may reduce the current regulatory thresholds for GHGs, making additional sources subject to PSD permitting requirements. However, in July 2012, the EPA declined to lower the applicability thresholds to allow the GHG regulations to apply to additional, smaller sources. The EPA’s determination was to allow states additional time to implement existing GHG regulations, as opposed to an EPA determination that regulation was unnecessary. As such, the EPA may still lower the threshold for GHG permitting in the future, which may affect our facilities. Some of our facilities emit GHGs in excess of the currently-applicable Tailoring Rule thresholds and have been required to obtain a Title V Permit that reflects this potential to emit GHGs. Although these existing facilities are not currently required to obtain a PSD permit containing enforceable limits on GHG emissions, any future modifications with a potential to emit GHGs above the applicable regulatory thresholds at the time of the application would require us to obtain a PSD permit containing enforceable limits on GHG emissions.

Additional direct regulation of GHG emissions in our industry may be implemented under other CAA programs, including the New Source Performance Standards, or NSPS, program. The EPA has already proposed to regulate GHG emissions from certain electric generating units under the NSPS program. While these proposed regulations for electric generating units would not apply to our operations, the EPA may propose to regulate additional sources under the NSPS program. In addition, in 2009, the EPA published a final rule requiring that specified large GHG emissions sources annually report the GHG emissions for the preceding year in the United States, beginning in 2011 for emissions occurring in 2010. In 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transportation compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year.

 

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The rule, which went into effect in December 2010, requires reporting of GHG emissions by regulated facilities to the EPA on an annual basis. Reporting was first required in 2012 for emissions during 2011. Some of our facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting requirements.

At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. Many of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. Depending on the particular program, we could be required to purchase and surrender emission allowances.

Because our operations, including our compressor stations and processing facilities, emit various types of GHGs, primarily methane and carbon dioxide, new legislation or regulation could increase our costs related to operating and maintaining our facilities, and could delay future permitting. Depending on the particular new law, regulation or program adopted, we could be required to incur capital expenditures for installation of new emission controls on our compressor stations and processing facilities, acquire and surrender allowances for our GHG emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program. We are not able at this time to estimate such increased costs; however, they could be significant. While we may be able to include some or all of such increased costs in the rates charged by our pipeline system, such recovery of costs is uncertain in all cases and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations. Similarly, while we may be able to recover some or all of such increased costs in the rates charged by our processing facilities, such recovery of costs is uncertain and may depend on the terms of our contracts with our customers. Any of the foregoing could have a material adverse effect on our business, financial position, results of operations and prospects. To the extent financial markets view climate change and greenhouse gas emissions as a financial risk, this could materially and adversely impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change, or incentives to conserve energy or use alternative energy sources, could also affect the markets for our services by making natural gas products less desirable than competing sources of energy.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures that could exceed our current expectations.

Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in natural gas transportation, storage and processing operations, and as a result, we may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state, and local laws and regulations governing health and safety aspects of our operations, environmental protection, including the discharge of materials into the environment, and the security of chemical and industrial facilities. These laws include, but are not limited to, the following:

 

   

CAA and analogous state laws, which impose obligations related to air emissions;

 

   

Clean Water Act, or CWA, and analogous state laws, which regulate discharge of pollutants contained in wastewater and storm water from our facilities to state and federal waters, including wetlands;

 

   

Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;

 

   

Resource Conservation and Recovery Act, or RCRA, and analogous state laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from our facilities;

 

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Occupational Safety and Health Act, or OSHA, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;

 

   

The National Environmental Policy Act, or NEPA, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;

 

   

The Migratory Bird Treaty Act, which implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;

 

   

Endangered Species Act, or ESA, and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and

 

   

Oil Pollution Act of 1990, or OPA, and analogous laws, which imposes liability for discharges of oil into waters of the United States and requires facilities which could be reasonably expected to discharge oil into waters of the United States to maintain and implement appropriate spill contingency plans.

Various governmental authorities, including the EPA, the U.S. Department of the Interior, the U.S. Department of Homeland Security, and analogous state and local agencies have the power to enforce compliance with these laws and regulations and the permits and related plans issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, permits, plans and agreements may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays in granting permits.

There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products we transport and store, air emissions related to our operations, historical industry operations, and waste disposal practices, and the prior use of flow meters and manometers containing mercury. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including but not limited to CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas and wastes on, under, or from our properties and facilities. We are currently conducting remediation at several sites to address contamination. For 2013, we have budgeted approximately $372,000 for these ongoing environmental remediation projects. Private parties, including but not limited to the owners of properties through which our pipeline system passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws, regulations and permits issued thereunder, or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours that could result in remedial action. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance does not cover all environmental risks and costs and may not provide sufficient coverage if an environmental claim is made against us.

In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which included the addition of “Energy Extraction Activities” to its enforcement priorities list. To address its concerns regarding the pollution risks raised by new techniques for oil and gas extraction and coal mining, the EPA is developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements and increasing its inspection and evaluation frequency. On January 28, 2013, the EPA issued a notice seeking comment on whether to extend the current National Enforcement Initiatives, including the initiative related to

 

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Energy Extraction Activities, for the next three years. We cannot predict what the results of the current initiative or any future initiative will be, or whether federal, state or local laws or regulations will be enacted in this area. If new regulations are imposed related to oil and gas extraction, the volumes of natural gas that we transport and/or process could decline and our results of operations could be materially adversely affected.

Our business may be materially and adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits or plans developed thereunder. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations, or may have to implement contingencies or conditions in order to obtain such approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.

We are also generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

We have agreed to a number of conditions in our environmental permits and associated plans, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where we currently operate, and would operate if our facilities are extended or expanded, or if we construct new facilities, and we are unable to predict the effect that any such measures would have on our business, financial position, results of operations or prospects.

Further, such existing laws and regulations may be revised or new laws or regulations may be adopted or become applicable to us. In addition to potential GHG regulations, there may also be potential regulations under the NSPS and/or the maximum available control technology standard that may affect us. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be materially different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

Increased regulation of hydraulic fracturing and other natural gas processing operations could affect our operations and result in reductions or delays in natural gas production by our customers, which could have a material adverse impact on our revenues.

A portion of our customers’ natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into shale formations to stimulate gas production. Hydraulic fracturing is currently exempt from federal regulation pursuant to the federal Safe Drinking Water Act, or the SDWA (except when the fracturing fluids or propping agents contain diesel fuels), because hydraulic fracturing is excluded from the SDWA definition of “underground injection” and therefore is not subject to permitting and federal regulatory control pursuant to SDWA. However, public concerns have been raised related to its potential environmental impact. Additional federal, state and local laws and regulations to more closely regulate hydraulic fracturing have been considered and, in some cases, adopted and implemented. For example,

 

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from time to time, legislation to further regulate hydraulic fracturing has been proposed in Congress, including repeal of the SDWA exemption for hydraulic fracturing, as well as to require disclosure for chemicals used in hydraulic fracturing. An EPA investigation requested by a committee of the House of Representatives to assess the potential environmental effects of hydraulic fracturing on drinking water and groundwater is underway, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Reports prepared by the U.S. Department of Energy’s Shale Gas Subcommittee could also lead to further restrictions on hydraulic fracturing. In addition, in October 2011, EPA announced its intention to propose regulations by 2014 under the CWA regarding wastewater discharges from hydraulic fracturing and other gas production and, in November 2011, EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act, or the TSCA, to require companies to disclose information regarding the chemicals used in hydraulic fracturing.

Apart from federal legislation and EPA regulations, other federal agencies and states have proposed or adopted legislation or regulations restricting hydraulic fracturing. On May 4, 2012, the U.S. Department of Interior issued a draft proposed rule requiring the disclosure of chemicals used during hydraulic fracturing, as well as drilling plans, water management, and wastewater disposal, on federal and Indian lands but, more recently, on January 18, 2013 a spokesperson for the Department of Interior announced plans to issue a new draft rule in 2013. Moreover, some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including additional permit requirements, operational restrictions, chemical disclosure obligations and temporary or permanent bans on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. For example, Wyoming has imposed regulations regarding disclosure of information regarding chemicals in well stimulation operations. We cannot predict whether any additional federal, state or local laws or regulations will be enacted in this area and if so, what their provisions would be. If additional levels of reporting, regulation or permitting moratoria were required or imposed related to hydraulic fracturing, the volumes of natural gas that we transport could decline and our results of operations could be materially and adversely affected.

In addition, new EPA rules that became effective on October 15, 2012 establish new air emission controls for oil and natural gas production, pipelines and processing operations. For new or reworked hydraulically-fractured gas wells, the rules require the control of emissions through flaring or reduced emission (or “green”) completions until 2015, when the rules require the use of green completions by all such wells except wildcat (exploratory) and delineation gas wells and low reservoir pressure non-wildcat and non-delineation gas wells. The rules also establish specific new requirements regarding emissions from wet seal and reciprocating compressors at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2012, and from pneumatic controllers and storage vessels at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2013. In addition, the rules revise existing requirements for volatile organic compound emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million and requiring the monitoring of connectors, pumps, pressure relief devices and open-ended lines, effective October 15, 2012. These rules may therefore require a number of modifications to our and our customers’ operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs, for us and our customers, which could have a material adverse effect on our business. In October 2012, several challenges to EPA’s rules were filed by various parties, including environmental groups and industry associations. In a January 1, 2013 unopposed motion to hold this litigation in abeyance, EPA indicated that it may reconsider some aspects of the rule. Depending on the outcome of such proceedings, the rules may be modified or rescinded or EPA may issue new rules; the costs of compliance with any modified or newly issue rules cannot be predicted.

We are exposed to costs associated with lost and unaccounted for volumes.

A certain amount of natural gas is naturally lost in connection with its transportation across a pipeline system, and under our contractual arrangements with our customers we are entitled to retain a specified volume

 

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of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to run our compressor stations, which we refer to as fuel usage. The level of fuel usage and lost and unaccounted for volumes on our pipeline system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our contractual agreements and it will be necessary to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. Future exposure to the volatility of natural gas prices as a result of gas imbalances could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

Approximately one-third of our contracted transportation and storage firm capacity is provided under long-term, fixed price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.

It is possible that costs to perform services under our “negotiated rate” contracts will exceed the negotiated rates. If this occurs, it could decrease the cash flow realized by our systems and, therefore, the cash we have available for distributions to our unitholders. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate,” which is fixed between the pipeline and the shipper for the contract term and does not vary with changes in the level of cost-based “recourse rates”, provided that the affected customer is willing to agree to such rates and that the FERC has approved the negotiated rate agreement. Approximately one-third of our contracted transportation firm capacity is currently subscribed under such “negotiated rate” contracts. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, under current FERC policy is generally not recoverable from other shippers.

Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our natural gas storage business.

Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, then demand for our storage services and the prices that we will be able to charge for those services may decline.

In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated storage expansion activities. Alternatively, an extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition, results of operations and ability to make distributions.

Certain portions of our transportation, storage and processing facilities have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our facilities that could have a material adverse effect on our business and results of operations.

Significant portions of our transportation, storage and processing systems have been in service for several decades. The age and condition of our facilities could result in increased maintenance or repair expenditures, and

 

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any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our facilities could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

Certain of our processing customers require credit support, some of which are currently provided through parent guarantees provided by Kinder Morgan or Tallgrass Development. We may incur additional costs associated with replacing those guarantees.

Certain of our processing customers require credit support, and some of this support is currently in the form of parent guarantees provided by Kinder Morgan or Tallgrass Development, the previous owners of Tallgrass Midstream, LLC. We expect to promptly replace the remaining Kinder Morgan guarantee with a guarantee of Tallgrass Development or to eliminate it altogether. To the extent we are required to replace the remaining guarantees with substitute credit support, we may incur additional costs, including costs associated with issuing letters of credit.

Restrictions in our new credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

We expect to enter into a new credit facility in connection with the closing of this offering. Our new credit facility will limit our ability to, among other things:

 

   

incur or guarantee additional debt;

 

   

redeem or repurchase units or make distributions under certain circumstances;

 

   

make certain investments and acquisitions;

 

   

incur certain liens or permit them to exist;

 

   

enter into certain types of transactions with affiliates;

 

   

merge or consolidate with another company; and

 

   

transfer, sell or otherwise dispose of assets.

