Tallgrass Energy Partners, LP - FORM S-1

Attached files

file	filename
EX-1.1 - EX-1.1 - Tallgrass Energy Partners, LP	d475659dex11.htm
EX-3.1 - EX-3.1 - Tallgrass Energy Partners, LP	d475659dex31.htm
EX-3.4 - EX-3.4 - Tallgrass Energy Partners, LP	d475659dex34.htm
EX-3.2 - EX-3.2 - Tallgrass Energy Partners, LP	d475659dex32.htm
EX-21.1 - EX-21.1 - Tallgrass Energy Partners, LP	d475659dex211.htm
EX-23.1 - EX-23.1 - Tallgrass Energy Partners, LP	d475659dex231.htm
EX-23.4 - EX-23.4 - Tallgrass Energy Partners, LP	d475659dex234.htm

Index to Financial Statements

As filed with the Securities and Exchange Commission on March 28, 2013

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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
Common units representing limited partner interests	$315,157,500	$42,988

(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).

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.

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 March 28, 2013

PROSPECTUS

LOGO

Tallgrass Energy Partners, LP

Common Units

Representing Limited Partner Interests

This is the initial public offering of our common units representing limited partner interests. We are offering common units in this offering. We currently expect that the initial public offering price will be between $ and $ per common unit. Prior to this offering, there has been no public market for our common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol “TEP.”

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 $ 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 % 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 common units in this offering, the underwriters have the option to purchase up to an additional 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

Prospectus dated , 2013

Index to Financial Statements

[Inside Cover Art]

Index to Financial Statements

TABLE OF CONTENTS


PROSPECTUS SUMMARY			1
RISK FACTORS			25
USE OF PROCEEDS			65
CAPITALIZATION			66
DILUTION			67
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			69
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			88
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			102
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			106
INDUSTRY OVERVIEW			127
BUSINESS			134
MANAGEMENT			157
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			164
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			165
CONFLICTS OF INTEREST AND DUTIES			169
DESCRIPTION OF THE COMMON UNITS			178
THE PARTNERSHIP AGREEMENT			180
UNITS ELIGIBLE FOR FUTURE SALE			192
MATERIAL FEDERAL INCOME TAX CONSEQUENCES			194
INVESTMENT IN TALLGRASS ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS AND IRAS			211
UNDERWRITING			213
VALIDITY OF THE COMMON UNITS			220
EXPERTS			220
WHERE YOU CAN FIND MORE INFORMATION			220
FORWARD-LOOKING STATEMENTS			222
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.

Index to Financial Statements

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 $ per common unit (the midpoint of the price range set forth on the cover page of this prospectus) and (2) that the underwriters do not exercise their option to purchase additional units. 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 indebtedness of the acquired entities). Tallgrass Development will contribute the TIGT System and the

Index to Financial Statements

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 each of the remaining 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 978 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 70% 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 4.3 years and 2.0 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 with on-system customers. In addition, over half of our remaining transportation and storage revenue during the

Index to Financial Statements

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

978 MMcf/d

689 MMcf/d

4.3 yrs

Storage

15.1 Bcf (3)

11.1 Bcf

2.0 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 Facilities has been reserved. In exchange for these reservations, we typically receive a fee, acreage dedication or,

Index to Financial Statements

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%

5.0 yrs

101

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

•

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, which is one of the most significant trading hubs for crude oil in North America. 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 and is currently contracted for 206,000 barrels per day for five years beginning from the date it is placed in service with an additional 10% of capacity available for walk-up customers.

Index to Financial Statements

•

the Trailblazer Pipeline, an approximately 439-mile interstate pipeline with a capacity of up to 862 MMcf/d, approximately 605 MMcf/d of which is under contract as of December 31, 2012 with a weighted average remaining contract term of approximately 4.8 years, 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 1,698-mile natural gas pipeline with a long-haul design capacity of up to 1.8 Bcf/d, substantially all of which is under contract as of December 31, 2012 with a weighted average remaining contract term of 6.2 years, that extends from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio and is one of the largest natural gas pipelines in North America.

Tallgrass Development will also own an approximately % 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 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.

•

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.

Index to Financial Statements

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.

•

Relationship with Tallgrass Development. We believe that Tallgrass Development and its affiliates, as the owners of a % 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 $ 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.

Index to Financial Statements

•

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 approximately two-thirds 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.

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.

Index to Financial Statements

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 common units and subordinated units, representing a % limited partner interest in us ( % if the underwriters exercise in full their option to purchase additional common units), (ii) assume from Tallgrass Development $ million of indebtedness and (iii) pay to Tallgrass Development $ 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 closing of this offering, Tallgrass Development will own a % 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 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 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.

Index to Financial Statements

segments of the energy complex. EMG has $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 a majority of 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 seven directors. 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 completion of this offering. At least one of our independent directors will be appointed prior to 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 expenses include 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 closing of this offering, our general partner will own 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 $ per unit per quarter after the closing of our initial public offering. Please read “Certain Relationships and Related Transactions.”

Index to Financial Statements

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 our officers and a majority of the 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 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.”

Index to Financial Statements

Formation Transactions and Partnership Structure

At or prior to the closing 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 common units and subordinated units, representing a % limited partner interest in us ( % if the underwriters exercise in full their option to purchase additional common units), (ii) assume from Tallgrass Development $ million of indebtedness and (iii) pay to Tallgrass Development $ 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 general partner units, representing its initial 2.0% general partner interest in us, and all of our IDRs;

•

we will issue common units to the public in this offering, representing a % limited partner interest in us ( % 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 origination fees related to our new revolving credit facility and to retire approximately $ of the debt assumed from Tallgrass Development;

•

we will enter into a new $ 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 $ million, the proceeds of which will be used to repay the remaining approximately $ million of debt assumed from Tallgrass Development and to pay $ 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 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 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.

Index to Financial Statements

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)		%
Tallgrass Development
Common Units(1)		%
Subordinated Units		%
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.

Index to Financial Statements

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. .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.

Index to Financial Statements

The Offering

Common units offered to the public

common units, or common units if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering

common units and subordinated units, representing a % and % limited partner interest in us, respectively. If the underwriters do not exercise their option to purchase additional common units, we will issue an additional 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 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 $ million from this offering (assuming an initial public offering price of $ per common unit, the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts, to:

•

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

At the closing of this offering, we intend to enter into a new $ 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 $ million, the proceeds of which will be used to:

•

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

•

pay approximately $ million in revolving credit facility origination fees;

•

pay the structuring fee and offering expenses payable by us of approximately $ million; and

•

pay $ 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.

Index to Financial Statements

If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $ 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 $ per unit ($ 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 $ 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 $ ; and

•

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

If cash distributions to our unitholders exceed $ 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

Index to Financial Statements

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 $54.9 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 immediately after this offering will be approximately $ million (or an average of approximately $ million per quarter). As a result, we would have generated available cash sufficient to pay the full minimum quarterly distribution of $ per unit per quarter ($ 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 $ per unit per quarter ($ 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

Index to Financial Statements

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 , 2016 on which we have earned and paid at least $ (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 $ (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 , 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 $ (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 , 2014 and (ii) with respect to 100% of the subordinated units, on the first business day after we have earned and paid at least $ (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 , 2014, in each case provided that there are no arrearages on our common units at that time.

The subordination period also will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not 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, it has received incentive distributions at the highest level to which it is entitled (48.0%) for the prior four consecutive whole fiscal quarters, and the amount of the total distribution of available cash for each

Index to Financial Statements

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. Upon closing of this offering, Tallgrass Development will own an aggregate of approximately % 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, of the remaining common units at a price not less than the then-

Index to Financial Statements

current market price of the common units, as calculated in accordance with our partnership agreement.

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 % 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 % 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 associated with us, as designated by us. For further information regarding our directed unit program, please read “Underwriting.”

New York Stock Exchange listing

We intend to apply to list our common units on the New York Stock Exchange under the symbol “TEP.”

Index to Financial Statements

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 closing 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 common units and subordinated units to Tallgrass Development, representing a % limited partner interest in us ( % if the underwriters exercise in full their option to purchase additional common units) and our assumption from Tallgrass Development of $ million of indebtedness;

•

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

•

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

•

the closing of our new $ million revolving credit facility under which we expect to borrow approximately $ million at the closing of this offering, to pay expenses associated with this offering and origination fees related to our new revolving credit facility and to repay the remaining approximately $ million of debt assumed from Tallgrass Development and to pay $ million to

Index to Financial Statements

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			25,162
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			204,585

Operating income		75,499			50,113			1,311			50,995
Other income (expense), net(2)		203			1			482			483
Interest income (expense), net(3)		2,101			1,661			(3,201	)		(9,103	)

Income (loss) before income taxes		77,803			51,775			(1,408	)		42,375
Texas margin taxes(4)		296			279			—			—

Net Income (loss) to member/partners	$	77,507		$	51,496		$	(1,408	)	$	42,375

Net income per limited partners’ unit:
Common units
Subordinated units
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			1,026,362
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			732,073
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	)		—
Other Financial Data: (unaudited)
Adjusted EBITDA(5)		98,428			70,761			5,606			76,367

Index to Financial Statements


	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)
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		101		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

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

Index to Financial Statements

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.

Index to Financial Statements

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	)	$	42,375
Add:
Interest (income) expense, net		(2,101	)		(1,661	)		3,201			9,103
Depreciation and amortization expense		22,726			20,647			4,086			25,162
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

Index to Financial Statements

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 $ per unit, or $ per unit on an annualized basis, we will require available cash of approximately $ million per quarter, or $ 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;

Index to Financial Statements

•

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 $62.0 million, as compared to approximately $54.9 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.

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. 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 4.3 years and 2.0 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;

Index to Financial Statements

•

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 the Retained Assets pursuant to the

Index to Financial Statements

right of first offer under the omnibus agreement, we have no contractual arrangement with 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

Index to Financial Statements

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 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 approximately two-thirds 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 66% 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

Index to Financial Statements

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, 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:

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rates, operating terms and conditions of service;

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the form of tariffs governing service;

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the types of services we may offer to our customers;

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

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the acquisition, extension, disposition or abandonment of facilities;

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creditworthiness and credit support requirements;

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the maintenance of accounts and records;

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

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depreciation and amortization policies; and

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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

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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.

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.

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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 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.

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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 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.