Our new credit facility also will contain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

The provisions of our new credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our new credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.

At the closing of this offering, we intend to borrow approximately $225 million under our new credit facility to repay approximately $135.6 of the debt assumed from Tallgrass Development, to pay origination fees with respect to the revolving credit facility and to pay $85.5 million to Tallgrass Development as reimbursement for certain capital expenditures made in connection with the contributed assets as partial consideration for its contribution of assets to us in connection with this offering. Please read, “Prospectus Summary—Formation

 

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Transactions and Partnership Structure.” Following this offering, we will have the ability to incur additional debt, subject to limitations in our credit facility. Our level of debt could have important consequences to us, including the following:

 

   

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

 

   

our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

 

   

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

   

our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Increases in interest rates could adversely impact demand for our storage capacity, our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

There is a financing cost for our customers to store natural gas in our storage facilities. That financing cost is impacted by the cost of capital or interest rate incurred by the customer in addition to the commodity cost of the natural gas in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.

In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.

We rely primarily on revenues generated from natural gas transportation, storage and processing systems that we own, which are primarily located in the Rocky Mountain and Midwest regions of the United States. Due

 

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to our lack of diversification in assets and geographic location, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for natural gas, could have a significantly greater impact on our results of operations and cash available for distribution to our common unitholders than if we maintained more diverse assets and locations.

We do not own most of the land on which the TIGT System and Midstream Facilities are located, which could disrupt our operations and subject us to increased costs.

We do not own most of the land on which the TIGT System and Midstream Facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way. For example, the West Frenchie Draw treating facility is located on land leased from the Wyoming Board of Land Commissioners pursuant to a contract that can be terminated at any time. Although many of these rights are perpetual in nature, we occasionally obtain the right to construct and operate pipelines on other owners’ land for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we may need to exercise TIGT System’s eminent domain authority and might incur increased costs to maintain the TIGT System, which could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions to our unitholders. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.

Some rights-of-way for the TIGT System and other real property assets are shared with other pipeline systems and other assets owned by third parties. We or owners of the other pipeline systems may not have commenced or concluded eminent domain proceedings for some rights-of-way. In some instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants.

The TIGT System has federal eminent domain authority. Regardless, we must compensate landowners for the use of their property, which may include any loss of value to the remainder of their property not being used by us, which are sometimes referred to as “severance damages”. Severance damages are often difficult to quantify and their amount can be significant. In eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipeline system is located.

Our operations are dependent on our rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.

Performance of our operations require that we obtain and maintain numerous environmental and land use permits and other approvals authorizing our business activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on our ability to initiate or continue operations at the affected location or facility. Expansion of our existing operations is also predicated on securing the necessary environmental or land use permits and other approvals, which we may not receive in a timely manner or at all.

In order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time

 

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needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is sometimes delayed or prevented due to community opposition and other factors beyond our control. The denial of a permit or other permit essential to our operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impair or prevent our ability to develop or expand a property or right-of-way. Significant opposition to a permit or other approval by neighboring property owners, members of the public or non-governmental organizations, or other third parties or delay in the environmental review and permitting process also could impair or delay our ability to develop or expand a property or right-of-way. New legal requirements, including those related to the protection of the environment, could be adopted at the federal, state and local levels that could materially adversely affect our operations (including our ability to gather, transport or process or the pace of gathering, transporting or processing natural gas), our cost structure or our customers’ ability to use our services. Such current or future regulations could have a material adverse effect on our business and we may not be able to obtain or renew permits or other approvals in the future.

A shortage of skilled labor in the midstream natural gas industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.

The transportation, storage and processing of natural gas and the fractionation of NGLs requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs for employees, our results of operations could be materially and adversely affected.

In connection with the acquisition of midstream assets from Kinder Morgan in November 2012, Tallgrass Development entered into a Transition Services Agreement with Kinder Morgan pursuant to which Kinder Morgan shares its employees to aid in the provision of certain services for up to nine months following the acquisition. Certain of those services are related to the assets to be contributed to us in connection with this offering and, as a result, we will rely on the shared Kinder Morgan employees for certain services during the transition period. Although we are in the process of hiring additional employees, we may be unable to complete the required hiring and training of the necessary employees during the nine-month transition period, which could have a material adverse effect on our business and results of operations.

Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations.

Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy demand and lower prices for our services, increased difficulty in collecting amounts owed to us by our customers and a reduction in our credit ratings (either due to tighter rating standards or as a result of such potential negative impacts), which could reduce our access to credit markets, raise the cost of such access or require us to provide additional collateral to our counterparties. Our ability to access available capacity under our credit facility could be impaired if one or more of our lenders fails to honor its contractual obligation to lend to us. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Exchange Act. We prepare our financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us

 

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to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report, as described below) beginning with our fiscal year ending December 31, 2014. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.

In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act, or the JOBS Act. For as long as we remain an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our limited partner interests held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile.

Our election to take advantage of JOBS Act extended accounting transition period may make our financial statements more difficult to compare to other public companies.

Pursuant to the JOBS Act, as an “emerging growth company,” we must make an election to opt in or opt out of the extended transition period for any new or revised accounting standards that may be issued by the Public Company Accounting Oversight Board (PCAOB) or the SEC. We have elected to take advantage of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies, we can, for so long as we are an “emerging growth company,” adopt the standard for private companies. This may make comparison of our financial statements with any other public company that either is not an “emerging growth company” or has opted out of using the extended transition period difficult or impossible as a result of our use of different accounting standards.

The outcome of future rate cases will determine the amount of income taxes that we will be allowed to recover.

In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. The extent to which owners of pipelines

 

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have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established. An adverse determination by the FERC with respect to this issue could have a material adverse effect on our revenues, earnings and cash flows.

Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.

We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. We may face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information, otherwise known as “social engineering.”

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position, results of operations and prospects.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including Tallgrass GP Holdings, which owns our general partner and the general partner of Tallgrass Development, LP, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

Following this offering, Tallgrass GP Holdings will own our general partner and will appoint all of the officers and directors of our general partner. Tallgrass GP Holdings will also own and control the general partner of Tallgrass Development. All of our initial officers and a majority of the initial directors of our general partner will also be officers and/or directors of Tallgrass GP Holdings. Certain of our initial directors are also officers or principals of Kelso or EMG, whose affiliated entities, along with certain members of our management, own and control Tallgrass GP Holdings. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner that is in the best interests of its owners, including management, Kelso and EMG. Conflicts of interest will arise between our general partner and its owners, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

 

   

Neither our partnership agreement nor any other agreement requires Tallgrass GP Holdings or its owners to pursue a business strategy that favors us, and the officers and directors of Tallgrass GP Holdings have a fiduciary duty to make these decisions in the best interests of Tallgrass GP Holdings and its owners, which may be contrary to our interests. Tallgrass GP Holdings may choose to shift the focus of its investment and growth to areas not served by our assets.

 

   

Tallgrass GP Holdings, its owners, and their respective affiliates are not limited in their ability to compete with us and, other than Tallgrass Development’s obligation to offer us certain assets, including the Retained Assets, pursuant to the right of first offer under the omnibus agreement, may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them.

 

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Our general partner is allowed to take into account the interests of parties other than us, such as Tallgrass GP Holdings, its owners, and their respective affiliates in resolving conflicts of interest and exercising certain rights under our partnership agreement, which has the effect of limiting its duty to our unitholders.

 

   

All of the initial officers and initial directors of our general partner are also officers and/or directors of Tallgrass GP Holdings and will owe fiduciary duties to Tallgrass GP Holdings. The officers of our general partner will also devote significant time to the business of Tallgrass Development.

 

   

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

 

   

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

 

   

Disputes may arise under our commercial agreements with Tallgrass Development and its affiliates.

 

   

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash available for distribution to our unitholders.

 

   

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units.

 

   

Our general partner determines which costs incurred by it are reimbursable by us.

 

   

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

 

   

Our partnership agreement permits us to classify up to $40 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated or general partner units or to our general partner in respect of the IDRs.

 

   

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

 

   

Our general partner may limit its liability regarding our contractual and other obligations.

 

   

Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

 

   

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including Tallgrass Development’s and its affiliates’ obligations under the omnibus agreement and their commercial agreements with us.

 

   

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

 

   

Our general partner may transfer its IDRs without unitholder approval.

 

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Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s IDRs without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Please read “Conflicts of Interest and Duties.”

Affiliates of our general partner are not limited in their ability to compete with us and have limited obligations to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

Affiliates of our general partner, including Kelso, EMG, Tallgrass GP Holdings and its subsidiaries, including Tallgrass Development, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, affiliates of our general partner and the entities owned or controlled by affiliates of our general partner, including Tallgrass Development, may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities, other than Tallgrass Development’s obligation to offer us certain assets, including the Retained Assets, pursuant to the right of first offer under the omnibus agreement. While affiliates of our general partner may offer us the opportunity to buy these or other additional assets, these affiliates of our general partner, including Tallgrass Development, are not contractually obligated to do so, other than as described above, and we are unable to predict whether or when such opportunities may arise.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner, its executive officers and directors or any of its affiliates, including Tallgrass Development. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner, including Tallgrass Development, and result in less than favorable treatment of us and our common unitholders. Please read “Conflicts of Interest and Duties.”

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on our common units, we will reimburse our general partner and Tallgrass Development’s general partner and its affiliates for expenses they incur and payments they make on our behalf. Under our partnership agreement and the omnibus agreement, we will reimburse our general partner and Tallgrass Development’s general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. Please read “Certain Relationships and Related Transactions—Omnibus Agreement.” Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and Tallgrass Development’s general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

 

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Our partnership agreement requires that we distribute our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires us to distribute our available cash to our unitholders. Accordingly, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we intend to distribute our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

While our partnership agreement requires us to distribute our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

While our partnership agreement requires us to distribute our available cash, our partnership agreement, including provisions requiring us to make cash distributions therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by our general partner and its affiliates, including Tallgrass Development) after the subordination period has ended. At the completion of this offering, affiliates of our general partner will own, direct or indirectly, approximately 46% of our outstanding common units and 100% of our outstanding subordinated units. Please read “Security Ownership of Certain Beneficial Owners and Management.”

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only 13,050,000 publicly traded common units, assuming no exercise of the underwriters’ over-allotment option. In addition, affiliates of our general partner will own 11,250,000 common units and 16,200,000 subordinated units, representing an aggregate of approximately 66% limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

   

the level of our quarterly distributions;

 

   

our quarterly or annual earnings or those of other companies in our industry;

 

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the loss of a large customer;

 

   

announcements by us or our competitors of significant contracts or acquisitions;

 

   

changes in accounting standards, policies, guidance, interpretations or principles;

 

   

general economic conditions;

 

   

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

 

   

future sales of our common units; and

 

   

other factors described in these “Risk Factors.”

You will experience immediate dilution in net tangible book value of $12.24 per common unit.

The estimated initial public offering price of $22.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus) exceeds our pro forma net tangible book value of $9.76 per unit. Based on the estimated initial public offering price of $22.00 per common unit, you will incur immediate dilution of $12.24 per common unit. This dilution results primarily because the assets contributed by Tallgrass Development are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We intend to apply to list our common units on the NYSE. Unlike most corporations, we are not required by NYSE rules to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management.”

If you are not an eligible taxable holder, you will not be entitled to allocations of income or loss or distributions or voting rights on your common units and your common units will be subject to redemption.

In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or an analogous regulatory body, we have adopted certain requirements regarding those investors who may own our common units. Eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. Please read “Description of the Common Units—Transfer of Common Units.” If a holder of our common units (other than affiliates of our general partner) is not a person who fits the requirements to be an eligible taxable holder, such holder will not receive allocations of income or loss or distributions or voting rights on its units and will run the risk of having its units redeemed by us at the market price calculated in accordance with our partnership agreement as of the date of redemption. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please see “The Partnership Agreement—Redemption of Ineligible Holders.”

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of

 

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decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

   

how to allocate business opportunities among us and its affiliates;

 

   

whether to exercise its limited call right;

 

   

whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;

 

   

how to exercise its voting rights with respect to the units it owns;

 

   

whether to elect to reset target distribution levels;

 

   

whether to transfer the IDRs or any units it owns to a third party; and

 

   

whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.

In addition, our partnership agreement provides that any construction or interpretation of our partnership agreement and any action taken pursuant thereto or any determination, in each case, made by our general partner in good faith, shall be conclusive and binding on all unitholders.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Duties— Duties of our General Partner.”

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

   

whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

   

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

 

   

our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

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our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

 

   

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

 

   

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

 

   

determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

   

determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth bullets above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Duties.”

Holders of our common units have limited voting rights and are not entitled to select our general partner or elect members of its board of directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to select our general partner or elect its board of directors. Rather, the board of directors of our general partner, including the independent directors, will be appointed by Tallgrass GP Holdings, as a result of it owning our general partner, and not by our unitholders. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Following the completion of this offering, Tallgrass Development will own an aggregate of approximately 68% of our outstanding common and subordinated units. This will give Tallgrass Development the ability to prevent the involuntary removal of our general partner. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common

 

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units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of unitholder dissatisfaction with the performance of our general partner in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, persons who acquired such units with the prior approval of the board of directors of our general partner and transferees of any of the foregoing, provided such transferee is an affiliate of the transferor, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Tallgrass GP Holdings to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a “change of control” without the vote or consent of the unitholders.

The IDRs of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its IDRs to a third party at any time without the consent of our unitholders. If our general partner transfers its IDRs to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its IDRs. For example, a transfer of IDRs by our general partner could reduce the likelihood of Tallgrass Development selling or contributing additional midstream assets to us, as Tallgrass Development would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

We may issue additional units without your approval, which could negatively impact your existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank could have the following effects:

 

   

our existing unitholders’ proportionate ownership interest in us will decrease;

 

   

the amount of cash available for distribution on each unit may decrease;

 

   

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

   

because the amount payable to holders of IDRs is based on a percentage of the total cash available for distribution, the distributions to holders of IDRs will increase even if the per unit distribution on common units remains the same;

 

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the ratio of taxable income to distributions may increase;

 

   

the relative voting strength of each previously outstanding unit may be diminished; and

 

   

the market price of the common units may decline.

Affiliates of our general partner may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, affiliates of our general partner will indirectly hold an aggregate of 11,250,000 common units and 16,200,000 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, we have agreed to provide our general partner and its affiliates with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner may limit its liability regarding our obligations.

Our general partner may limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, affiliates of our general partner will indirectly own approximately 46% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), affiliates of our general partner will indirectly own approximately 68% of our outstanding common units. For additional information about this right, please read “The Partnership Agreement—Limited Call Right.”

Our general partner, or any transferee holding a majority of the IDRs, may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the IDRs, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of the IDRs, which is initially our general partner, have the right, at any time when there are no subordinated units outstanding and the holders have received incentive distributions at the highest level to which they are entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly

 

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distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our general partner has the right to transfer the IDRs at any time, in whole or in part, and any transferee holding a majority of the IDRs shall have the same rights as our general partner with respect to resetting target distributions.

In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the IDRs will be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the IDRs in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. This risk could be elevated if our IDRs have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

 

   

we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

   

your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable both for the obligations of the transferor to make contributions to the partnership that were known to the transferee at the time

 

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of transfer and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors within a year of the closing of this offering, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements and our general partner will maintain director and officer liability insurance. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly-traded partnership. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a publicly traded partnership.

We have included $2.5 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

 

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Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional tax on us by a state will reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative, judicial or administrative changes or interpretations of applicable law at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such recent legislative proposal would have eliminated the qualifying income exception upon which we rely for our treatment as a partnership for federal income tax purposes. Please read “Material Federal Income Tax Consequences—Partnership Status.” We are unable to predict whether any of these changes or any other proposals will be reintroduced or will ultimately be enacted or whether judicial or administrative interpretations of applicable law will change. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to the unitholder, which may require the payment of federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our

 

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counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may

 

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not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Our counsel has not rendered an opinion with respect to our monthly convention for allocating taxable income and losses. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, Tallgrass Development will own approximately 68% of the total interests in our capital and profits. Therefore, a transfer by Tallgrass Development of all or a portion of its

 

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interests in us could result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year if the termination occurs on a day other than December 31 and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

As a result of investing in our common units, you will likely become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We will initially own property or conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

 

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USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $264.4 million from this offering (assuming an initial public offering price of $22.00 per common unit, the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts, the structuring fee and offering expenses payable by us of approximately $21.5 million, to retire approximately $264.4 million of the indebtedness assumed from Tallgrass Development.

At the closing of this offering, we intend to enter into a new $500 million revolving credit facility, as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility,” and to borrow approximately $225 million, the proceeds of which will be used to:

 

   

retire the remaining approximately $135.6 million of indebtedness assumed from Tallgrass Development;

 

   

pay approximately $5.2 million in revolving credit facility origination fees; and

 

   

pay $85.5 million to Tallgrass Development as reimbursement for a portion of capital expenditures made by Tallgrass Development to purchase the contributed assets, which Tallgrass Development acquired together with the Retained Assets for $1.8 billion.

The indebtedness assumed from Tallgrass Development was used by Tallgrass Development to acquire certain assets from Kinder Morgan, including the assets being contributed to us in connection with this offering, in November 2012. Please read “Prospectus Summary—Our Relationship with Tallgrass Development.” Certain of the underwriters are lenders under the senior secured term loan under which the assumed debt was initially borrowed and, in that respect, will indirectly receive a portion of the net proceeds from this offering. Please read “Underwriting.” The indebtedness assumed from Tallgrass Development constitutes a portion of the senior secured term loan, referred to in this prospectus as the Term Loan, outstanding under Tallgrass Development’s senior secured revolving credit and term loan facilities. The Term Loan bears interest, at Tallgrass Development’s option, at either (a) an alternate base rate, which is a rate equal to the sum of (x) the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5%, (iii) 2.25% and (iv) a one-month reserve adjusted Eurodollar rate plus 1.00%, plus (y) 3.00% or (b) a reserve adjusted Eurodollar rate, which is a rate equal to the sum of (x) the greater of (i) 1.25% and (ii) the Eurodollar rate in effect for the applicable interest period, adjusted for any statutory reserves, plus (y) 4.00%. The Term Loan matures on November 13, 2018 and amortizes in equal quarterly installments of 0.25% beginning on March 31, 2013 through September 30, 2018, with the remaining amount of principal and interest due on November 13, 2018.

If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder of the 1,957,500 additional common units, if any, will be issued to Tallgrass Development. Any such units issued to Tallgrass Development will be issued for no additional consideration. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $40.4 million. The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be distributed to Tallgrass Development.

A $1.00 increase or decrease in the assumed initial public offering price of $22.00 per common unit would cause the net proceeds from this offering, after deducting underwriting discounts, the structuring fee and offering expenses, to increase or decrease, respectively, by approximately $12.2 million. If the proceeds increase due to a higher initial public offering price or decrease due to a lower initial public offering price, then the amount we borrow under our new revolving credit facility will decrease or increase, as applicable, by a corresponding amount.

 

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CAPITALIZATION

The following table shows:

 

   

the historical capitalization of TEP Predecessor as of December 31, 2012; and

 

   

our pro forma capitalization as of December 31, 2012 after giving effect to this offering (assuming an initial public offering price of $22.00 per common unit, the midpoint of the price range set forth on the cover page of this prospectus) and other formation transactions described under “Prospectus Summary—Formation Transactions and Partnership Structure,” including the assumption of $400 million of debt from Tallgrass Development, the application of the net proceeds of this offering and borrowing of approximately $225 million under our new revolving credit facility as described under “Use of Proceeds.”

This table is derived from, should be read in conjunction with and is qualified in its entirety by reference to, our historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of December 31, 2012  
     TEP Predecessor
Historical
     Partnership
Pro Forma(1)
 
     (In thousands)  

Cash and cash equivalents(2)

   $ —        $ —    
  

 

 

    

 

 

 

Long-Term Debt:

     

Debt allocated from Tallgrass Development

     390,491         —     

Revolving Credit Facility

     —           225,000   

Partners’ capital:

     

Predecessor Members’ equity

   $ 571,834       $ —    

Common units—public(3)

     —           258,986   

Tallgrass Development—

     

– Common units(3)

     —           188,729   

– Subordinated units

     —           271,770   

General partner units

     —           13,866   
  

 

 

    

 

 

 

Total members’ equity/partners’ capital

     571,834         733,351   
  

 

 

    

 

 

 

Total capitalization

   $ 962,325       $ 958,351  
  

 

 

    

 

 

 

 

(1) On a pro forma basis, as of December 31, 2012, the public would have held 13,050,000 common units, Tallgrass Development would have held an aggregate of 11,250,000 common units and 16,200,000 subordinated units, and our general partner would have held 826,531 general partner units.
(2) TEP Predecessor participates in a centralized cash management arrangement with Tallgrass Development in which Tallgrass Development sweeps cash balances residing in TEP Predecessor’s bank accounts on a daily basis and settles the balances, less certain reimbursement payments, at the beginning of the following month as equity distributions. Prior to the completion of this offering, the final cash sweep from Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC to Tallgrass Development will be made, and following the completion of this offering, we will no longer participate in the cash management arrangement with Tallgrass Development and we will establish a cash management arrangement for us and our subsidiaries. All cash distributions from us will be made to unitholders and to our general partner in accordance with the terms of our partnership agreement as further described in “Our Cash Distribution Policy and Restrictions on Distributions.”

 

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(3) A $1.00 increase or decrease in the assumed initial public offering price of $22.00 per common unit would cause the net proceeds from this offering, after deducting underwriting discounts, the structuring fee and offering expenses, to increase or decrease, respectively, by approximately $12.2 million. If the proceeds increase due to a higher initial public offering price or decrease due to a lower initial public offering price, then the amount we borrow under our new revolving credit facility will decrease or increase, as applicable, by a corresponding amount.

 

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after this offering. On a pro forma basis as of December 31, 2012, our net tangible book value was $403.2 million, or $9.76 per unit. Purchasers of common units in this offering will experience immediate dilution in pro forma net tangible book value per unit for financial accounting purposes, as illustrated in the following table:

 

Assumed initial public offering price per common unit

     $ 22.00  

Historical net tangible book value per unit before this offering(1)

   $ 8.26     

Less: Payment to Tallgrass Development for capital expenditures(2)

     (3.02  

           Estimated distributions to Tallgrass Development from January 1, 2013
           through the completion of this offering(3)

     (0.54  

Increase in pro forma net tangible book value per unit attributable to purchasers in this offering

     5.06     
  

 

 

   

Less: Pro forma net tangible book value per unit after this offering(4)

       9.76   
    

 

 

 

Immediate dilution in pro forma net tangible book value per unit attributable to purchasers in this offering

     $ 12.24   
    

 

 

 

 

(1) Determined by dividing the number of units (11,250,000 common units, 16,200,000 subordinated units and 826,531 general partner units) to be issued to subsidiaries of Tallgrass Development for its contribution of assets and liabilities to Tallgrass Energy Partners, LP into the historical net tangible book value of the assets and liabilities contributed.
(2) Determined by dividing the number of units (11,250,000 common units, 16,200,000 subordinated units and 826,531 general partner units) to be issued to subsidiaries of Tallgrass Development for its contribution of assets and liabilities to Tallgrass Energy Partners, LP into the expected capital expenditures reimbursement. At the closing of this offering, we intend to make a payment of $85.5 million to Tallgrass Development as reimbursement for a portion of capital expenditures made by Tallgrass Development to purchase the contributed assets, which Tallgrass Development acquired together with the Retained Assets for approximately $1.8 billion.
(3) Determined by dividing the number of units (11,250,000 common units, 16,200,000 subordinated units and 826,531 general partner units) to be issued to subsidiaries of Tallgrass Development for its contribution of assets and liabilities to Tallgrass Energy Partners, LP into the $15.3 million of net estimated distributions paid from the contributed entities to Tallgrass Development from the period from January 1, 2013 through the completion of this offering. Distributions from TIGT and TMID to Tallgrass Development were approximately $18.1 million for the period from January 1, 2013 through March 31, 2013. This amount is partially offset by the $2.8 million of capital contributions that we estimate Tallgrass Development will make to TIGT and TMID during the period from April 1, 2013 through the completion of this offering.
(4) Determined by dividing the total number of units to be outstanding after this offering (24,300,000 common units, 16,200,000 subordinated units and 826,531 general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering.