Index to Financial Statements

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:

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adverse changes in general global economic conditions;

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adverse changes in domestic regulations;

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

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the price and availability of other forms of energy;

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prices for natural gas;

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

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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

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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:

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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;

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

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uncontrolled releases of natural gas and other hydrocarbons;

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

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outages at our processing facilities;

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ruptures, fires and explosions; and

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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.

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

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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.

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:

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

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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;

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

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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

Index to Financial Statements

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 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

Index to Financial Statements

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. 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.

Index to Financial Statements

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:

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

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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;

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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;

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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;

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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;

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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;

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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

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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

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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. 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 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.

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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, 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 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. 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”)

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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 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. A small percentage 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.

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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 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 is likely to limit our ability to, among other things:

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incur or guarantee additional debt;

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redeem or repurchase units or make distributions under certain circumstances;

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make certain investments and acquisitions;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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merge or consolidate with another company; and

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transfer, sell or otherwise dispose of assets.

Our new credit facility also will likely 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 $ million under our new credit facility to repay approximately $ of the debt assumed from Tallgrass Development and to pay $ 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 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:

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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;

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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;

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

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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

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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 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

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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 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

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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 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

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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 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.

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Risks Inherent in an Investment in Us

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:

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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.

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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 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.

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All of the initial officers and a majority of the 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.

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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.

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

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

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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.

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Index to Financial Statements

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.

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

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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.

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Our partnership agreement permits us to classify up to $ 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.

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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.

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

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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.

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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.

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

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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 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.

Index to Financial Statements

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.”

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

Index to Financial Statements

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 closing of this offering, affiliates of our general partner will own, direct or indirectly, approximately % of our outstanding common units and % 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 publicly traded common units, assuming no exercise of the underwriters’ over-allotment option. In addition, affiliates of our general partner will own common units and subordinated units, representing an aggregate of approximately % 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:

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the level of our quarterly distributions;

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

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the loss of a large customer;

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

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

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general economic conditions;

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

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future sales of our common units; and

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other factors described in these “Risk Factors.”

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

The estimated initial public offering price of $ 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 $ per unit. Based on the estimated initial public offering price of $ per common unit, you will incur immediate dilution of $ 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.”

Index to Financial Statements

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.”

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 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:

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how to allocate business opportunities among us and its affiliates;

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whether to exercise its limited call right;

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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;

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

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whether to elect to reset target distribution levels;

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

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

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:

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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

Index to Financial Statements

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;

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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;

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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:

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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;

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

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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

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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.

Index to Financial Statements

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 closing of this offering to be able to prevent its removal. The vote of the holders of at least 66²/₃% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Following the closing of this offering, Tallgrass Development will own an aggregate of approximately % 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 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 and persons who acquired such units with the prior approval of the board of directors of our general partner, 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 in a merger or in a sale of all or substantially all of its assets 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.

Index to Financial Statements

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:

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

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

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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;

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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;

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

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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 common units and 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.

Index to Financial Statements

investment. You may also incur a tax liability upon a sale of your units. At the closing 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 % 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 % 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 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

Index to Financial Statements

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:

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

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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 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.

Index to Financial Statements

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.

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 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

Index to Financial Statements

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 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.

Index to Financial Statements

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 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

Index to Financial Statements

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 % of the total interests in our capital and profits. Therefore, a transfer by Tallgrass Development of all or a portion of its 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

Index to Financial Statements

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.

Index to Financial Statements

USE OF PROCEEDS

•

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

•

pay approximately $ million in revolving credit facility origination fees;

•

pay the structuring fee and offering expenses payable by us of approximately $ million; and

•

pay $ 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 alternative 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 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 $ 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 $ per common unit would cause the net proceeds from this offering, after deducting underwriting discounts, to increase or decrease, respectively, by approximately $ 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.

Index to Financial Statements

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 $ 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 $ million of debt from Tallgrass Development, the application of the net proceeds of this offering and borrowing of approximately $ 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	$	—	$

Long-Term Debt:
Debt allocated from Tallgrass Development		390,491		—
Revolving Credit Facility		—
Partners’ capital:
Predecessor Members’ equity	$	571,834	$
Common units—public(2)		—
Tallgrass Development—
– Common units(2)		—
– Subordinated units		—
General partner units		—

Total members’ equity/partners’ capital		571,834

Total capitalization	$	962,325	$

(1)	On a pro forma basis, as of December 31, 2012, the public would have held common units, Tallgrass Development would have held an aggregate of common units and subordinated units, and our general partner would have held general partner units.

(2)

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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 $ million, or $ 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		$
Pro forma net tangible book value per unit before this offering(1)	$
Decrease in pro forma net tangible book value per unit attributable to purchasers in this offering

Less: Pro forma net tangible book value per unit after this offering(2)

Immediate dilution in pro forma net tangible book value per unit attributable to purchasers in this offering(3)(4)		$

(1)	Determined by dividing the number of units ( common units, subordinated units and general partner units) to be issued to subsidiaries of Tallgrass Development for its contribution of assets and liabilities to Tallgrass Energy Partners, LP into predecessor historical capital.

(2)

Determined by dividing the total number of units to be outstanding after this offering ( common units, subordinated units and 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.

(3)	If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $ and $ , respectively.

(4)

Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will be distributed to Tallgrass Development, there will be no change to the dilution in net tangible book value per common unit to purchasers in this offering due to any such exercise of the option.

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
Common Units owned by our general partner and its affiliates(1)(2)(3)				%	$			%
Public Common Units				%	$			%

Total	$		100.0	%	$		100.0	%

(1)	The units acquired by our general partner and its affiliates consist of common units, subordinated units and general partner units.

(2)	Assumes the underwriters’ option to purchase additional common units is not exercised.

Index to Financial Statements

(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 millions)
Book value of net assets contributed		$
Less: Payment to Tallgrass Development for capital expenditures(a)
Total consideration		$

(a)

At the closing of the offering, we intend to make a payment of $ 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.

Index to Financial Statements

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

Index to Financial Statements

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 closing of this offering, assuming no exercise of the underwriters’ option to purchase additional units, Tallgrass Development will own approximately % of our outstanding common units and all of our outstanding subordinated units, representing an aggregate % 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 $ 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

Index to Financial Statements

growth may not be as fast as that of businesses that reinvest their available cash to expand 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 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 $ per unit for each whole quarter, or $ per unit on an annualized basis. This represents an aggregate cash distribution of approximately $ million per quarter, or approximately $ million on an annualized basis, based on the number of common, subordinated and general partner units expected to be outstanding immediately after the closing 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 , 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 immediately after this offering for one quarter and on an annualized basis is summarized in the table below:


	Number of Units	Minimum Quarterly Distributions
	Number of Units	One Quarter	Annualized
		(in millions)
Publicly held common units(1)
Common units held by Tallgrass Development(1)
Subordinated units held by Tallgrass Development
General partner units held by our general partner

Total

(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 $ 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.

Index to Financial Statements

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.

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 $ 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 $54.9 million. This amount would have been sufficient to pay the minimum quarterly distribution of $ per unit per quarter ($ per unit on an annualized basis) on all of our common units and subordinated units for such period. This amount would exceed by $ million the amount needed to pay the total annualized minimum quarterly distribution of $ 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

Index to Financial Statements

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.

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:	$	42.4
Add:
Depreciation and amortization		25.2
Interest expense, net(1)		9.1

Less:
Estimated incremental general and administrative expenses		2.5

Pro Forma Adjusted EBITDA(2)	$	74.1

Less:
Cash interest paid(3)		10.2
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	$	54.9

Annualized minimum quarterly distribution per unit
Distributions to public common unitholders
Distributions to Tallgrass Development, LP—common units
Distributions to Tallgrass Development, LP—subordinated units
Distributions to general partner
Total distributions to our unitholders and general partner


Excess (Shortfall)
Percent of minimum quarterly distribution payable to common unitholders

Percent of minimum quarterly distribution payable to subordinated unitholders

(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

Index to Financial Statements

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%.

(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 $62.0 million. This amount would exceed by $ million the amount needed to pay the total annualized minimum quarterly distribution of $ 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

Index to Financial Statements

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.

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.”

Index to Financial Statements

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)
Total Revenues(2)	$	300.2		$	(1.7	)	$	—		$	298.5
Operating costs and expenses:
Cost of sales and transportation services(3)		153.2			7.2			(7.2	)		153.2
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		252.3			2.7			(7.2	)		247.9

Operating income		47.9			(4.4	)		7.2			50.7
Interest expense, net(8)		(9.2	)		2.3			—			(6.8	)
Other income (expense), net		1.5			—			—			1.5

Net Income to partners	$	40.3		$	(2.1	)	$	7.2		$	45.4

Interest expense, net(8)		9.2			(2.3	)		—			6.8
Depreciation and amortization		30.0			(2.3	)		—			27.7

Adjusted EBITDA(9)	$	79.4		$	(6.7	)	$	7.2		$	79.9

Less:
Cash interest paid		10.7			(2.3	)		—			8.4
Maintenance capital expenditures(10)		9.4			—			—			9.4
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	$	59.3		$	(58.0	)	$	60.8		$	62.0
Annualized minimum quarterly distribution per unit
Distributions to public common unitholders
Distributions to Tallgrass Development, LP—common units
Distributions to Tallgrass Development, LP—subordinated units
Distributions to general partner
Total distributions to our unitholders and general partner

Excess (Shortfall)

(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

Index to Financial Statements

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 a $3.2 million increase in general and administrative expenses reflecting our cost structure in comparison to that of Kinder Morgan, as well as $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 $2.4 million decrease ($3.6 million on an annualized basis) in interest expense as a result of our receipt of an estimated $90.3 million purchase price 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 $62.0 million. This amount of estimated cash available for distribution is approximately $7.2 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.

Index to Financial Statements

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 proceeds of 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 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.

We expect to use all proceeds from the upfront payment of the actual net book value of the Pony Express Assets to pay down borrowings under our revolving credit facility. 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 $2.4 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.”

Index to Financial Statements

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	$	31.5
Maintenance capital expenditures		1.9		2.6
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)		116		168
Gross NGL production (MBbl/d)		6.3		10.1
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, 60 MMcf/d is included based on assumed renewals of existing contracts and 166 MMcf/d is included based on new contracts that we expect to enter

Index to Financial Statements

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.”

Index to Financial Statements

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 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 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 $ 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 $298.5 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.

Index to Financial Statements

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 87% 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.