 

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The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon completion of the transactions contemplated by this prospectus:

 

     Units Acquired     Total Consideration  
     Number      Percent     Amount      Percent  

Units owned by our general partner and its affiliates(1)(2)(3)

     28,276,531         68   $ 132,751         34

Public Common Units

     13,050,000         32   $ 287,100         66
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 41,326,531         100   $ 419,851         100
  

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) The units acquired by our general partner and its affiliates consist of 11,250,000 common units, 16,200,000 subordinated units and 826,531 general partner units.
(2) Assumes the underwriters’ option to purchase additional common units is not exercised.
(3) The assets contributed by the general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by the general partner and its affiliates, as of December 31, 2012, after giving effect to the formation transaction, is as follows:

 

    

(In thousands)

 

Net tangible book value of assets contributed

   $ 233,564   

Less: Payment to Tallgrass Development for capital expenditures(a)

     (85,469

Estimated net distributions to Tallgrass Development from January 1, 2013 through the completion of this offering (b)

     (15,344
  

 

 

 

Total consideration

   $ 132,751   
  

 

 

 

 

(a) At the closing of the offering, we intend to make a payment of $85.5 million to Tallgrass Development as reimbursement for a portion of capital expenditures made by Tallgrass Development to purchase the contributed assets, which Tallgrass Development acquired together with the Retained Assets for $1.8 billion.
(b) Distributions from TIGT and TMID to Tallgrass Development were approximately $18.1 million for the period from January 1, 2013 through March 31, 2013. This amount is partially offset by the $2.8 million of capital contributions that we estimate Tallgrass Development will make to TIGT and TMID during the period from April 1, 2013 through the completion of this offering.

 

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “—Assumptions and Considerations” below. Additionally, please read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical and pro forma operating results, you should refer to our historical and pro forma financial statements and related notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute our available cash quarterly. Our cash distribution policy reflects our belief that our unitholders generally will be better served if we distribute rather than retain available cash, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Our partnership agreement generally defines available cash as the sum of our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) if our general partner so determines, all or any portion of the cash on hand immediately prior to the date of distribution of available cash for the quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our unitholders than would be the case if we were subject to entity-level federal income tax.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions and uncertainties, including the following:

 

   

Our cash distribution policy will be subject to restrictions on cash distributions under our new revolving credit facility. Should we be unable to satisfy these restrictions under our credit facility, we would likely be prohibited from making cash distributions to our unitholders notwithstanding our cash distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Credit Facility.”

 

   

Our general partner will have the authority to establish reserves for the proper conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must subjectively believe that the determination is in our best interests.

 

   

Prior to making any distribution on our common units, we will reimburse our general partner and Tallgrass Development’s general partner and its affiliates for all direct and indirect expenses they incur on our behalf pursuant to the partnership agreement and the omnibus agreement. These expenses will vary with the size and scale of our operations, among other factors. We currently anticipate these reimbursable expenses will be approximately $46.8 million for the twelve months ended June 30, 2014 based on current operations. Neither our partnership agreement nor the omnibus agreement will limit the

 

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amount of expenses for which our general partner and Tallgrass Development’s general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and Tallgrass Development’s general partner and its affiliates will reduce the amount of available cash.

 

   

While our partnership agreement requires us to distribute our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders, except in certain limited circumstances when our general partner can amend our partnership agreement without unitholder approval. However, after the subordination period has ended, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by our general partner and its affiliates, including Tallgrass Development). At the completion of this offering, assuming no exercise of the underwriters’ option to purchase additional units, Tallgrass Development will own approximately 46% of our outstanding common units and all of our outstanding subordinated units, representing an aggregate 66% limited partner interest in us. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

 

   

Even if our cash distribution policy is not modified or revoked, the amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

 

   

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

 

   

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expense, principal and interest payments on our debt, working capital requirements and anticipated cash needs. Our cash available for distribution to common unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.

 

   

If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly cash distributions in order to service or repay our debt or fund expansion capital expenditures.

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $40 million cash basket, that represent non-operating sources of cash. Accordingly, it is possible that return of capital distributions could be made from operating surplus. Any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. We do not anticipate that we will make any distributions from capital surplus.

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

Our partnership agreement requires us to distribute our available cash to our unitholders on a quarterly basis. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and issuances of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we intend to distribute our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand operations. To the

 

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extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units and the incremental distributions on the IDRs may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate that there will be limitations in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

Upon the completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $0.2875 per unit for each whole quarter, or $1.15 per unit on an annualized basis. This represents an aggregate cash distribution of approximately $11.9 million per quarter, or approximately $47.5 million on an annualized basis, based on the number of common, subordinated and general partner units expected to be outstanding upon completion of this offering. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly distributions, if any, will be made within 45 days after the end of each quarter, on or about the 15th day of each February, May, August and November to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the first business day immediately following the indicated distribution date. We will adjust our first distribution for the period from the closing of this offering through June 30, 2013 based on the actual length of the period. The amount of available cash needed to pay the minimum quarterly distribution on all of our common units, subordinated units and general partner units to be outstanding upon completion of this offering for one quarter and on an annualized basis is summarized in the table below:

 

     Number of
Units
     Minimum Quarterly Distributions  
      One Quarter      Annualized  
           

(in thousands)

 

Publicly held common units(1)

     13,050,000       $ 3,752       $ 15,008   

Common units held by Tallgrass Development(1)

     11,250,000         3,234         12,938   

Subordinated units held by Tallgrass Development

     16,200,000         4,658         18,630   

General partner units held by our general partner

     826,531         238         951   
  

 

 

    

 

 

    

 

 

 

Total

     41,326,531       $ 11,882       $ 47,527   
  

 

 

    

 

 

    

 

 

 

 

(1) Assumes no exercise of the underwriters’ option to purchase additional common units. Please read “Prospectus Summary—Formation Transactions and Partnership Structure” for a description of the impact of an exercise of the option on the common unit ownership percentages.

Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest. Our general partner will also hold the IDRs, which entitle the holder to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.3048 per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period.” We cannot guarantee, however, that we will pay the minimum quarterly distribution on our common units in any quarter. Except during the subordination period, if distributions on our common units are not paid at the minimum quarterly distribution rate during any fiscal quarter, our common unitholders will not be entitled to receive such payments in the future.

 

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Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner in good faith will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is in our best interests. Please read “Conflicts of Interest and Duties.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $1.15 per unit for the twelve-month period ending June 30, 2014. In the following sections, we present two tables, consisting of:

 

   

“Unaudited Pro Forma Cash Available for Distribution,” in which we present the amount of cash we would have had available for distribution on a pro forma basis for the year ended December 31, 2012; and

 

   

“Estimated Cash Available for Distribution,” in which we demonstrate our ability to generate sufficient cash available for distribution for us to pay the minimum quarterly distribution on all units for the twelve-month period ending June 30, 2014.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012

If we had completed this offering and related transactions on January 1, 2012, our unaudited pro forma cash available for distribution for the year ended December 31, 2012 would have been approximately $54.2 million. This amount would have been sufficient to pay the minimum quarterly distribution of $0.2875 per unit per quarter ($1.15 per unit on an annualized basis) on all of our common units and subordinated units for such period. This amount would exceed by approximately $6.7 million the amount needed to pay the total annualized minimum quarterly distribution of $47.5 million on all of our common, subordinated and general partner units for the twelve-month period ending June 30, 2014.

Our unaudited pro forma cash available for distribution for the year ended December 31, 2012 includes $2.5 million of estimated incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. Incremental general and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance expenses and director compensation. Our incremental general and administrative expense is not reflected in our predecessor’s historical financial statements or our unaudited pro forma financial statements included elsewhere in the prospectus.

We have based the pro forma assumptions upon currently available information and estimates and assumptions. The pro forma amounts below do not purport to present the results of our operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Moreover, the pro forma adjustments made below contain adjustments that may be in addition to or different from the adjustments made on our pro forma financial statements appearing elsewhere herein. We have not, however, included any adjustments relating to the Pony Express Abandonment, in calculating our unaudited pro forma available cash for the year ended December 31, 2012.

 

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In addition, cash available to pay distributions is primarily a cash accounting concept, while our predecessor’s historical financial statements and our unaudited pro forma financial statements included elsewhere in the prospectus have been prepared on an accrual basis. As a result, you should view the amount of historical Pro Forma Cash Available for Distribution only as a general indication of the amount of cash available to pay distributions that we might have generated had we completed this offering on the dates indicated. The pro forma amounts below are presented on a twelve-month basis, and there is no guarantee that we would have had available cash sufficient to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units during the twelve-month periods presented.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2012 the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the related formation transactions had been completed on January 1, 2012. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.

Unaudited Pro Forma Cash Available for Distribution

 

     Year Ended
December 31, 2012
 
     (in millions, except
per unit data)
 

Pro forma net income:

   $ 39.3   

Add:

  

Depreciation and amortization

     27.6   

Interest expense, net(1)

     9.7   

Less:

  

Estimated incremental general and administrative expenses

     2.5   

Non-cash income related to derivative instruments

     0.3   
  

 

 

 

Pro Forma Adjusted EBITDA(2)

   $ 73.9   

Less:

  

Cash interest paid(3)

     10.6   

Maintenance capital expenditures(4)

     9.1   

Expansion capital expenditures(4)

     23.1   

Add:

  

Borrowings to fund expansion capital expenditures(5)

     23.1   
  

 

 

 

Pro Forma Cash Available for Distribution

   $ 54.2   
  

 

 

 
  

Annualized minimum quarterly distribution per unit

   $ 1.15   
  

Distributions to public common unitholders

   $ 15.0   

Distributions to Tallgrass Development, LP—common units

     12.9   

Distributions to Tallgrass Development, LP—subordinated units

     18.6   

Distributions to general partner

     1.0   
  

 

 

 

Total distributions to our unitholders and general partner

   $ 47.5   
  

 

 

 

Excess (Shortfall)

   $ 6.7   

Percent of minimum quarterly distribution payable to common unitholders

     100

Percent of minimum quarterly distribution payable to subordinated unitholders

     100

 

(1) Interest expense, net includes commitment fees on, and amortization of origination fees incurred in connection with, our new revolving credit facility, as well as interest expense on approximately $225 million of funded borrowings under our new revolving credit facility that we expect to make in connection with this offering and additional assumed borrowings to fund expansion capital expenditures as described further in footnote 6. We have assumed an interest rate on funded borrowings of 4.25% and unfunded commitments of 0.375%.

 

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(2) For more information, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”
(3) Cash interest includes commitment fees on our new revolving credit facility, as well as interest expense on approximately $225 million of funded borrowings under our new revolving credit facility that we expect to make in connection with this offering and additional assumed borrowings to fund expansion capital expenditures as described further in footnote 6. We assumed an interest rate on funded borrowings of 4.25% and unfunded commitments of 0.375%.
(4) Under our partnership agreement, maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity over the long term. For the year ended December 31, 2012, our total capital expenditures were $32.2 million. Historically, we did not make a distinction between maintenance capital expenditures and expansion capital expenditures, however, for purposes of the presentation of “Unaudited Historical As Adjusted Pro Forma Cash Available for Distribution” we have estimated that approximately $9.1 million of these capital expenditures were maintenance capital expenditures for the year ended December 31, 2012. The balance of our capital expenditures for the period were assumed to have been expansion capital expenditures, which primarily consisted of an expansion of the capacity of our natural gas pipeline facilities that run from Franklin to Hastings, Nebraska, an increase in the capacity of our natural gas storage facility, a project to transport NGLs to a refinery near our Casper processing plant and other expansion projects focused on expanding connection to the growing Niobrara shale region.
(5) Because we expect that, in the future, expansion capital expenditures will primarily be funded through external financing sources, we have included borrowings to offset our estimated expansion capital expenditures as well as incremental interest expense on these borrowings.

Estimated Cash Available for Distribution for the Twelve-Month Period Ending June 30, 2014

We forecast that our estimated cash available for distribution for the twelve-month period ending June 30, 2014 will be approximately $56.7 million. This amount would exceed by approximately $9.1 million the amount needed to pay the total annualized minimum quarterly distribution of $47.5 million on all of our common, subordinated and general partner units for the twelve-month period ending June 30, 2014.

We are providing the forecast of estimated cash available for distribution to supplement the historical financial statements of our Predecessor and our unaudited pro forma financial statements included elsewhere in the prospectus in support of our belief that we will have sufficient cash available to allow us to pay cash distributions at the minimum quarterly distribution rate on all of our units for the twelve-month period ending June 30, 2014. Please read “—Assumptions and Considerations” for further information as to the assumptions we have made for the forecast. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” for information as to the accounting policies we have followed for the financial forecast.

Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve-month period ending June 30, 2014. We believe that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. If our estimates are not achieved, we may not be able to pay the minimum quarterly distribution or any other distribution on our common units. The assumptions and estimates underlying the forecast are inherently uncertain and, though we consider them reasonable as of the date of this prospectus, are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast, including, among others, risks and uncertainties contained in “Risk Factors.” Accordingly, there can be no assurance that the forecast is indicative of our future performance or that actual results will not differ materially from those presented in the forecast. Inclusion of the forecast in this prospectus should not be regarded as a representation by any person that the results contained in the forecast will be achieved.

 

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We have prepared the following forecast to present the estimated cash available for distribution to our common unitholders during the forecasted period. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not necessarily indicative of future results.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has neither examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The reports of PricewaterhouseCoopers LLP included in this prospectus relate to the Partnership’s and the Predecessor’s historical financial information. It does not extend to the prospective financial information and should not be read to do so.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the completion of this offering. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full minimum quarterly distribution on all of our outstanding units for the twelve-month period ending June 30, 2014, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

The table below presents (i) our projection of operating results for the twelve-month period ending June 30, 2014 (excluding Pony Express Abandonment adjustments), (ii) the impact of the Pony Express Abandonment on our projected results of operations, and (iii) our adjusted forecast including the impact of the Pony Express Abandonment adjustments. The assumptions discussed below correspond to the amounts in the column titled “Twelve-Month Period Ending June 30, 2014 (including Pony Express Abandonment adjustments),” which we believe presents a more meaningful representation of our anticipated operating results as we expect to complete the sale and related transactions by November 1, 2013. We believe the Pony Express Abandonment will have a small positive impact on our cash available for distribution during the forecast period primarily due to reduced interest expense as we plan to use the proceeds from the sale to pay down borrowings under our revolving facility. Additional detail regarding the Pony Express Abandonment is provided in the footnotes below and in “—Pony Express Abandonment Adjustments.”

 

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Estimated Cash Available for Distribution

 

     Twelve-Month
Period Ending
June 30, 2014
(excluding
Pony Express
Abandonment

adjustments)
    Pony Express Abandonment
adjustments(1)
    Twelve-Month
Period Ending
June 30, 2014
(including
Pony Express
Abandonment

adjustments)
 
     Base Impact     Reimbursement    
     (in millions, except per unit data)  

Revenues:

        

Natural gas liquids sales—Processing

   $ 153.8      $      $      $ 153.8   

Natural gas sales—Processing

     10.3                      10.3   

Natural gas sales—Transportation & Storage

     9.2                      9.2   

Transportation & Storage Services—Firm

     99.5        (1.7            97.8   

Transportation & Storage Services— Interruptible

     3.2        (0.1            3.1   

Other revenues

     12.6                      12.6   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenues(2)

   $ 288.6      $ (1.7   $      $ 286.9   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses:

        

Cost of sales and transportation services(3)

     145.2        7.2        (7.2     145.2   

Operations and maintenance(4)

     37.5        (0.4            37.1   

Depreciation and amortization(5)

     30.0        (2.3            27.7   

General and administrative(6)

     23.7                      23.7   

Taxes, other than income taxes(7)

     8.0        (1.8            6.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating costs and expenses

     244.3        2.7        (7.2     239.8   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     44.3        (4.4     7.2        47.1   

Interest expense, net(8)

     (10.3     2.3               (8.0

Other income (expense), net

     1.5                      1.5   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Income to partners

   $ 35.6      $ (2.1   $ 7.2      $ 40.6   
  

 

 

   

 

 

   

 

 

   

 

 

 

Interest expense, net(8)

     10.3        (2.3            8.0   

Depreciation and amortization

     30.0        (2.3            27.7   
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA(9)

   $ 75.8      $ (6.7   $ 7.2      $ 76.3   

Less:

        

Cash interest paid

     11.1        (2.3            8.8   

Maintenance capital expenditures(10)

     10.8                      10.8   

Expansion capital expenditures(11)

     20.4                      20.4   

One-time replacement capital expenditures(12)

            53.6        (53.6       

Paydown of borrowings with proceeds from sale of Pony Express Assets

            90.3               90.3   

Add:

        

Proceeds from sale of Pony Express Assets

            90.3               90.3   

Borrowings to fund expansion capital expenditures

     20.4                      20.4   
  

 

 

   

 

 

   

 

 

   

 

 

 

Estimated Cash Available for Distribution

   $ 53.9      $ (58.0   $ 60.8      $ 56.7   
  

 

 

   

 

 

   

 

 

   

 

 

 

Annualized minimum quarterly distribution per unit

   $ 1.15      $      $      $ 1.15   

Distributions to public common unitholders

   $ 15.0      $      $      $ 15.0   

Distributions at the minimum distribution rate:

        

Tallgrass Development, LP—common units

     12.9                      12.9   

Tallgrass Development, LP—subordinated units

     18.6                      18.6   

General partner

     1.0                      1.0   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total distributions to our unitholders and general partner at the minimum distribution rate

   $ 47.5      $      $      $ 47.5   
  

 

 

   

 

 

   

 

 

   

 

 

 

Excess of estimated cash available for distribution over annual distributions at the minimum rate

   $ 6.3      $      $      $ 9.1   

 

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(1) Represents adjustments related to the Pony Express Abandonment, assuming these transactions occur on November 1, 2013. These adjustments include the estimated impact of the Pony Express Abandonment for the eight-month period from November 1, 2013 through June 30, 2014. For more information, please see “—Pony Express Abandonment.”
(2) Decrease of $1.7 million ($2.6 million on an annualized basis) arises from foregone short-term firm and interruptible long-haul service that we would have expected to have contracted on the TIGT System.
(3) Following the Pony Express Abandonment, we will incur increased cost of transporting gas on third party pipelines (Trailblazer Pipeline, Wyoming Interstate Company, NGPL) to enable continuation of service to customers who previously received gas transported on the abandoned portion of the TIGT System ($10.9 million annualized costs). We will be reimbursed for these costs by Tallgrass Development for a minimum of five years, or up to 10 years, as described below under “—Pony Express Abandonment.”
(4) Includes net cost savings associated with removing from service certain compressors related to the abandoned portion of the TIGT System, partially offset by the operating cost of replacement compressors ($0.6 million of cost savings on an annualized basis).
(5) Adjustment represents reduced depreciation associated with reduced asset base following the Pony Express Abandonment ($3.5 million on an annualized basis).
(6) Includes $2.5 million in incremental costs associated with Sarbanes-Oxley compliance, investor relations functions, and other costs associated with operating as a publicly traded partnership.
(7) Pro rata ad valorem tax savings following Pony Express Abandonment ($2.7 million of tax savings on an annualized basis).
(8) Reflects a $2.3 million decrease ($3.5 million on an annualized basis) in interest expense as a result of our receipt of an estimated $90.3 million initial payment for the Pony Express Assets and the application of those sale proceeds to pay down borrowing under our new revolving credit facility by an equivalent amount. The actual sale proceeds for the Pony Express Assets will be the actual net book value of the Pony Express Assets at the time of sale, as described in more detail under “—Pony Express Abandonment.”
(9) For more information, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”
(10) Maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our operating income or operating capacity over the long term.
(11) Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.
(12) Consists of expenses associated with the Pony Express Abandonment, including $50.1 million in capital expenditures related to the construction of new gas transportation facilities and $3.5 million associated with abandonment of existing facilities. We will be reimbursed for these costs by Tallgrass Development as described below under “—Pony Express Abandonment.”

Assumptions and Considerations

General

We believe our estimated cash available for distribution for the twelve-month period ending June 30, 2014 will be approximately $56.7 million. This amount of estimated cash available for distribution is approximately $2.5 million more than the unaudited pro forma cash available for distribution for the year ended December 31, 2012. The comparability of our forecast period to historical results is primarily impacted by the following: (i) expected decline in interest expense during the forecast period primarily attributable to lower borrowing amounts, (ii) a decline in firm transportation contracted capacity on the TIGT System and a related decline in throughput volumes primarily from “off-system” customers, such as producers and marketing companies, (iii) the current expansion underway of our Casper and Douglas processing plants which is scheduled to be completed in the second half of 2013 and (iv) NGL and natural gas price volatility in historical periods.

 

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Set forth below are the material assumptions and estimates that we have made in order to demonstrate our ability to generate the minimum estimated cash available for distribution to pay the total annualized minimum quarterly distribution to all unitholders for the twelve-month period ending June 30, 2014. The assumptions discussed below correspond to the amounts listed in the column titled “Twelve-Month Period Ending June 30, 2014 (including Pony Express Abandonment adjustments),” which we believe presents a more accurate representation of our anticipated operating results because we expect to complete the sale and related transactions by November 1, 2014. For more discussion on the abandonment adjustments, please read “—Pony Express Abandonment Adjustments”.

Pony Express Abandonment Adjustments

The Pony Express Abandonment adjustments included in the table above relate to (i) the abandonment of the Pony Express Assets, (ii) the construction of the Replacement Gas Facilities and incremental costs of continuing existing service and related contractual reimbursements, (iii) the sale of the Pony Express Assets to a subsidiary of Tallgrass Development (and the application of an estimated $90.3 million of proceeds from that sale to reduce borrowings under our revolving credit facility by an equivalent amount) and (iv) reimbursements for costs incurred to construct the Replacement Gas Facilities and to transport gas on third party pipelines to enable continuation of service to customers who previously received gas transported on the abandoned portion of the TIGT System. These transactions are referred to in this prospectus collectively as the Pony Express Abandonment. Although these assets will be contributed to us as part of the TIGT System, we have filed an application with the FERC to take these assets out of gas service and then sell these assets to a subsidiary of Tallgrass Development. The FERC application requires us to construct and operate the Replacement Gas Facilities necessary to continue service to existing natural gas firm transportation customers following the proposed abandonment. We and Tallgrass Development have entered into the Pony Express PSA, the form of which was filed with the FERC, that provides that, upon receiving the required FERC approvals and construction of the Replacement Gas Facilities, Tallgrass Development will pay us the actual net book value of the Pony Express Assets at the time of sale, currently estimated to be approximately $90.3 million, and will reimburse us for (i) costs associated with the abandonment of the Pony Express Assets, currently estimated to be $3.5 million, (ii) costs to construct the Replacement Gas Facilities, currently estimated to be $50.1 million, and (iii) costs incurred in obtaining gas pipeline transportation services for existing customers from other interstate pipelines, which we refer to as Reimbursable Transportation Costs, for a minimum period of 5 years, and up to 10 years. These Reimbursable Transportation Costs are currently estimated to be approximately $10.9 million per year. We and Tallgrass Development expect to amend the Pony Express PSA as may be required to conform the duration of the obligation of Tallgrass Development to pay the Reimbursable Transportation Costs (for a period not to exceed ten years) as may be needed so that such obligation is consistent with any condition to approval of the Pony Express Abandonment that is ordered by the FERC.