•

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 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 73% 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, these customers have tended to renew contracts at or near their existing reserved capacity. Only 59 MMcf/d of the firm contracted capacity we have assumed for the forecast period is scheduled to expire during the forecast period, all of which is currently contracted with customers we categorize as “on-system” customers. Our

Index to Financial Statements

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 4.3 years and for firm storage contracts is approximately 2.0 years, which we believe offers substantial certainty of cash flows during and beyond the forecast period. In addition, of the remaining 27% of projected revenue from off-system customers, 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.

LOGO

(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 50 MMcf/d, 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 $188.1 million in total revenues and approximately $143.9 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 $44.2 million. The expected $49.1 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.

•

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

Index to Financial Statements

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 28% and 72% 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 20% and 80% for the year ended December 31, 2012. 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.

Index to Financial Statements

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 $153.2 million for the twelve-month period ending June 30, 2014, an increase of $36.9 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.

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 $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 $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.

Index to Financial Statements

Depreciation and Amortization

We estimate depreciation and amortization expense for the twelve-month period ending June 30, 2014 of $27.7 million as compared to $24.7 million for the year ended December 31, 2012. 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 $9.4 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 $9.4 million is generally indicative of the average annual maintenance capital requirement going forward. This forecasted figure is lower than levels experienced in recent periods 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 $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 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 $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 $8.4 million for the twelve-month period ending June 30, 2014. The difference of $1.6 million between forecasted interest expense and forecasted cash interest

Index to Financial Statements

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 $ million of net proceeds from this offering plus approximately $ million of revolver borrowings to pay estimated offering expenses of $ , retire $ million of debt assumed from Tallgrass Development and to pay $ 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 $ 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 $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 expenses of $1.8 million.

•

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

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.

Index to Financial Statements

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 and for anticipated future credit subsequent to that quarter);

•

comply with applicable law, 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 $ per unit, or $ 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.

Index to Financial Statements

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 be represented by 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 $ 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:

•

$ 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), 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 operating surplus 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, 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 finance the expansion capital expenditures referred to in the prior bullet; less

•

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

•

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.

Index to Financial Statements

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 $ 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;

•

investment capital expenditures;

•

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

•

distributions to our partners;

•

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.”

Index to Financial Statements

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.

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.

Index to Financial Statements

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 $ 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 , 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 $ (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 $ (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 , 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 $ 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) $ 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.

Index to Financial Statements

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 , 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 $ 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) $ 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 , 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 $ 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) $ 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;

•

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; and

•

our general partner will have the right to convert its general partner interest and its IDRs into common units or to receive cash in exchange for those interests.

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.

Index to Financial Statements

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.

Index to Financial Statements

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 $ 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 $ 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 $ 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

Index to Financial Statements

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
	Total Quarterly Distribution per Unit Target Amount		Unitholders			General Partner
Minimum Quarterly Distribution		$		98.0	%		2.0	%
First Target Distribution	above $	up to $		98.0	%		2.0	%
Second Target Distribution	above $	up to $		85.0	%		15.0	%
Third Target Distribution	above $	up to $		75.0	%		25.0	%
Thereafter	above $			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.

Index to Financial Statements

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 $ .


	Quarterly Distribution per Unit Prior to Reset		Marginal Percentage Interest in Distribution									Quarterly Distribution per Unit following Hypothetical Reset
	Quarterly Distribution per Unit Prior to Reset		Unitholders			2% General Partner			Incentive Distribution Rights
Minimum Quarterly Distribution		$		98.0	%		2.0	%				$
First Target Distribution		above $ up to $		98.0	%		2.0	%					above $ up to $	(1)
Second Target Distribution		above $ up to $		85.0	%		2.0	%		13	%		above $ up to $	(2)
Third Target Distribution		above $ up to $		75.0	%		2.0	%		23	%		above $ up to $	(3)
Thereafter		above $		50.0	%		2.0	%		48	%		above $

(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.

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 common units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit would be $ 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

—

First Target Distribution

above $ up to $

—

Second Target Distribution

above $ up to $

Third Target Distribution

above $ up to $

Thereafter

above $

Index to Financial Statements

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 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 $ . The number of common units issued as a result of the reset was calculated by dividing (x) $ 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 $ .

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

—

First Target Distribution

above $

up to $

—

Second Target Distribution

above $

up to $

—

Third Target Distribution

above $

up to $

—

Thereafter

above $

—

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until the minimum quarterly distribution is reduced to zero, as described below under “—Effect of a Distribution from Capital Surplus”;

•

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 of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

•

thereafter, as if such distributions were from operating surplus.

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.

Effect of a Distribution from Capital Surplus

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. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital

Index to Financial Statements

surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the IDRs.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•

the minimum quarterly distribution;

•

target distribution levels;

•

the unrecovered initial unit price;

•

the number of general partner units comprising the general partner interest; and

•

the arrearages in payment of the minimum quarterly distribution on the common units

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50.0% of its initial level, and each subordinated unit would be split into two subordinated units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our

Index to Financial Statements

liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the IDRs of our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

•

first, to our general partner to the extent of any negative balance in its capital account;

•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•

fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;

•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;

•

sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;

•

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

The percentages set forth above are based on the assumption that our general partner has not transferred its IDRs and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

100

Index to Financial Statements

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

•

first, 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

•

second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

•

thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

101

Index to Financial Statements

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The summary pro forma financial data presented as of and for the year ended December 31, 2012 was derived from the 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 closing 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:

•

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

•

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

•

the issuance of common units to the public in this offering, representing a % limited partner interest in us ( % 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 origination fees related to our new revolving credit facility and to retire $ of the debt assumed from Tallgrass Development, as described in “Use of Proceeds,” and

•

the closing of our new $ million revolving credit facility under which we expect to borrow $ million at the closing of this offering to repay the remaining approximately $ million of debt assumed from Tallgrass Development and to pay $ 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.

102

Index to Financial Statements

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			25,162
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			204,585

Operating income		75,499			50,113			1,311			50,995
Other income (expense), net(2)		203			1			482			483
Interest income (expense), net(3)		2,101			1,661			(3,201	)		(9,103	)

Income (loss) before income taxes		77,803			51,775			(1,408	)		42,375
Texas margin taxes(4)		296			279			—			—

Net Income (Loss) to Member	$	77,507		$	51,496		$	(1,408	)	$	42,375

Net income per limited partners’ unit:
Common units
Subordinated units

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			1,026,362
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			732,073

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	)		—

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 inlet volumes		101			122			127

103

Index to Financial Statements

(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)

(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

•

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.

104

Index to Financial Statements


	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	)	$	42,375
Add:
Interest (income) expense, net		(2,101	)		(1,661	)		3,201			(9,103	)
Depreciation and amortization expense		22,726			20,647			4,086			25,162
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

105

Index to Financial Statements

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical financial statements included in this prospectus reflect the combined results of operations of Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC, which we refer to collectively as our “Predecessor.” In connection with this offering, Tallgrass Development will contribute to us its equity interests in our Predecessor. The following discussion analyzes the financial condition and results of operations of our Predecessor. In certain circumstances and for ease of reading we discuss the financial results of the Predecessor as being “our” financial results during historic periods, although our Predecessor was owned by Kinder Morgan prior to Tallgrass Development’s acquisition from Kinder Morgan in November 2012.

The following discussion and analysis should be read in conjunction with the historical and pro forma combined financial statements and related notes included elsewhere in this prospectus. For more detailed information regarding the basis of presentation for the following information, please read the notes to the historical and pro forma combined financial statements included elsewhere in this prospectus. In addition, please read “Forward-Looking Statements” and “Risk Factors” for information regarding certain risks inherent in our business.

Overview

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 construction of additional assets.

Our reportable business segments are:

•

Gas Transportation and Storage—the ownership and operation of interstate natural gas pipelines and integrated natural gas storage facilities that provide services primarily to on-system customers such as third-party LDCs, industrial users and other shippers; and

•

Processing—the ownership and operation of natural gas processing, treating and fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets.

How We Evaluate Our Operations

We evaluate our results using, among other measures, contract mix and volumes, operating costs and expenses and Adjusted EBITDA.

Contract Mix and Volumes

Our results are driven primarily by the volume of natural gas transportation and storage capacity under firm contracts, the volume of natural gas that we process and the fees assessed for such services.

Gas Transportation and Storage

Firm service

One of our primary operational goals is to maximize the portion of our physical transportation and storage capacity that is contracted under multi-year firm contracts in order to enhance the stability of our revenues and

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Index to Financial Statements

cash flows. We provide a significant portion of our transportation and storage services through firm contracts and derive a small portion of our revenues through interruptible service contracts. To the extent that physical capacity that is contracted by firm service customers is not being fully utilized or there is excess capacity that is not contracted for firm service, we can offer such capacity to interruptible service customers.

Firm transportation service allows the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm transportation contracts obligate our customers to pay a fixed monthly charge to reserve an agreed-upon amount of pipeline capacity regardless of the actual pipeline capacity used by the customer during each month, which we refer to as a monthly reservation charge. In addition to monthly reservation charges, we also collect usage charges when a firm transportation customer uses the capacity it has reserved under these firm transportation contracts. Usage charges are assessed on the actual volume of natural gas transported on the transportation system. In addition, firm transportation customers are charged an overrun usage charge when the level of natural gas received for delivery from a firm transportation customer exceeds its reserved capacity.

Firm storage contracts obligate our customers to pay a fixed monthly reservation charge for the right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Firm storage customers are also assessed usage charges for the actual quantities of natural gas injected into or withdrawn from storage.

We generate a high percentage of our transportation and storage services revenue from reservation charges under long-term, fee-based contracts, which mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices.

Interruptible service

Interruptible transportation and storage service is typically short-term in nature and is generally used by customers that either do not need firm service, have been unable to contract for firm service or require transportation volumes in excess of their contracted firm service. Interruptible customers and firm customers that overrun their reserved capacity level are not guaranteed capacity or service on the applicable pipeline and storage facilities. To the extent that firm contracted capacity is not being fully utilized or there is excess capacity that has not been contracted for firm service, the system can allocate such excess capacity to interruptible services. FERC-regulated transportation and storage operators are obligated to provide interruptible services only if a shipper is willing to pay our FERC-approved tariff. We believe that our interruptible services are competitively priced in order to be in a position to capture short-term market opportunities as they occur. Included in our interruptible transportation and storage services is our natural gas ‘‘park and loan’’ services to assist customers in managing short-term natural gas surpluses or deficits. Under our park and loan service agreements, customers are charged a usage fee based on the quantities of natural gas they store in (park), or borrow from (loan), our storage facilities.

Natural gas sales

We collect a small portion of the natural gas transported on our pipelines by our customers pursuant to our FERC-approved tariff as a contractual fee to compensate us for fuel consumed by transportation and storage operations. The contractual fee associated with these volumes of gas is recorded as transportation services revenue at market prices when the gas is received. These volumes are typically sold thereafter, and the revenues received from these sales are recorded as natural gas sales revenue for our Gas Transportation and Storage segment. These natural gas sales typically fluctuate significantly from period-to-period due to changes in the market price of natural gas and the volume of natural gas transported and stored in our system. Further, the percentage of gas we are permitted to collect from our customers is subject to review by FERC and may be challenged by our customers. We enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our natural gas purchases and sales in our Gas Transportation and Storage segment,

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which expose us to risks associated with changes in the market price of natural gas. Our hedging program is designed to mitigate our exposure to changes in natural gas prices from the time we collect gas from our customers until it is sold to third parties.

Processing

Processing contracts

Our processing services are typically provided pursuant to contracts featuring characteristics of one, or a combination of more than one, of the following contractual arrangements.

Percent of Proceeds. Percent of proceeds contracts are those under which we process our customer’s natural gas, sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. A portion of our percent of proceeds contracts also require our customer to pay a monthly reservation fee for capacity at our processing facilities.

Fee-based. Fee-based contracts are those under which we receive a fixed fee and/or a volumetric-based fee rate, which are typically tied to reserved capacity or inlet volumes.

Keep Whole. Keep whole provisions constitute the third major component of our contract mix at the Midstream Facilities. Under these 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 and retain, for our account, the remaining portion of the products we process.

For additional information regarding our exposure to changes in commodity prices under our percent of proceeds and keep whole arrangements, see “—Quantitative and Qualitative Discussions about Market Risk—Commodity Price Risk.”

NGL Sales

NGL sales in the Processing segment consist of the sale of outputs from our processing plants and the marketing of NGLs that are purchased from local suppliers. NGL revenues are recognized when goods are delivered and title has passed to the customer.

Natural Gas Sales

We also purchase natural gas in the Processing segment primarily for use in our operations and, as described above under “—Keep whole,” for meeting contractual requirements to deliver natural gas to certain customers. In addition, as described above, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased.

Operating Costs and Expenses

The primary components of our operating costs and expenses that we evaluate include cost of sales and transportation services, operations and maintenance and general and administrative. Our operating expenses in the transportation and storage segment are driven primarily by expenses related to the maintenance and growth of our asset base.

Cost of sales and transportation services

Cost of sales and transportation services in the Gas Transportation and Storage segment primarily consists of the cost of natural gas sales, which fluctuates with changes in market prices. A certain amount of natural gas can be lost in connection with its transportation and related measurement across a pipeline system, and under our

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contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to operate our system. These volumes of gas that are retained from our customers are recorded as transportation services revenue when received. The gas that remains after accounting for lost and unaccounted for volumes and natural gas used to operate our system is subsequently recorded as natural gas sales revenue and cost of sales and transportation services when sold.

In the Processing segment, cost of sales and transportation services is primarily comprised of NGL and natural gas purchases and settlements. NGL and natural gas settlements represent proceeds from sales of NGLs and residue natural gas remitted back to the suppliers of our inlet gas which offsets a substantial portion of the revenues we record for the NGLs and residue natural gas we retain pursuant to these contracts. NGL purchases occur when we buy NGLs directly from our suppliers and then process and remarket the NGLs for our own account. Natural gas purchases represent the cost of natural gas purchased for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers.

Operations and maintenance

Operations and maintenance expense is comprised primarily of fuel and power costs and employee, insurance and environmental and safety costs. The timing of maintenance expenditures during a year generally fluctuates with customer demands and we schedule as much planned maintenance as possible during off-peak periods, including annual major maintenance that typically occurs in the fall months. Changes in regulation can also impact maintenance requirements and affect the timing and amount of our costs and expenditures.

General and administrative expense

In our historical financial statements, general and administrative expense included direct costs incurred by TEP Predecessor on our behalf and various direct and indirect cost allocations from Kinder Morgan. In the future, we expect general and administrative expense to be comprised primarily of similar direct and indirect costs that we will reimburse to our general partner and Tallgrass Development’s general partner and its affiliates pursuant to our partnership agreement and the omnibus agreement, and other expenses attributable to our status as a publicly traded partnership, such as: 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.

Adjusted EBITDA and Distributable Cash Flow

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. Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA less net cash paid for interest expense and maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances. Distributable cash flow and Adjusted EBITDA are not presentations made in accordance with GAAP.

Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of our combined 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, in the case of Adjusted EBITDA, financing methods;

•

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

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•

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 expansion and growth opportunities.

We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see ‘‘Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

Factors and Trends Impacting Our Business

We expect to continue to be affected by certain key factors and trends described below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. Please read “Risk Factors.”

U.S. Natural Gas Supply and Demand Dynamics

Natural gas continues to be a critical component of energy supply and demand in the United States. Recently, the price of natural gas has been at historically low levels, with the prompt month NYMEX natural gas futures price reaching $4.07 per MMBtu as of March 14, 2013, compared to a high of $8.27 per MMBtu on January 29, 2008. The lower price of natural gas is due primarily to increased production, especially from unconventional sources such as natural gas shale plays, high levels of natural gas in storage, warm winter weather and the lingering effects of the economic downturn starting in 2008. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,347 as of December 26, 2008 to approximately 431 as of December 28, 2012 according to Baker Hughes, as a number of producers have curtailed their exploration and production activities. We believe that until the supply overhang has been reduced and the economy sees more robust growth, natural gas pricing is likely to be constrained.

Over the long term, however we believe that the prospects for natural gas production increases are favorable and will be driven in part by increased demand resulting from population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation due to the low prices of natural gas and stricter government environmental regulations on the mining and burning of coal. For example, according to the U.S. Energy Information Administration, or EIA, in 2010, 45% of the electricity in the United States was generated by coal-fired power plants and in 2012, 38% of the electricity in the United States was generated by coal-fired power plants. In addition, the EIA’s 2013 Annual Energy Outlook projects that annual natural gas consumption will increase by approximately 12.2% from 24.3 quadrillion Btu in 2010 to 27.3 quadrillion Btu in 2025 and that annual natural gas production will increase by approximately 33.9% from 21.8 quadrillion Btu in 2010 to 29.2 quadrillion Btu in 2025.

Growth in Production from Niobrara Shale Play

Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional resources (defined by the EIA as natural gas produced from shale formations

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and coalbeds), such as the Niobrara shale. According to Wood Mackenzie, in the Denver Julesburg Basin, Niobrara shale production of natural gas is expected to increase 65.8% from 913 MMcf/d in 2012 to 1514 MMcf/d in 2017, and in the Powder River Basin, Niobrara shale production of natural gas is expected to increase 391% from 23 MMcf/d in 2012 to 113 MMcf/d in 2017. Given the proximity of our Midstream Facilities to the Niobrara shale play and the fact that our Midstream Facilities provide straddle processing to the TIGT System, we believe that production growth in the Niobrara shale play will benefit our Midstream Facilities and, to a lesser extent, the TIGT System with increased throughput volumes.

Growth Associated with Acquisitions and Expansion Projects

Growth associated with acquisitions

We believe that we are well-positioned to grow through accretive acquisitions, both from Tallgrass Development and from third parties. We intend to review acquisition opportunities from third parties as they become available and to pursue acquisitions from Tallgrass Development that we expect will be primarily sourced from Tallgrass Development’s portfolio of Retained Assets, which following the completion of this offering will include the Pony Express Project (following our proposed abandonment and sale), the Trailblazer Pipeline and a 50% interest in the REX Pipeline. Pursuant to the omnibus agreement, Tallgrass Development will grant to us a right of first offer to acquire each of the remaining Retained Assets if Tallgrass Development decides to attempt to sell such Retained Asset. We expect each Retained Asset to be offered to us under the right of first offer provisions of the omnibus agreement as each Retained Asset matures into an operating profile more conducive to our principal business objective, which is typically characterized by a stable cash flow profile. Although it is uncertain when Tallgrass Development will offer us the opportunity to acquire any of the Retained Assets or whether they will ever choose to sell any of the Retained Assets, we have described below our management’s current expectations as to the potential timing of opportunities to acquire the Retained Assets and the factors affecting such timing.

•

We anticipate the Trailblazer Pipeline will be the first Retained Asset offered to us by Tallgrass Development, subject, in part, to Trailblazer acceptably resolving certain outstanding issues under its FERC tariff.

•

We believe Tallgrass Development will offer us the opportunity to purchase the Pony Express Project in whole or in part at some point after the crude oil pipeline is placed in service (which is currently expected to be in the second half of 2014).

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We do not have any expectation about when Tallgrass Development would offer all or any part of its 50% interest in the REX Pipeline to us.

We do not have a right of first offer to acquire any other assets or business opportunities from Tallgrass Development besides the Retained Assets.

Growth associated with expansion projects

As production and demand for our services increase in our areas of operations, we believe that we are well-positioned to attract volumes to our systems through cost-effective capacity expansions. For example, we are currently undertaking an expansion of our Casper and Douglas plants to increase processing capacity from 138.5 MMcf/d to 188.5 MMcf/d and to increase our fractionation capabilities from 2,000 barrels per day to 3,500 barrels per day. This expansion project is estimated to cost an aggregate of approximately $48 million, all of which is expected to have been expended by December 31, 2013.

Transportation and Storage Customers

Currently, the customers on the TIGT System primarily consist of on-system customers such as LDCs and industrial users, including ethanol plants and irrigation and grain drying operations, which value the TIGT System’s proximity to customer facilities and extensive footprint in the Midwest. LDCs and industrial users

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typically require a secure and reliable supply of natural gas over a sustained period of time to meet the needs of their customers and, as a result, these types of customers are incentivized to enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract based on their maximum peak usage rather than their average usage requirements.