Our new revolving credit facility will require that we use all proceeds from the upfront payment of the actual net book value of the Pony Express Assets to pay down borrowings thereunder. The remaining payments under the Pony Express PSA are designed to reimburse us for substantially all of the actual costs incurred in connection with the abandonment, the construction of the Replacement Gas Facilities and the incremental cost of continuing service to existing customers after the abandonment and sale occurs. We have adjusted our estimates for the forecast period to reflect the expected impact of the Pony Express Abandonment as we believe this treatment provides a more meaningful depiction of our results of operations because we expect to complete the sale and related transactions in the fourth quarter of 2013. We estimate the abandonment and sale of the Pony Express Assets will reduce forecasted interest expense by $2.3 million, as a result of using the proceeds from our initial sale of the Pony Express Assets to reduce outstanding borrowings under our revolver. Otherwise, the Pony Express Abandonment is not expected to have a material impact on our cash available for distribution for the forecast period. Please see “Risk Factors – Our ability to abandon and sell the Pony Express Assets to Tallgrass Development in connection with the Pony Express Abandonment is subject to the timing and receipt of governmental approvals.”

 

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Segment Data

The following table compares certain financial data in our Gas Transportation and Storage and Processing segments for the twelve-month period ending June 30, 2014 to the historical financials for the year ended December 31, 2012:

 

     Historical      Forecasted  
     Year Ended
December 31,
2012
     Twelve-Month
Period
Ending June 30,
2014
 
     (in millions)  

TIGT

     

Financial Summary

     

Segment Adjusted EBITDA(1)

   $ 55.3       $ 50.9   

Maintenance capital expenditures

     7.1         6.9   

Expansion capital expenditures

     9.7         7.0   

Midstream Facilities

     

Financial Summary

     

Segment Adjusted EBITDA

   $ 21.0       $ 27.9   

Maintenance capital expenditures

     1.9         4.0   

Expansion capital expenditures

     13.4         13.4   

 

(1) Excludes allocation of $2.5 million of incremental costs associated with operating as a publicly traded partnership.

For more information, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

Volumes

The following table compares estimated volumes and operational data on the TIGT System and the Midstream Facilities for the twelve-month period ending June 30, 2014 to the historical volumes and operational data for the year ended December 31, 2012:

 

     Historical      Forecasted  
     Year Ended
December 31, 2012
     Twelve-Month
Period Ending
June 30, 2014
 

TIGT

     

Transportation Summary

     

Firm contracted capacity (MMcf/d)(1)

     754         805   

Interruptible volumes (MMcf/d)

     11         4   

Storage Summary

     

Average firm storage volumes (Bcf)(2)

     11.1         11.1   

Average interruptible volumes (Bcf)

     0.5         0.0   

Midstream Facilities

     

Processing Summary

     

Plant natural gas inlet volume (MMcf/d)

     123         164   

Gross NGL production (MBbl/d)

     6.3         9.9   

Fractionation volumes (MBbl/d)

     1.8         2.4   

 

(1)

Of the 805 MMcf/d of firm contracted capacity forecasted for the twelve-month period ending June 30, 2014, 579 MMcf/d is currently contracted through June 30, 2014, 59 MMcf/d is included based on assumed renewals of existing contracts and 167 MMcf/d is included based on new contracts that we expect to enter

 

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  into in the ordinary course of business prior to or during the forecast period based on anticipated demand increases on the west end of the TIGT system. Although our projected firm contracted capacity is slightly higher for the forecast period as compared to the year ended December 31, 2012, the projected increase in firm capacity reservations relate to customers that we expect to transport volumes shorter distances and at a lower tariff rate, which are expected to partially offset the revenues lost in connection with non-renewing customers in prior periods.

 

(2) Of the 11.1 Bcf of firm storage volumes forecasted for the twelve-month period ending June 30, 2014, 9.9 Bcf is currently contracted through June 30, 2014 and 1.1 Bcf is included based on assumed renewals of existing contracts. We have not included any forecasted firm storage volumes based on new contracts.

Commodity Price Assumptions and Sensitivity Analysis

Natural gas, crude oil and NGL prices are factors that influence whether the amount of cash available for distribution for the twelve-month period ending June 30, 2014 will be above or below our forecast. The profitability of our processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices; as such, during the twelve-month period ending June 30, 2014 we expect approximately two-thirds of our processing revenues to be exposed to direct commodity risk. In addition, NGL prices have historically been correlated to the market price of oil and as a result any significant change in oil prices could also impact our financial results. We do not currently hedge the commodity exposure in our processing contracts. Our processing segment comprised approximately 28% of our Adjusted EBITDA for the year ended December 31, 2012. Our cash flows in our gas transportation and storage segment are not significantly impacted by commodity price fluctuations as we have only a limited amount of direct commodity price exposure related to electrical compression costs and lost and unaccounted for gas on the TIGT System. Historically, we have entered into derivative contracts with third parties for the purpose of hedging these commodity price exposures on the TIGT System. For additional information regarding the estimated impact of increases or decreases in our commodity price assumptions during the forecast period on our cash available for distribution, please read “—Commodity Price Sensitivity Analysis” below. Please read “Risk Factors—We are exposed to direct commodity price risk with respect to approximately two-thirds of our processing revenues, and our exposure to direct commodity price risk may increase in the future.”

 

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Commodity Price Assumptions

The following table compares the commodity price assumptions for the twelve-month period ending June 30, 2014 used for the TIGT System and for the Midstream Facilities to historical commodity prices for the year ended December 31, 2012. As of March 14, 2013, the NYMEX strip prices for natural gas and crude oil for the twelve-month period ending June 30, 2014 were $4.07 per MMBtu and $92.42 per Bbl, respectively. The gas strip price is approximately 4.4% above the forecasted price of $3.90 per MMBtu used to calculate the estimated cash available for distribution, and the oil strip price is approximately 2.6% above the forecasted $90.10 per Bbl used to calculate estimated cash available for distribution. The NGL price forecast generated by our management utilizes the forward strip of NGLs at Mont Belvieu as the baseline, net of estimated basis differentials between Conway and Mont Belvieu, and the transport differentials to Douglas and Casper. We assess the relationship between current NGL and crude prices and assume a correlation that is generally consistent with recent historical periods and current market dynamics. The natural gas price forecast utilizes the NYMEX Gas strip as a baseline, net of estimated basis differentials between Henry Hub and Rockies pricing points. The oil price forecast utilizes the NYMEX forward strip.

 

     Historical      Forecasted  
     Year Ended
December 31, 2012
     Twelve-Month
Period
Ending June 30,
2014
 

Natural Gas

   $ 2.76/MMBtu       $ 3.90/MMBtu   

Natural Gas Liquids

     

Ethane

   $ 0.177/gallon       $ 0.220/gallon   

Propane

   $ 0.811/gallon       $ 0.833/gallon   

Isobutane

   $ 1.721/gallon       $ 1.717/gallon   

Normal butane

   $ 1.484/gallon       $ 1.532/gallon   

Natural gasoline

   $ 2.086/gallon       $ 2.084/gallon   

Crude Oil

   $ 94.07/Bbl       $ 90.10/Bbl   

Commodity Price Sensitivity Analysis

We estimate that (i) a 5.0% change in the price of natural gas from forecasted levels would result in a $0.3 million change in cash available for distribution for the forecast period and (ii) a 5.0% change in the price of NGLs from forecasted levels, would result in a $1.3 million change in cash available for distribution for the forecast period. A decrease in forecasted cash available for distribution of greater than $9.1 million would result in our generating less than the minimum cash required to pay distributions during the forecast period.

Revenues

We estimate that we will generate approximately $286.9 million in revenues for the twelve-month period ending June 30, 2014. We generated $255.6 million in revenues for the year ended December 31, 2012. Our forecasted revenues have been determined by considering the firm contracted capacity under our transportation and storage services agreements, forecasted processing volumes with respect to our current reserved capacity at the Midstream Facilities, and increased processing volumes as a result of the expansion in processing and fractionation capacity at the Midstream Facilities. In addition, our forecasted revenues include assumptions about an immaterial amount of newly contracted capacity on the TIGT System. We expect that any substantial variances between actual revenues during the forecast period and forecasted revenues will be primarily driven by differences between (i) actual and forecasted firm contracted capacity on the TIGT System, (ii) actual and forecasted processing volumes at the Midstream Facilities and (iii) actual and forecasted commodity prices.

We expect approximately $153.8 million, or approximately 54%, of our total forecasted revenues and other income to be supported by natural gas liquids sales under our Processing segment and approximately $10.3 million, or approximately 4%, of our total forecasted revenues and other income to be supported by natural gas

 

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sales under our Processing segment. We expect approximately $9.2 million, or approximately 3%, of our total forecasted revenues and other income to be supported by natural gas sales under our Transportation and Storage segment. We expect approximately $97.8 million, or approximately 34%, of our total forecasted revenues and other income to be supported by firm transportation revenues under our Transportation and Storage segment and approximately $3.1 million, or approximately 1%, of our total forecasted revenues and other income to be supported by interruptible transportation revenues under our Transportation and Storage segment.

Gas Transportation and Storage Segment Revenues

 

   

Revenues from the TIGT System are primarily fee-based in nature and are generated from (i) reservation fees charged for firm transportation capacity reservations and usage fees for firm or interruptible transportation throughput, (ii) reservation fees charged for firm storage capacity reservations and usage fees for firm or interruptible storage volumes and (iii) other items including net fuel collections, natural gas sales and other miscellaneous items. Our cash flows in our gas transportation and storage segment are not significantly impacted by commodity price fluctuations. The limited amount of direct commodity exposure we do have is derived from the Fuel Retention Factors collection component under our FERC tariff. A portion of the gas we collect pursuant to this component is consumed in our gas fired compressor stations, with the balance available for sale by us to reimburse us for our electrical compression costs and lost and unaccounted for gas. Historically, we have hedged a majority of our expected natural gas sales, significantly reducing our commodity price exposure in our gas transportation and storage segment. We do not experience material revenue seasonality in transportation services revenue in the gas transportation and storage segment. Our limited seasonality is caused by our interruptible service and usage fees. These are affected by seasonality because, in contrast to reservation fees under firm contracts, they are highly correlated with actual throughput, which increases in winter months; however, interruptible and usage fees contribute a de minimus portion of total segment revenue. In addition, natural gas sales in the gas transportation and storage segment vary based on levels of customer gas being stored in our facilities. We tend to sell lower volumes of gas in the winter months because our customers are typically withdrawing gas during these periods to meet increased levels of demand. In order to maintain volumes required for efficient operation of our storage facilities, we sell lower volumes of our own gas during these periods.

 

   

We estimate we will generate approximately $110.4 million in total revenues on the TIGT System for the twelve-month period ending June 30, 2014, as compared to $117.4 million in total revenues on the TIGT System for the year ended December 31, 2012. We estimate that approximately 82% of our estimated revenues from TIGT for the forecast period will be generated from services provided under firm transportation and firm storage agreements relating to the TIGT System, as compared to 81% for the year ended December 31, 2012. We estimate that we will have an average of 805 MMcf/d of firm contracted capacity during the forecast period. A substantial majority of the revenues generated from these volumes relates to existing firm contracted capacity with existing customers or renewals of that capacity in the forecast period, with an immaterial amount of revenues generated from these volumes attributable to new contracts we expect to enter into in connection with additional volumes processed at our Casper and Douglas plants for growing liquids-rich Niobrara production. We estimate that approximately 3% of our estimated revenues from TIGT for the forecast period will be generated from services provided under interruptible transportation and interruptible storage agreements relating to the TIGT System, as compared to approximately 2% for the year ended December 31, 2012. We estimate that we will have an average of 4 MMcf/d of interruptible transportation service volumes during the forecast period.

 

   

The expected $7.0 million decrease in revenue on the TIGT System in the twelve-month period ending June 30, 2014, compared to the year ended December 31, 2012 is due in part to decreased renewals of firm capacity contracts with off-system customers over the last few years. We believe these non-renewals may be attributable to competition from long-haul interstate pipelines and reduced drilling activity for dry gas in the Rocky Mountain region. Although our projected firm contracted capacity is

 

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slightly higher for the forecast period as compared to the year ended December 31, 2012, the projected increase in firm capacity reservations relate to customers that we expect to transport volumes shorter distances and at a lower tariff rate, which only partially offsets the revenues lost in connection with the non-renewing customers in prior periods.