Historically, some of the customers on the TIGT System used the TIGT System to access other interstate pipelines for ultimate delivery to consuming markets outside of our areas of operations. Some of these customers entered into short-term transportation and storage agreements with us. Over the last several years, some of these customers have opted not to renew their contracts on the TIGT System. 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. As a result, we have seen a decline in the overall volumes transported on the TIGT System over the past several years. However, a significant portion of our current customer base is comprised of on-system customers, with approximately 65% of our transportation and storage revenue generated under contracts with on-system customers during the year ended December 31, 2012. 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 our customer base has shifted away from large producers to LDCs and other on-system customers, we have seen significant increases both in the weighted average remaining life of our contract portfolio and the percentage of our customers that have historically exhibited a tendency to renew their contracts. Of our top ten transportation and storage customers by revenue for the year ended December 31, 2012, which collectively contributed approximately 64% of our total transportation and storage revenue for that period), six have been our customers for over 20 years, including prior to deregulation of the U.S. natural gas pipeline industry. The revenue-weighted average relationship tenure of the remaining four of our top ten customers for the same period is approximately 13 years, with each having been a customer for at least six years. Given the high percentage of our transportation revenue that is derived from on-system customers, and the tendency of these customers to renew their contracts in the past, we believe that our transportation services revenues have largely stabilized.

Regulation

Government regulation, particularly regulation of natural gas storage and transportation assets, can have a significant impact on our business. For example, the permitting processes at all government levels, including the FERC, impact our ability to obtain the approvals and permits required to construct new infrastructure. These processes are increasingly impacted by political, environmental and other concerns that can significantly delay or increase the cost of obtaining the approvals and permits required to expand our operations. Other federal, state and local regulation can also impact our operations, cost structure and profitability, which could in turn impact our financial performance and our ability to make distributions to our common unitholders. As a result, we closely monitor regulatory developments affecting our business.

Access to capital markets

We require periodic access to capital in order to fund acquisitions and expansion projects. Under the terms of our partnership agreement, we are required to distribute our available cash to our unitholders, which makes us dependent upon raising capital to fund growth projects. Historically, master limited partnerships have accessed the debt and equity capital markets to raise money for new growth projects and acquisitions. Market conditions can either raise the cost of capital markets financing or, in some cases, even make such financing unavailable. If we are unable either to access the capital markets or find alternative sources of capital, our growth strategy may be more challenging to execute.

Interest Rates

The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on floating rate credit facilities and future offerings in the debt capital markets could be higher than current levels, causing our financing costs to increase accordingly.

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In addition, there is a financing cost for the storage capacity user to carry the cost of the inventory while it is stored in the facility. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user as well as the commodity cost of the natural gas in inventory. The higher the financing cost, the lower the margin that will be left over from the price spread that was intended to be captured. Accordingly, a significant increase in interest rates could impact the demand for storage capacity independent of other market fundamentals.

Rising Operating Costs and Inflation

The current high level of natural gas exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This may ultimately increase the prices we pay for labor, supplies, property and equipment. An increase in the general level of prices in the economy could have a similar effect. We may be unable to recover all of these increased costs from our customers. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

Factors Impacting the Comparability of Our Financial Results

The following factors may affect the comparability of our historical results of operations as well as the comparability of our historical results to future results:

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Increased Fee-based Component of Processing Contract Portfolio. We intend to continue to pursue opportunities to increase the fee-based component of our contract portfolio through contract renewal negotiations, acquisitions or other growth projects. Increasing the fee-based component of our processing contract portfolio reduces the volatility of our processing segment gross margin over time.

•

2011 Gas Sale. In the third quarter of 2011, as a result of capital improvements to our natural gas storage facility, including additional compression, the operational requirements of our natural gas storage facility allowed us to sell 2.0 Bcf of natural gas that had historically been required to be kept in inventory in order to operate the facility. This one-time sale generated revenue of $8.1 million and Adjusted EBITDA of $7.0 million in 2011, and we do not expect similar sales in the future.

•

Section 5 Settlement. In September 2011, the FERC approved a settlement of the Section 5 proceeding related to the TIGT System. The settlement resolved all issues in the proceeding and provided shippers on the TIGT System with prospective reductions in the fuel and gas and lost and unaccounted for rates, referred to as the Fuel Retention Factors, effective June 1, 2011. The Settlement resulted in a 27% reduction in the Fuel Retention Factors billed to shippers effective June 1, 2011, as compared to the Fuel Retention Factors approved and in effect on March 1, 2011. The 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.

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Pony Express 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 completion of 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 for a minimum period of 5 years, and up to 10 years, 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. We expect to use

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all proceeds from the upfront payment of the actual net book value of the Pony Express Assets to pay down borrowings under our revolving credit facility. 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. Our Predecessor’s results of operations include the Pony Express Assets, however we expect to complete the Pony Express Abandonment in the fourth quarter of 2013 and the Pony Express Assets will not be reflected in our results of operations following the Pony Express Abandonment. We expect the abandonment and sale of the Pony Express Assets will reduce our interest expense as we expect to use the estimated $90.3 million in sale proceeds from Tallgrass Development to pay down borrowings under our revolving credit facility; otherwise, the Pony Express Abandonment is not expected to have a material impact on our results of operations.

•

General and Administrative Expenses. Our Predecessor’s general and administrative expenses included charges for the management and operation of our business and certain expenses allocated for general corporate services, such as finance, internal audit and legal services. These expenses were charged or allocated to our Predecessor based on the nature of the expenses and our Predecessor’s proportionate share of employee time and headcount. Following the closing of this offering, Tallgrass Development will charge us directly for the management and operation of our business. We expect to incur an additional $3.2 million of general and administrative expenses, largely reflecting Kinder Morgan’s scale advantage in supporting similar required administrative functions by a substantially larger number of operated businesses. We also expect to incur additional general and administrative expenses of approximately $2.5 million annually as a result of being a publicly traded partnership, consisting of costs associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, Sarbanes-Oxley Act compliance, stock exchange listing, registrar and transfer agent fees, incremental director and officer liability insurance and director compensation. These additional general and administrative expenses are not reflected in our historical or our pro forma financial statements.

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Financing. There are differences in the way we will finance our operations going forward as compared to the way our Predecessor financed its operations. Historically, our Predecessor’s operations were financed as part of its larger operations and corporate structure and our predecessor did not record any separate costs associated with financing its operations. Following the closing of this offering, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future expansion capital expenditures primarily from external sources, including borrowings under our new revolving credit facility and issuances of equity and debt securities. In connection with the closing of this offering, we expect to enter into a $ million revolving credit facility. The revolving credit facility will be available for general partnership purposes, including working capital, capital expenditures and acquisitions.

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Index to Financial Statements

Results of Operations

The following provides a summary of our results of operations for our Predecessor for the periods indicated:


	TEP Pre-Predecessor				TEP Predecessor
	Year Ended Dec 31,		Period From Jan 1 to Nov 12,		Period From Nov 13 to Dec 31,
	2011		2012		2012
	(in thousands, except per unit and operating data)
Statements of Operations Data
Revenues:
Natural gas liquids sales	$	151,627	$	106,355	$	18,554
Natural gas sales		28,339		15,634		1,910
Transportation services		123,018		93,214		13,102
Other operating revenues		4,059		5,089		1,722

Total revenues		307,043		220,292		35,288
Operating costs and expenses:
Cost of sales and transportation services		146,069		98,585		17,711
Operations and maintenance		37,345		32,768		3,940
Depreciation and amortization		22,726		20,647		4,086
General and administrative		16,044		11,318		7,133
Taxes, other than income taxes		9,360		6,861		1,107

Total operating costs and expenses		231,544		170,179		33,977

Operating income		75,499		50,113		1,311
Interest income (expense), net		2,101		1,661		(3,201	)
Other income (expense), net		203		1		482

Income (loss) before income taxes		77,803		51,775		(1,408	)
Texas margin taxes		296		279		—

Net Income (Loss)	$	77,507	$	51,496	$	(1,408	)

Other Financial Data
Adjusted EBITDA(1)		98,428		70,761		5,606
Capital Expenditure and Operating Data
Capital Expenditures:
Sustaining capital expenditures		13,443		6,218		2,845
Expansion capital expenditures		9,345		13,322		9,786
Operating Data: (Mmcf/d)
Transportation firm contracted capacity		795		762		702
Natural gas processing volumes		101		122		127

(1)	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.”

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	TEP Pre-Predecessor				TEP Predecessor
	Year Ended Dec 31,		Period From Jan 1 to Nov 12,		Period From Nov 13 to Dec 31,
	2011		2012		2012
	(in thousands, except per unit and operating data)

Segment Financial Data—Gas Transportation and Storage
Revenues:
Natural gas sales	$	25,475	$	9,814	$	208
Transportation services		123,619		93,910		13,198
Other operating revenues		42		278		6

Total revenues		149,136		104,002		13,412
Operating costs and expenses:
Cost of sales and transportation services		26,509		11,511		973
Operations and maintenance		27,549		24,492		3,059
Depreciation and amortization		19,751		17,895		3,263
General and administrative		13,785		8,994		5,662
Taxes, other than income taxes		8,632		6,547		1,065

Total operating costs and expenses		96,226		69,439		14,022

Operating income	$	52,910	$	34,563	$	(610	)

Segment Adjusted EBITDA		72,864		52,459		2,862
Segment Financial Data—Processing
Revenues:
Natural gas liquids sales	$	151,627	$	106,355	$	18,554
Natural gas sales		2,864		5,820		1,702
Other operating revenues		4,017		4,811		1,716

Total revenues		158,508		116,986		21,972
Operating costs and expenses:
Cost of sales and transportation services		120,161		87,770		16,834
Operations and maintenance		9,796		8,276		881
Depreciation and amortization		2,975		2,752		823
General and administrative		2,259		2,324		1,471
Taxes, other than income taxes		728		314		42

Total operating costs and expenses		135,919		101,436		20,051

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

Segment Adjusted EBITDA		25,564		18,302		2,744

Period from January 1 to November 12, 2012 Compared to the Year Ended December 31, 2011

Revenues. Total revenues were $220.3 million for the period from January 1 to November 12, 2012, compared to $307 million for the year ended December 31, 2011, which represents a 17% decrease in average monthly revenues. The decrease in average monthly revenues in the Gas Transportation and Storage segment and the Processing segment was 19% and 15%, respectively.

In the Gas Transportation and Storage segment, natural gas sales of $9.8 million in the period from January 1 to November 12, 2012 represent a 56% decrease in average monthly revenues compared to the year ended December 31, 2011. This decrease was attributable to a decrease in sales volumes attributable to the reduction in Fuel Retention Factors as a result of the Section 5 settlement that became effective on June 1, 2011 and a one-time sale of 2.0 Bcf of natural gas from storage in the third quarter of 2011 of approximately $8.1 million, partially offset by an increase in

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natural gas sales prices attributable to higher overall market prices. Excluding this one-time sale, natural gas revenues in the Gas Transportation and Storage segment would have been $17.3 million for the year ended December 31, 2011. In addition, a 12% decline in average monthly transportation services revenue during the 2012 period was attributable to lower throughput volumes. As described under “—Transportation and Storage Customers” above, we believe that our transportation 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 a large portion of our currently contracted firm capacity 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, these customers have tended to renew contracts at or near their existing reserved capacity. We do not expect any further decline in the number of transportation and storage customers to materially impact revenues in the Gas Transportation and Storage segment.

Lower revenues in the Processing segment were primarily attributable to a decrease in average monthly NGL sales in the 2012 period due to lower ethane revenue attributable to significantly lower market prices for this product in 2012 and a reduction in average monthly sales of other NGLs due to lower market prices. This was partially offset by higher monthly average natural gas sales and an increase in other operating revenues due to an increase in average monthly processing fees associated with increased volumes in the 2012 period. Although market prices for NGLs decreased during the period, our processing volumes increased due to the continuing trend of our customers focusing drilling for gas with higher NGL content.

Operating costs and expenses. Operating costs and expenses were $170.2 million for the period from January 1 to November 12, 2012 compared to $231.5 million for the year ended December 31, 2011, which represents a 15% decrease in average monthly operating costs and expenses. These decreases are attributable to lower cost of sales and transportation services in both segments and lower general and administrative expenses in the Gas Transportation and Storage segment.

The 17% decrease in average monthly cost of sales and transportation services in the Gas Transportation and Storage segment is attributable to lower sales of natural gas volumes due to the reduction in Fuel Retention Factors as a result of the Section 5 Settlement. In addition, the 25% reduction in average monthly general and administrative expenses in this segment was the result of one-time bonuses paid to all employees of Kinder Morgan in 2011 for attainment of a previously specified financial performance metric.

The Processing segment reported a 14% decrease in average monthly cost of sales and transportation services in the 2012 period. This decrease is attributable to lower market prices for purchased NGLs and natural gas.

Interest income, net. Interest income represents imputed interest on payments received from certain customers for reimbursement of the capital costs we incurred to connect these customers to our system. The level of interest income is decreasing over time as the balances due to us are being amortized.

Texas Margin Taxes. Our Predecessor incurred Texas Margin Taxes because it was a part of an affiliated group that generated sales in the State of Texas. Subsequent to our being acquired by Tallgrass in November 2012, we are no longer subject to Texas Margin Taxes or any other income-based taxes based on currently enacted tax legislation.

Period from November 13 to December 31, 2012 Compared to the Year Ended December 31, 2011

Revenues. Total revenues for the period from November 13 to December 31, 2012 were $35.3 million, which was comprised of $13.4 million in the Gas Transportation and Storage segment and $21.9 million in the Processing segment.

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The average monthly revenue in the Gas Transportation and Storage segment decreased by 33% compared to the average monthly revenue for the year ended December 31, 2011. In addition to the decrease in average monthly natural gas sales attributable to the one-time 2.0 Bcf natural gas sale in the third quarter of 2011 and the reduction in Fuel Retention Factors, each as described above, average monthly natural gas sales volumes decreased in the period from November 13 to December 31, 2012 due to seasonality. During this time of year, many of our customers are withdrawing natural gas from storage to meet increased levels of demand in the winter months. We typically sell lower volumes of our own gas during these periods in order to maintain the volumes of gas that are required for the operational needs of the storage facility. The lower average monthly revenue for the November 13 to December 31, 2012 period was attributable to a reduction in natural gas sales and in transportation services revenue.

In the Processing segment, average monthly revenue for the period November 13 to December 31, 2012 increased by 4% compared to the average monthly revenue in the year ended December 31, 2011. This increase was attributable to higher natural gas sales and processing fees attributable to a new processing contract executed in November 2012 with a significant customer.

Operating costs and expenses. Total operating costs and expenses for the period from November 13 to December 31, 2012 were $34.0 million, which represents a 10% increase compared to the average monthly operating costs and expenses for the year ended December 31, 2011. The most significant component of this increase in both segments was higher allocated general and administrative expenses attributable to approximately $2.3 million of transaction expenses related to the acquisition of the Predecessor Entities on November 13, 2012, as well as approximately $1.0 million of transition services and employee retention costs associated with the acquisition. In addition, depreciation and amortization was higher in both segments in the period from November 13 to December 31, 2012 due to the higher cost basis of property, plant and equipment as a result of the acquisition of the Predecessor Entities on November 13, 2012.

Interest income (expense), net. Interest expense represents the imputed interest, amortization of deferred financing costs and amortization of discount on the debt of Tallgrass Development that is related to its acquisition of the Predecessor Entities on November 13, 2012 and is pushed down to the balance sheet of TEP Predecessor. Interest income represents imputed interest on payments received from certain customers for reimbursement of the capital costs we incurred to connect these customers to our system. The level of interest income is decreasing over time as the balances due to us are being amortized.

Liquidity and Capital Resources

Overview

Our ability to finance our operations, fund capital expenditures, pay cash distributions to unitholders and satisfy our indebtedness obligations will depend on our ability to generate cash flow in the future. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. Please read “Risk Factors.”

Historically, our primary source of liquidity has been cash generated from operations. We also participated in Kinder Morgan’s centralized cash management system, whereby Kinder Morgan swept cash balances residing in our bank accounts on a daily basis and periodically the balances were settled and recorded as equity distributions. Therefore, our historical balance sheets do not reflect any cash balances. Following the acquisition from Kinder Morgan, Tallgrass Development implemented a similar cash management arrangement in which the subsidiary

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companies make loans on each business day equal to the amount swept from their depository bank accounts. At the beginning of the following month, the total of these loans for each company, less certain reimbursement payments, is transferred to an interest bearing account and are periodically recorded as equity distributions. As a result, prior to the completion of this offering, any cash balances residing in the bank accounts of Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC will be swept into Tallgrass Operations as part of Tallgrass Development’s cash management system and recorded as an equity distribution to Tallgrass Operations.

Following the completion of this offering, we expect our sources of liquidity to include:

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cash generated from our operations;

•

proceeds from the sale of the Abandoned Assets;

•

$ million available for borrowing under our revolving credit facility; and

•

future issuances of additional partnership units and debt securities.

We believe that cash on hand, cash generated from operations and availability under our credit facility will be adequate to meet our operating needs, our planned short-term capital and debt service requirements and our planned cash distributions to unitholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through borrowings under our credit facility or through issuances of debt and equity securities.

New Credit Facility

In connection with this offering, we expect to enter into a new $ million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on the fifth anniversary of the closing date of this offering. We expect the credit facility to include a $ million sublimit for letters of credit and a $ million sublimit for swing line loans. Subject to the satisfaction of certain conditions precedent, the credit facility will be available on and after the closing date of this offering for capital expenditures and permitted acquisitions, to provide for working capital requirements and for other general partnership purposes. Upon the closing of this offering, we will have approximately $ million in outstanding borrowings under the credit facility and $ million in issued and outstanding letters of credit leaving approximately $ million available for future borrowings or letter of credit issuances (subject to the letter of credit sublimit in the facility). The initial borrowings under the credit facility will be used to retire the remaining $ million of indebtedness assumed from Tallgrass Development and to pay $ million to Tallgrass Development as reimbursement for certain capital expenditures made in connection with the contributed assets. See “Use of Proceeds” for additional information. We expect the credit facility will also contain an accordion feature whereby we can increase the size of the credit facility to an aggregate of $ million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. Our obligations under the credit facility, as well as obligations under certain interest rate protection and hedging arrangements, will be (i) guaranteed by us and each of our existing and subsequently acquired or organized direct or indirect domestic subsidiaries, subject to our ability to designate certain of our subsidiaries as “Unrestricted Subsidiaries” or “Designated Project Subsidiaries,” and (ii) secured by a first priority lien on substantially all of the present and after acquired property owned by us and each guarantor. Borrowings under the credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin will initially be %, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin will initially be %. After the first full fiscal quarter after the closing date of this offering, the applicable margin will range from % to %, based upon our leverage ratio and whether we have elected the base rate or the reserve adjusted Eurodollar rate.

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The credit agreement is expected to contain various affirmative and negative covenants, that, among other things, will limit or restrict our ability (as well as the ability of our subsidiaries) to:

•

incur or guarantee additional debt;

•

incur certain liens on assets;

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dispose of assets;

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make certain distributions, including distributions from available cash, if a default or event of default under the credit agreement then exists or would result therefrom, and subject to satisfaction of certain other conditions to be negotiated in the definitive documentation governing the credit facility;

•

change the nature of our business;

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engage in certain mergers or make certain investments and acquisitions;

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enter into non arms-length transactions with affiliates; and

•

designate certain subsidiaries as “Unrestricted Subsidiaries” or “Designated Project Subsidiaries.”

Additionally, we expect that the credit agreement will contain certain financial covenants, to be tested quarterly for the four most recently completed fiscal quarters with respect to us and our subsidiaries on a consolidated basis, that will require us to maintain a minimum fixed charge coverage ratio of 2.00 to 1.00 and a maximum leverage ratio of 4.75 to 1.00 (which will be increased by 0.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions).

The credit agreement is also expected to contain certain events of default, including, but not limited to, the failure to pay any principal, interest or fees when due, failure to satisfy any covenant, untrue representations or warranties, impairment of liens, cross-defaults under other material debt agreements, insolvency, certain bankruptcy proceedings, change of control (to be defined in the credit agreement), dissolution and material money judgments. Upon the occurrence and during the continuation of an event of default under the credit agreement, the lenders may, among other things, terminate their revolving loan commitments, accelerate and declare the outstanding loans to be immediately due and payable, charge us with additional interest in the amount of 2.0% per annum plus the rate otherwise applicable to such amounts and exercise remedies against us and the collateral as may be available to the lenders under the credit agreement and other loan documents.

We expect that borrowings under the credit facility may be subject to mandatory prepayment with the net cash proceeds of certain asset sales or dispositions and certain issuances of debt, as well as the proceeds related to the Pony Express Abandonment.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of December 31, 2012, we had a working capital deficit of $43.8 million compared to a working capital deficit of $0.3 million at December 31, 2011.