 

   

We believe that TIGT System revenues have largely stabilized. The off-system customers that have not renewed their contracts in recent periods are generally producers and marketers that are focused on transporting volumes from one region to another, whereas 70% of our projected firm capacity for the forecast period is represented by on-system customers, such as LDCs, who are users of natural gas and rely on the TIGT System to obtain natural gas for their operations. In addition, we believe these customers will tend to renew contracts at or near their existing reserved capacity based on historical renewal patterns and their peak period requirements. Only 59 MMcf/d of the firm contracted capacity we have assumed for the forecast period is scheduled to expire during the forecast period, most of which is currently contracted with customers we categorize as “on-system” customers. Our forecast assumes that each “on-system” customer will roll-over their contracts at or near their existing reserved capacity at the FERC-approved recourse rate, resulting in no material revenue adjustment from what each of these customers is currently paying to us on a monthly basis. As of December 31, 2012, our weighted average contract life for firm transportation commitments is approximately four years and for firm storage contracts is approximately two years, which we believe offers substantial certainty of cash flows during and beyond the forecast period. Approximately 73% of our forecasted firm revenue is expected to come from on-system customers (approximately 51% from LDCs, 15% from ethanol and industrial users, and 7% from producers and marketers). In addition, of the remaining 27% of projected revenue which is expected to come from off-system customers (approximately 17% from LDCs and 10% from producers and marketers), approximately 44% is currently contracted under firm transportation agreements through September 2017.

The table below illustrates the increasing percentage of revenue attributable to firm contracted capacity on the TIGT System in our historical results and the forecast period.

 

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(1) Other revenues include net gas sales and other miscellaneous items.

Processing Segment Revenues

 

   

We expect that opportunities to process liquids-rich natural gas from the Niobrara shale area, which is served by our Midstream Facilities, will be the primary driver of our near-term growth. We are currently expanding our processing capacity at our Casper and Douglas plants by approximately 50 MMcf/d,

 

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representing an approximate 36% increase in our processing capacity. We are also increasing our NGL fractionation capacity by installing additional capacity of approximately 1,500 barrels per day. We expect each of these expansions to be complete and in-service in the second half of 2013.

 

   

We estimate we will generate approximately $176.5 million in total revenues and approximately $135.9 million in cost of goods sold from the Midstream Facilities for the twelve-month period ending June 30, 2014, resulting in forecasted Midstream Facilities gross margin of $40.6 million. The expected $37.5 million increase in our revenues from the year ended December 31, 2012 compared to the twelve-month period ending June 30, 2014 is primarily due to an expected increase in processing volumes during the forecast period in connection with the expansion of our Casper and Douglas plants and includes an expected increase in the fee-based component of our processing revenues as described in more detail in the fourth bullet below. We estimate that approximately 87% of our estimated revenues from the Midstream Facilities for the forecast period will be generated from natural gas liquids sales, as compared to approximately 91% for the year ended December 31, 2012. We estimate that approximately 6% of our estimated revenues from the Midstream Facilities for the forecast period will be generated from natural gas sales, as compared to approximately 9% for the year ended December 31, 2012.

 

   

This forecast for the twelve-month period ending June 30, 2014 anticipates that our natural gas supply will come primarily from volumes from existing and new customers with active drilling programs in the Niobrara shale. With respect to our existing processing capacity, we have assumed that we will process volumes generally consistent with our throughput volumes for the year ended December 31, 2012. In addition, we believe that our additional expansion capacity will be fully utilized based on the growing gas production from the liquids-rich Niobrara shale. We anticipate the annual Adjusted EBITDA contribution from the Midstream Facilities expansion to be between $8.0 million and $10.0 million once the expansion capacity is fully operational. We expect to complete this expansion project in late 2013, resulting in a material positive impact on profitability in that segment for the twelve-month period ending June 30, 2014. If the expansion is completed in late 2013 as forecasted, we expect the impact on profitability will be less than the annualized impact in periods subsequent to the forecast period due to (i) partial period capacity availability and (ii) a degree of lagged capacity utilization during the ramp up stage after the capacity expansions are completed. As such, we expect the positive impact in subsequent periods to exceed that in the forecasted period.

 

   

Revenues from the Midstream Facilities are generated from natural gas processing, fractionation and treating charges under (i) fee-based contracts, (ii) percentage-of-proceeds (POP) contracts and (iii) keep-whole contracts, or contracts that exhibit characteristics of more than one of these structures. We recognize revenues for all of the NGLs and to a lesser extent, residue gas that we produce and sell pursuant to our processing contracts, and a substantial majority of our revenues are remitted back to our customers and reflected as cost of goods sold in our income statement. As a result, only a small portion of our revenues are retained by us as profit under our percent-of-proceeds or keep whole arrangements. Under our fee-based contracts, the revenues we recognize for NGLs and natural gas sold on behalf of our customers and the cost of goods sold in connection with those sales offset each other, eliminating any material commodity price exposure. Under our percent-of-proceeds and keep whole contracts our revenues and costs of goods sold move with changes in commodity prices. In addition, under our keep-whole arrangements, we are required to replace a contractually specified percentage of the Btu content of the inlet wet gas that we process with a combination of NGLs that we produce and dry natural gas, some of which we must purchase at market prices. For the twelve-month period ending June 30, 2014, we have estimated that approximately 29% and 71% of the gross margin before transport expense in our processing segment will be fee-based and spread-based (which include percent-of-proceeds and keep-whole arrangements), respectively. In comparison, the corresponding contribution percentages to gross margin before transport expense by fee-based and spread-based, respectively, were 22% and 78% for the year ended December 31, 2012. The increased contribution of fee-based revenue to gross margin before transport expense is primarily attributable to a significant fee-based contract executed with a large producer during 2012 and expected volumes from that producer during the forecast period. The

 

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initial reserved capacity level under this contract was 20 Mmcf/d (approximately $1.4 million on an annualized basis) beginning September 1, 2012. Because the contract was only in effect for four of twelve months in 2012, the contribution to fee income was smaller for the year ended December 31, 2012 than it will be in subsequent periods, including the forecast period. Furthermore, the producer has already exercised an option to increase its reserved capacity to 40 Mmcf/d commencing November 16 2012, doubling the contracted annualized fee income in future periods, and has indicated an intention to exercise its option to increase its reserved capacity to 60 Mmcf/d as soon as available volumes exceed the current reservation capacity. In addition, we are projecting increased fee revenue of approximately $0.8 million from other arrangements during the forecast period. In addition to commodity prices, processing segment revenue is also affected by throughput volumes. Volumes are somewhat impacted by temperatures, both locally due to its physical effects on our facilities and the natural gas flowing through them, and more broadly by seasonal dynamics in demand for natural gas; however, the magnitude of this seasonality is muted and as such does not typically give rise to material differences in overall cash flow generation from period to period. Both types of cash flow streams are projected to increase in absolute value as a result of increased capacity stemming from our expansion project, though fee-based margin is anticipated to grow on a comparative basis. The bulk of this estimated increase is driven by a substantial reservation fee on one of our large percent-of-proceeds contracts which we began collecting in late 2012.

 

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Cost of Sales and Transportation Services

Cost of sales and transportation services primarily arises from the purchase of inlet gas at our processing plants from producers and the purchases of NGLs from local suppliers in our processing segment. In addition, but to a lesser extent, the cost of natural gas sales associated with fuel and lost and unaccounted for volumes in our gas transportation and storage segment is recorded as cost of sales and transportation services. We estimate total costs of goods sold to be approximately $145.2 million for the twelve-month period ending June 30, 2014, an increase of approximately $28.9 million from the year ended December 31, 2012. Approximately 94% of costs of goods sold over the forecast period is related to our Midstream Facilities segment. This is due to higher forecasted commodity prices and increased volumes due to expansion of capacity and resulting increase in the cost of the natural gas and NGLs we sell on behalf of our customers.

 

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Operating Expenses

Our operating expenses include salary and wage expense, utility costs, insurance premiums, taxes and other operating costs. We estimate that we will incur operating expenses of approximately $37.1 million for the twelve-month period ending June 30, 2014, as compared to $37.3 million and $36.7 million for the year ended December 31, 2011 and the year ended December 31, 2012, respectively.

General and Administrative Expenses

We estimate that our general and administrative expenses will be approximately $23.7 million for the twelve-month period ending June 30, 2014, as compared to $18.5 million for the year ended December 31, 2012. The increase in forecasted general and administrative expenses is largely reflective of Kinder Morgan’s scale advantage in supporting similar required administrative functions by a substantially larger number of operated businesses. We also estimate that we will incur approximately $2.5 million of incremental general and administrative expenses as a result of operating as a publicly-traded partnership that are not reflected in our unaudited pro forma financial statements.

Depreciation and Amortization

We estimate depreciation and amortization expense for the twelve-month period ending June 30, 2014 of approximately $27.7 million as compared to $27.6 million for the year ended December 31, 2012 on a pro forma basis. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in forecasted depreciation and amortization is largely attributable to the expansions of the Douglas and Casper plants and the increased basis in the Processing segment assets.

Capital Expenditures

Estimated capital expenditures for the twelve-month period ending June 30, 2014 are based on the following assumptions:

 

   

Maintenance Capital Expenditures. We estimate that our maintenance capital expenditures will be approximately $10.8 million for the twelve-month period ending June 30, 2014, which is expected to primarily relate to general pipeline management. Maintenance capital expenditures were $9.1 million for the year ended December 31, 2012, and included general maintenance, upgrades and integrity management. While we anticipate variability in levels of maintenance capital expenditure in both of our segments going forward due to occasional unpredictable expenditures, we believe the forecasted $10.8 million is generally indicative of the average annual maintenance capital requirement going forward. This forecasted figure is lower than recent trends in maintenance capital expenditures for two primary reasons:

 

   

Recent historical maintenance capital expenditures on the TIGT System included integrity management-related replacement of certain pipe sections with newer pipe during the year ended December 31, 2012. As this replacement pipe program is substantially complete, we do not currently anticipate incurring substantial further expenditures on the replacement pipe program during the forecasted period.

 

   

We expect the maintenance capital expenditure requirements of our Midstream Facilities to decline following completion of the current expansion project at the Casper and Douglas plants, as it includes the installation of newer, more efficient compressors, which require less ongoing maintenance. The expansion project is expected to be completed in the second half of 2013.

 

   

Expansion Capital Expenditures. We have assumed expansion capital expenditures of approximately $20.4 million for the twelve-month period ending June 30, 2014, as compared to $23.1 million for the year ended December 31, 2012. Our planned expansion capital expenditures relate primarily to the

 

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ongoing expansion of the Douglas and Casper plants. After the closing of this offering, we expect to fund expansion capital expenditures from external sources, including borrowings under our new revolving credit facility and the issuance of additional partnership units and debt offerings. For purposes of this forecast, we have assumed that we will fund all of the forecasted expansion capital expenditures with borrowings under our new revolving credit facility.

 

   

One-Time Replacement Capital Expenditures. In addition, we estimate that we will incur expansion capital expenditures related to the Pony Express Project of approximately $53.6 million for which we will receive reimbursement from Tallgrass Development. As a result, these expansion capital expenditures will not have any impact on cash available for distribution.

Although we may make acquisitions during the twelve-month period ended June 30, 2014, our forecast does not reflect any acquisitions, as we cannot assure you that we will be able to identify attractive acquisition opportunities or, if identified, that we will be able to negotiate acceptable purchase agreements.

Financing

We estimate that cash interest paid will be approximately $8.8 million for the twelve-month period ending June 30, 2014. The difference of $0.8 million between forecasted interest expense and forecasted cash interest paid primarily represents non-cash interest income in our gas transportation and storage segment. Our cash interest paid for the forecast period is based on the following significant financing assumptions:

 

   

We expect to use $264.4 million of net proceeds from this offering plus approximately $225 million of revolver borrowings to retire approximately $400 million of debt assumed from Tallgrass Development and to pay $85.5 million to Tallgrass Development as reimbursement for certain capital expenditures made with respect to the assets contributed to us.

 

   

We expect to have average borrowings of approximately $178 million under our new $500 million revolving credit facility during the forecast period, which reflects (i) approximately $225 million of borrowings we expect to incur at the closing of this offering, (ii) $20.4 million of borrowings we expect throughout the forecast period to incur to fund our forecasted expansion capital expenditures and (iii) the repayment of an estimated $90.3 million of borrowings in connection with the sale of the Pony Express Asset in the fourth quarter of 2013.