Our working capital requirements have been and will continue to be primarily driven by changes in accounts receivable and accounts payable, which generally fluctuate with changes in the market prices of energy commodities that we buy and sell in the normal course of our business. Other factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers and payments to suppliers, as well as the level of spending for maintenance and growth capital expenditures. A material adverse change in operations or available financing under our revolving credit facility could impact our ability to fund our requirements for liquidity and capital resources.

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Following the completion of this offering, we believe that our anticipated cash flows from operations and the borrowing capacity under our revolving credit facility will be sufficient to meet our liquidity needs for the next 12 months.

Historical Cash Flow

The following table and discussion presents a summary of our cash flow for the periods indicated:


	TEP Pre-Predecessor						TEP Predecessor
	Year Ended Dec 31,			Period From Jan 1 to Nov 12,			Period From Nov 13 to Dec 31,
	2011			2012			2012
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	)		—

Operating Activities. Cash flows provided by operating activities were $81.3 million and $10.7 million for the period January 1, 2012 through November 12, 2012 and the period November 13, 2012 through December 31, 2012, respectively, which is generally consistent with $90.5 million of cash flow provided by operating activities for the year ended December 31, 2011.

Net income was $27.4 million lower in the 2012 periods compared to 2011, which was primarily attributable to decreases in natural gas collections from customers and natural gas sales in the Gas Transportation and services segment, as well as lower NGLs prices in the Processing segment, both of which are more fully described in “Results of Operations” in this MD&A. In addition, the one-time sale of 2.0 Bcf of natural gas from storage in the third quarter of 2011 generated approximately $7.0 million of net income that is reported as a cash flow from investing activities.

The component of working capital that had the most significant impact on operating cash flow during the 2012 periods was accounts payable and accrued liabilities. The increases in these balances, and related positive impact on cash flow from operating activities, is attributable to (i) trade payables owed to Kinder Morgan that would have been settled at the end of each period under Kinder Morgan’s centralized cash management program in the periods before the Predecessor Entities were acquired by Tallgrass Development and (ii) increased accounts payable and accrued liabilities associated with the ramp up of spending activity on the Pony Express Abandonment.

Investing Activities. Cash flows used in investing activities were $21.7 million and $12.7 million for the period from January 1, 2012 to November 12, 2012 and the period from November 13, 2012 to December 31, 2012, respectively, compared to $9.9 million in the year ended December 31, 2011. Capital expenditures consist of maintenance capital expenditures and expansion capital expenditures.

Maintenance capital expenditures are somewhat consistent from period-to-period. However, during 2011 we incurred higher levels of maintenance capital expenditures because of a replacement pipe program on the TIGT System, which is expected to be substantially complete by June 30, 2013, and an expansion project at the Casper and Douglas plants, which is expected to be completed in the second half of 2013. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from period-to-period. We expect that the level of maintenance capital expenditures in future periods will continue to have some variability but generally be consistent with the range of expenditures in the historical periods reported.

For the year ended December 31, 2011, we incurred expansion capital expenditures of $9.3 million. The most significant projects in the Gas Transportation and Storage segment were the completion of an expansion of

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the capacity of our natural gas pipeline facilities that run from Franklin to Hastings, Nebraska and an increase in the capacity of our natural gas storage facility. We spent approximately $15.7 million on the pipeline expansion and approximately $7.3 million on the gas storage project in 2010. The remaining expenditures on these projects in 2011 were approximately $4.8 million. In the Processing segment, we spent $3.1 million in 2011 on a project to transport NGLs to a refinery near our Casper processing plant.

For the year ended December 31, 2012, expansion capital projects were approximately $23.1 million. Approximately $9.8 million of this amount was incurred for initial engineering, permitting, hydraulic studies and right-of-way acquisitions for the Pony Express Abandonment. In the Midstream segment, we spent approximately $7.5 million to increase the capacity and efficiency of our Douglas processing plant in order to accommodate our customers’ increasing natural gas production in the region. In addition, we settled a dispute related to the construction of West Frenchie Draw treating plant in the amount of $5.9 million.

Financing Activities. Historically, cash flows used in financing activities consisted entirely of cash distributions paid to Kinder Morgan. TEP Predecessor has historically participated in Kinder Morgan’s centralized cash management system. Under this system, all cash balances of TEP Predecessor were swept on a daily basis and periodically the balances were settled and recorded as equity distributions. Therefore, TEP Predecessor did not have cash balances at the end of any period and cash flows from financing activities is equal to the total of cash flows from operating activities and cash flows from investing activities in all periods presented.

Distributions

We intend to pay quarterly distributions at an initial rate of $ per unit, which equates to an aggregate distribution of approximately $ million per quarter and $ million per year based on the number of common, subordinated and general partner units anticipated to be outstanding immediately after the closing of this offering. We do not have a legal obligation to pay distributions except as provided in our partnership agreement. Please read “Our Cash Distribution Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Capital Requirements

Our business can be capital-intensive, requiring significant investment to maintain and improve existing assets. We categorize capital expenditures as either:

•

maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, including the replacement of system components and equipment that have become obsolete or have approached the end of their useful lives; or

•

expansion capital expenditures, which include those expenditures incurred in order to acquire additional assets to grow our business, or to expand, upgrade or extend the useful lives of our existing assets.

We have budgeted approximately $41.2 million for capital expenditures during 2013. The largest component of our $13.4 million budgeted maintenance capital expenditures for 2013 relates to non-recurring integrity projects on the TIGT System. Our budgeted $27.8 million expansion capital expenditures during 2013 primarily relate to the ongoing expansion of the Douglas and Casper plants. In addition to the budgeted amounts above, we estimate that we will have expansion capital expenditures related to the Pony Express Abandonment of $53.6 million for which we will receive reimbursement from Tallgrass Development.

Contractual Obligations

Our contractual obligations consist of short-term pipeline reservation charges paid in our Processing segment to divert gas around our plants when market conditions are not favorable for processing gas, as well as

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nominal right-of-way payments to landowners in the Gas Transportation and Storage segment. The contracts associated with these obligations typically renew automatically as long as we continue to make the required payments. The total annual estimated payments under these contracts is less than $0.3 million in each of the next five years.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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 of December 31, 2012, approximately 60% of the reserved capacity in our processing segment was contracted under percent of proceeds, keep whole, or other non-fee-based 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 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 indirectly 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 year ended December 31, 2012.

We also have 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. As of December 31, 2012, we had natural gas swaps outstanding with a notional volume of approximately 1.7 Bcf, representing a portion of the natural gas that is expected to be sold by our Gas Transportation and Storage segment through the end of 2013. The fair value of these swaps was approximately $0.2 million at December 31, 2012.

We measure the risk of price changes in the our natural gas swaps utilizing a sensitivity analysis model. The sensitivity analysis measures the potential income or loss (i.e., the change in fair value of the derivative instruments) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. As of December 31, 2012, a hypothetical 10% change in natural gas market prices would change the estimated fair value of our natural gas derivative instruments by approximately $0.6 million. We enter into derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore both in the sensitivity analysis model and the change in the market value of our outstanding derivative contracts are offset largely by changes in the value of the underlying physical natural gas sales.

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Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the natural gas derivative contracts (including fixed price swaps and basis swaps) assuming hypothetical movements in future market prices and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market prices, operating exposures and the timing thereof, as well as changes in the notional volumes of our outstanding derivatives during the year.

Interest Rate Risk

As described above, at the closing of this offering, we intend to enter into a new $ million revolving credit facility. We may or may not hedge the interest on portions of our borrowings under the credit facility from time-to-time in order to manage risks associated with floating interest rates.

Credit Risk

We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through credit analysis, credit approval, credit limits and monitoring procedures. For certain transactions, we may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support. We have historically experienced only minimal credit losses in connection with our receivables.

A substantial majority of our revenue is produced under long-term, fee-based contracts with high-quality customers. For the year ended December 31, 2012, a substantial majority of our transportation and storage revenues were generated under long-term, fee-based firm contracts with a weighted average maturity of approximately 4.3 years and 2.0 years for transportation and storage contracts, respectively, as of December 31, 2012. The customer base we currently serve under these contracts generally has a strong credit profile, with eight of the top ten customers or their parent companies having investment grade credit ratings as of December 31, 2012. As of December 31, 2012, the weighted-average duration of our processing contracts was over four years and more than half of our capacity was reserved under contract through early 2019.

Critical Accounting Policies and Estimates

Our significant accounting policies are described in Note 2 to the audited combined financial statements included elsewhere in this prospectus. Management’s discussion and analysis of financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on our results of operations, equity or cash flows. For additional information concerning our other accounting policies, please read the notes to the financial statements included elsewhere in this prospectus.

Revenue Recognition

We recognize revenues when services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured.

NGL sales occur in the Processing segment and consist of the sale of outputs from our processing plants and the marketing of NGLs that are purchased from our suppliers. NGL revenues are recognized when goods are delivered and title has passed to the customer.

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Index to Financial Statements

Natural gas sales occur in both the Gas Transportation and Storage segment and in the Processing segment. In the Gas Transportation and Storage segment, natural gas sales occur when a portion of the natural gas transported by customers is collected as a contractual fee to compensate us for fuel consumed by pipeline and storage operations. These volumes of gas that are retained from our customers are recorded as transportation services revenue when received and injected into storage and the volumes, when subsequently sold, are recorded as natural gas sales revenue and cost of sales and transportation services. In addition, when operational conditions allow, we occasionally sell “cushion gas,” which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our contractual and operational requirements.

Transportation services occur in the Gas Transportation and Storage segment. In many cases (generally described as “firm service”), the customer pays a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customer’s agreed upon delivery point, or when the volumes are injected into or withdrawn from our storage facilities. In other cases (generally described as “interruptible service”), there is no fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to our “firm” and “interruptible” transportation services, we provide natural gas park and loan services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts.

Other operating revenues represent processing fees earned in the Processing segment. These fees are recognized when services are provided.

Accounting for Regulatory Activities

Our regulated activities are accounted for in accordance with the “Regulated Operations” Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process.

Property, Plant and Equipment

Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of utility property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned.

We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset’s use and its eventual disposition are less than its carrying amount and would be recognized upon regulatory approval.