 

   

We have assumed an interest rate on funded borrowings of 4.25% and unfunded commitments of 0.375%. An increase or decrease of 1.0% in the interest rate will result in increased or decreased, respectively, annual interest expense of $1.8 million.

 

   

We expect to remain in compliance with the financial and other covenants in our new credit facility.

A $1.00 increase or decrease in the assumed initial public offering price of $22.00 per common unit would cause the net proceeds from this offering, after deducting underwriting discounts, the structuring fee and offering expenses, to increase or decrease, respectively, by approximately $12.2 million. If the offering proceeds increase due to a higher initial public offering price or decrease due to a lower initial public offering price, then the amount we will borrow under our new revolving credit facility at the closing of this offering to make the payments described under “Use of Proceeds” will decrease or increase, as applicable, by a corresponding amount. A $12.2 million increase in the amount we borrow under our new credit facility at the closing of this offering will increase our interest expense over the forecast period by $0.5 million and result in a corresponding decrease in our estimated cash available for distribution over the forecast period assuming the $12.2 million increase in the amount we borrow at closing is outstanding for the entire forecast period.

 

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Regulatory, Industry and Economic Factors

Our forecast for the twelve-month period ending June 30, 2014 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

   

There will not be any new federal, state or local regulation of the portions of the midstream energy industry, or any new interpretation of existing regulations, that will be materially adverse to our business.

 

   

There will not be any material adverse change in the midstream energy industry, commodity prices, capital or insurance markets or in general economic conditions.

 

   

There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend.

While we believe that our assumptions supporting our estimated cash available for distribution for the twelve-month period ending June 30, 2014 are reasonable in light of our current beliefs concerning future events, the assumptions are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual cash available for distribution that we generate could be substantially less than the amounts that we currently expect to generate and could, therefore, be insufficient to permit us to make the full minimum quarterly distribution on all of our units, in which event the market price of our common units could decline materially.

 

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending June 30, 2013, we distribute our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the completion of this offering through June 30, 2013, based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

 

   

less, the amount of cash reserves established by our general partner to:

 

   

provide for the proper conduct of our business (including reserves for our future capital expenditures, for anticipated future credit needs subsequent to that quarter, for legal matters and for refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings);

 

   

comply with applicable law or regulation, any of our debt instruments or other agreements; or

 

   

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

 

   

plus, if our general partner so determines, all or any portion of the cash on hand on the date of distribution of available cash for the quarter, including cash on hand resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash received by us after the end of the quarter but on or before the date of distribution of available cash for the quarter, including cash on hand from working capital borrowings made after the end of the quarter but on or before the date of distribution of available cash for that quarter, to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.2875 per unit, or $1.15 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

 

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General Partner Interest and Incentive Distribution Rights

Initially, our general partner will be entitled to 2.0% of all quarterly distributions from inception that we make prior to our liquidation. This general partner interest will initially be represented by 826,531 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2.0% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

Our general partner also currently holds IDRs that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.3048 per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. Please read “—General Partner Interest and Incentive Distribution Rights” for additional information

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:

 

   

$40 million (as described below); plus

 

   

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) and the termination of commodity and interest rate hedges, provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

 

   

working capital borrowings made after the end of a quarter but on or before the date of distribution of available cash for that quarter; plus

 

   

cash distributions (including incremental distributions on IDRs) paid in respect of equity issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, acquisition, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus

 

   

cash distributions (including incremental distributions on IDRs) paid in respect of equity issued, other than equity issued in this offering, to pay construction period interest and related fees on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to in the prior bullet, in each case, in respect of the period from the date that we enter into a binding obligation to commence the construction, development, acquisition, replacement, improvement or expansion of a capital asset until the earlier to occur of the date the capital asset is placed in service and the date that it is abandoned or disposed of; less

 

   

all of our operating expenditures (as defined below) after the closing of this offering; less

 

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the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

   

all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings; less

 

   

any cash loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $40 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the 12-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements and (iv) a capital contribution.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, director and employee compensation, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its settlement or termination date specified therein will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract and amounts paid in connection with the initial purchase of a rate hedge contract or a commodity hedge contract will be amortized at the life of such rate hedge contract or commodity hedge contract), maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

 

   

repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

 

   

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

 

   

expansion capital expenditures (including interest and fees incurred on construction debt);

 

   

investment capital expenditures;

 

   

payment of transaction expenses (including taxes) relating to interim capital transactions;

 

   

distributions to our partners;

 

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repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans); or

 

   

any other expenditures or payments using the proceeds of this offering that are described in “Use of Proceeds.”

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

 

   

borrowings other than working capital borrowings;

 

   

sales of our equity and debt securities; and

 

   

sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of equipment and the construction, development or acquisition of additional pipeline, storage, treating or processing capacity to the extent such capital expenditures are expected to expand our operating capacity or our operating income. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of.

Maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but that are not expected to expand our operating capacity or operating income over the long term.

 

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Capital expenditures that are made in part for maintenance capital purposes, investment capital purposes and/or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our general partner.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day of any quarter beginning after June 30, 2016, that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $1.15 (the annualized minimum quarterly distribution), for each of the three consecutive non-overlapping four quarters immediately preceding that date;

 

   

the adjusted operating surplus (as defined below) generated during each of the three consecutive non-overlapping four quarters immediately preceding that date equaled or exceeded the sum of $1.15 (the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted, weighted average basis (as defined in our partnership agreement, a copy of which is included as Appendix A); and

 

   

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending June 30, 2014, that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $1.725 per unit (150% of the annualized minimum quarterly distribution), for the four-quarter period immediately preceding that date;

 

   

the “adjusted operating surplus” (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $1.725 per unit (150% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted, weighted average basis (as defined in our partnership agreement, a copy of which is included as Appendix A) and (ii) the corresponding distributions on the IDRs; and

 

   

there are no arrearages in payment of the minimum quarterly distribution on the common units.

 

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In addition, and notwithstanding the foregoing, the subordination period will also automatically terminate,

 

   

with respect 50% of the subordinated units, on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending December 31, 2014, that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $0.3306 per unit (115% of the minimum quarterly distribution), for the quarter immediately preceding that date;

 

   

the “adjusted operating surplus” (as defined below) generated during the quarter immediately preceding that date equaled or exceeded the sum of (i) $0.3306 per unit (115% of the minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during that period on a fully diluted, weighted average basis and (ii) the corresponding distributions on the IDRs; and

 

   

there are no arrearages in payment of the minimum quarterly distribution on the common units.

 

   

with respect 100% of the subordinated units, on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending December 31, 2014, that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $0.3594 per unit (125% of the minimum quarterly distribution), for the quarter immediately preceding that date;

 

   

the “adjusted operating surplus” (as defined below) generated during the quarter immediately preceding that date equaled or exceeded the sum of (i) $0.3594 per unit (125% of the minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during that period on a fully diluted, weighted average basis and (ii) the corresponding distributions on the IDRs; and

 

   

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause:

 

   

the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner; and

 

   

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

 

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Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net changes in working capital borrowings and net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

 

   

operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

 

   

any net increase in working capital borrowings with respect to that period; less

 

   

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

 

   

any net decrease in working capital borrowings with respect to that period; plus

 

   

any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods pursuant to the third bullet point above; plus

 

   

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus during the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

   

first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

   

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

   

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

   

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

 

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General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units in this offering or upon expiration of such option, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the IDRs) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.

IDRs represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The following discussion assumes that our general partner maintains its 2.0% general partner interest and that our general partner continues to own all of the IDRs.

If for any quarter:

 

   

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

   

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

 

   

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $0.3048 per unit for that quarter (the “first target distribution”);

 

   

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.3536 per unit for that quarter (the “second target distribution”);

 

   

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $0.4313 per unit for that quarter (the “third target distribution”); and

 

   

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Available Cash From Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has

 

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contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its IDRs and that there are no arrearages on common units.

 

     Total Quarterly
Distribution per Unit

Target Amount
     Marginal Percentage
Interest in Distributions
 
      Unitholders     General Partner  

Minimum Quarterly Distribution

               $0.2875         98.0     2.0

First Target Distribution

   above $ 0.2875 up to $0.3048         98.0     2.0

Second Target Distribution

   above $ 0.3048 up to $0.3536         85.0     15.0

Third Target Distribution

   above $ 0.3536 up to $0.4313         75.0     25.0

Thereafter

    
above $0.4313
  
     50.0     50.0

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our IDRs, has the right under our partnership agreement, subject to certain conditions, to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our IDRs in the future, then the holder or holders of a majority of our IDRs will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the IDRs at the time that a reset election is made. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the IDRs at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter, respectively. If our general partner and its affiliates are not the holders of a majority of the IDRs at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the IDRs received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. In addition, our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its IDRs during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

 

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Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute our available cash from operating surplus for each quarter thereafter as follows:

 

   

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 106.0% of the reset minimum quarterly distribution for that quarter;

 

   

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 123.0% of the reset minimum quarterly distribution for the quarter;

 

   

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

 

   

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.50.

 

    Quarterly
Distribution per Unit

Prior to Reset
  Marginal Percentage
Interest in Distribution
    Quarterly
Distribution per
Unit following
Hypothetical
Reset
      Unitholders     2% General
Partner
    Incentive
Distribution
Rights
   

Minimum Quarterly Distribution

  $0.2875     98.0     2.0          $0.5000

First Target Distribution

  above $0.2875 up to $0.3048     98.0     2.0          above $0.5000 up to $0.5300(1)

Second Target Distribution

  above $0.3048 up to $0.3536     85.0     2.0     13   above $0.5300 up to $0.6150(2)

Third Target Distribution

  above $0.3536 up to $0.4313     75.0     2.0     23   above $0.6150 up to $0.7500(3)

Thereafter

  above $0.4313     50.0     2.0     48   above $0.7500

 

(1) This amount is 106.0% of the hypothetical reset minimum quarterly distribution.
(2) This amount is 123.0% of the hypothetical reset minimum quarterly distribution.
(3) This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

 

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of IDRs, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be 40,500,000 common units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit would be $0.50 per quarter for the two consecutive non-overlapping quarters prior to the reset.

 

        Common
Unitholders
Cash
Distribution
Prior to
Reset
    General Partner  Cash
Distributions Prior to Reset
       
    Quarterly
Distribution
per Unit
Prior to Reset
    2.0%
General
Partner
Interest
        IDRs             Total         Total
    Distributions    
 

Minimum Quarterly Distribution

  $0.2875   $ 11,643,750      $ 237,628      $      $ 237,628      $ 11,881,378   

First Target Distribution

  above $0.2875 up to $0.3048     689,625        14,258               14,258        712,883   

Second Target Distribution

  above $0.3048 up to $0.3536     1,979,438        46,575        302,738        349,313        2,328,750   

Third Target Distribution

  above $0.3536 up to $0.4313     3,143,813        83,835        964,103        1,047,938        4,191,750   

Thereafter

  above $0.4313     2,784,375        111,375        2,673,000        2,784,375        5,568,750   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    $ 20,250,000      $ 493,670      $ 3,939,840      $ 4,433,510      $ 24,683,510   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of IDRs, with respect to the quarter after the reset occurs. The table reflects that as a result of the reset there would be 48,379,680 common units outstanding, our general partner has maintained its 2.0% general partner interest, and that the average distribution to each common unit would be $0.50. The number of common units issued as a result of the reset was calculated by dividing (x) $3,939,840 as the average of the amounts received by the general partner in respect of its IDRs for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, by (y) the average of the cash distributions made on each common unit per quarter for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, or $0.50.

 

               General Partner Cash
Distributions After Reset
       
     Quarterly
Distribution
per Unit

After Reset
  Common
Unitholders
Cash
Distribution
After Reset
    Common
Units
Issued As
a Result of

the Reset
    2.0%
General
Partner
Interest
    IDRs     Total     Total
Distributions
 

Minimum Quarterly Distribution

   $0.5000   $ 20,250,000      $ 3,939,840      $ 493,670      $      $ 493,670