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Risk Management Activities

We enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our natural gas purchases and sales in our Gas Transportation and Storage segment, which expose us to risks associated with changes in the market price of natural gas and NGLs. Specifically, these risks are associated with (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases; and (iii) natural gas system use and storage. During the years ended December 31, 2011 and 2012, we recognized no gain or loss as a result of ineffectiveness of these hedges. We did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness. As the hedged sales and purchases take place and we record them into earnings, we also reclassify the associated gains and losses included in accumulated other comprehensive income into earnings. Subsequent to our acquisition by Tallgrass, we intend to discontinue the use of hedge accounting and prospectively record the changes in fair value of our derivative contracts in current earnings.

We do not currently hedge the commodity exposure in our processing contracts with respect to our natural gas and NGL purchases and sales in our Processing segment. However, we monitor the mix of our contractual arrangements described above and expect to continue to increase the fee-based component of our contract portfolio when practical in order to reduce our exposure to natural gas and NGL price volatility.

Emerging Growth Company

We are an “emerging growth company” pursuant to the JOBS Act. The JOBS Act provides that an emerging growth company may delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have elected to take advantage of this exemption and, therefore, may adopt new or revised accounting standards at the time those standards apply to private companies. As a result of our election to take advantage of this transition period, our financial statements may not be comparable to those of companies that comply with public company effective dates for the adoption of new or revised accounting standards. This election had no impact on the combined financial statements included in this prospectus.

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INDUSTRY OVERVIEW

The midstream natural gas industry provides the link between the exploration and production of natural gas and the delivery of that natural gas and its by-products to industrial, commercial and residential users. The principal components of the industry consist of gathering, compressing, treating, dehydrating, processing, fractionating and transporting natural gas and NGLs. The midstream industry is generally characterized by regional competition based on the proximity of gathering and pipeline systems and processing and treating plants to natural gas producing wells. Companies within this industry provide services at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and NGLs and then routing the separated dry gas and NGL streams to the next intermediate stage of the value chain or to transportation pipelines for delivery to customers. Our transportation and storage operations focus on acting as a regional delivery and storage system that ultimately transports natural gas to local distribution companies, or LDCs, and other large industrial and agricultural users, including ethanol plants and irrigation and grain drying systems. Our processing operations provide straddle processing of natural gas flowing into the TIGT System out of the Niobrara shale and processing gas from third-party gathering systems that feed into our processing facilities. Adjusted EBITDA generated by our transportation and storage segment and our processing segment represented approximately 72% and 28%, respectively, of our total Adjusted EBITDA for the year ended December 31, 2012.

The following diagram illustrates the various components of the natural gas value chain and the extent of our current operations:

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Midstream Value Chain

The services provided by us and other midstream natural gas companies are generally classified into the categories described below. As indicated above, we do not currently provide all of these services, although we may provide other midstream services in the future. We provide transportation and storage services through our TIGT System, which consists of a series of interconnected pipeline and integrated storage facilities designed to provide transportation and service to regional users in the Midwest. We also provide processing, treating and fractionation services, which we collectively refer to elsewhere in this prospectus as our processing segment, at our Casper and Douglas processing plants and West Frenchie Draw treating facility, primarily to customers that source production from the Wind River Basin and the liquids-rich Niobrara shale.

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Gathering. At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport natural gas from the wellhead to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which enables more efficient gathering and delivery into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Compression is also used in the transportation of natural gas to support the movement of gas across pipeline systems and in storage to enhance withdrawal and injection capability.

Treating and Dehydration. Another process in the midstream value chain is treating and dehydration, a step that involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. To meet downstream pipeline specifications, processing plant capabilities and end-user natural gas quality standards, the natural gas is dehydrated to remove the saturated water and is chemically treated to separate the impurities from the gas stream.

Processing. The principal components of natural gas are methane and ethane, but some natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, some natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, which increase Btu levels beyond transport specifications. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components. However, NGLs are also valuable commodities once removed from the natural gas stream and utilized in the refining and petrochemical industries. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation. Fractionation is the separation of the mixture of extracted NGLs into individual components for end-user sale. Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take advantage of the difference in boiling points of separate products.

Transportation and Storage. The transportation of natural gas involves the movement of pipeline-quality natural gas from gathering / processing and treating systems to wholesalers and end-users, including industrial plants and LDCs. The primary methods of transporting natural gas are through long-haul transportation pipelines, header system transportation pipelines, regional delivery systems or all of the above.

Long-haul transportation pipelines, such as the Trailblazer pipeline, generally span considerable distances and consist of large-diameter high pressure pipelines and have few interconnects with other gathering and transportation systems. Some long-haul transportation pipelines are designed to transport natural gas from one receipt point to one delivery point.

Header system transportation pipelines are characterized as networks of medium to large-diameter high pressure pipelines that connect local gathering systems to large-diameter high pressure long-haul transportation pipelines through multiple interconnects. Header system transportation pipelines typically do not transport natural gas long distances.

Regional delivery systems, such as the TIGT System, are characterized as networks of interconnected FERC-regulated pipelines designed to deliver natural gas to LDCs and industrial users, throughout a large regional area. These regional delivery systems typically interconnect with a number of long-haul transportation pipelines to provide the customer with access to production from a diverse supply of basins.

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The concentration of natural gas production in a few regions of the U.S. generally requires transportation pipelines to cross state borders to meet national demand. These pipelines are referred to as interstate pipelines and are primarily regulated by federal agencies or commissions, including the FERC. Pipelines that transport natural gas produced and consumed wholly within one state are generally referred to as intrastate pipelines. Intrastate pipelines are primarily regulated by state agencies or commissions.

The storage sector is extremely important in maintaining the balance between the supply and demand of natural gas. Storage enables the warehousing of natural gas and is used to store excess production during periods of low demand and to withdraw natural gas during periods of high demand. Storage facilities are also utilized by pipelines to manage imbalances caused by LDCs, natural gas producers and independent natural gas marketing and trading companies in connection with the execution of trading strategies.

Market Fundamentals

As indicated in the charts shown below, U.S. natural gas production and overall U.S. energy demand are expected to grow in the coming decades. Population is a large determinant of energy consumption through its influence on demand for travel, housing, consumer goods and services. The U.S. Energy Information Administration, or EIA, anticipates the total U.S. population will increase by 29% from 2011 to 2040. Another important contributor to energy consumption is the industrial sector, with total consumption in this sector expected to grow to 28.7 quadrillion Btu in 2040, according to the EIA. According to the EIA, energy use is only projected to grow by approximately 10% from 2011 to 2040, and energy use per capita is expected to decline by 15% over the same period. A review of other supply and demand elements follows.

Natural gas is a key component of energy consumption within the United States. According to the EIA, annual consumption of natural gas in the United States increased from 24.3 quadrillion Btu in 2010 to 24.9 quadrillion Btu in 2011. According to the EIA, natural gas consumption represented approximately 25% of total energy consumption in 2011, and the EIA projects that this percentage will increase to approximately 27% by 2040. The charts shown below illustrate energy consumption by fuel source in 2011 and expected energy consumption by fuel source in 2040.

Energy Consumption by Fuel Source

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Source: EIA, Annual Energy Outlook 2013 (January 2013).

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The EIA expects that the growth of natural gas consumption relative to other fuel sources will be primarily driven by the use of natural gas electricity generation. According to the EIA, demand for natural gas in the electric power sector is projected to increase from approximately 7.6 Tcf in 2011 to approximately 9.5 Tcf in 2040, with a portion of the growth attributable to the retirement of 49 gigawatts of coal-fired capacity by 2022. The EIA also projects that natural gas consumption in the industrial sector will be higher due to the rejuvenation of the industrial sector as it benefits from surging shale gas production that is accompanied by slow price growth, particularly from 2011 through 2019, when the price of natural gas is expected to remain below 2010 levels. However, the EIA expects growth in natural gas consumption for power generation and in the industrial sector is to be partially offset by decreased usage in the residential sector related primarily to decreased demand for natural gas powered home heating.

U.S. Primary Energy Consumption by Fuel, 1980 – 2040

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Source: EIA, Annual Energy Outlook 2013 (January 2013).

Domestic natural gas consumption today is satisfied primarily by production from conventional onshore and offshore production in the lower 48 states, and is supplemented by production from historically declining pipeline imports from Canada, imports of LNGs from foreign sources, and some Alaska production.

In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of natural gas must continue to be developed to support consumption rates. Over the past several years, there has been a fundamental shift in U.S. natural gas production towards unconventional resources, defined by the EIA as natural gas produced from shale formations and coal beds. The emergence of unconventional natural gas plays and advancements in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of natural gas from these plays. According to the EIA, the dual application of horizontal drilling and hydraulic fracturing has been the primary driver of increases in shale gas production. As indicated by the diagram below, the development of these unconventional sources has offset declines in other, more traditional U.S. natural gas supply sources, which has helped meet growing consumption and lowered the need for imported natural gas. In fact, the EIA predicts that the U.S. will become a net exporter of natural gas starting in 2020.

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As indicated by EIA forecasts shown in the diagram below, as the depletion of conventional onshore and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. In fact, the EIA estimates that, natural gas production from the major shale formations will provide the majority of the growth in domestically produced natural gas supply in coming years, increasing to approximately 50% in 2040 as compared with 34% in 2011. According to the EIA, shale gas will be the largest contributor to natural gas production growth, while production from tight sands, coalbed methane deposits and offshore waters is expected to remain stable.

U.S. Dry Natural Gas Production by Source, 1990 – 2040

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Source: EIA, Annual Energy Outlook 2013 (January 2013).

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Key Areas of Operation

We are positioned to serve numerous basins and plays located primarily in the Rocky Mountain and the Midwest regions. A few of the key hydrocarbon basins that we are strategically located to provide services to include the Denver-Julesburg Basin, the Powder River Basin, the Wind River Basin and the Anadarko Basin.

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Denver-Julesburg and Powder River Basins and the Niobrara Shale Play

Denver-Julesburg Basin. The Denver-Julesburg Basin is a structural basin located in eastern Colorado, southeastern Wyoming, western Kansas and the Nebraska Panhandle and covers an area of more than 109,000 square kilometers (42,000 square miles). The first hydrocarbon discovery in this particular basin was made in 1862, and as of December 2012 there were over 20,000 active wells in the area according to Wood Mackenzie. Gas production is dominated by the giant Wattenberg field, where activity has focused on exploitation of the field’s tight gas assets using recompletions, multi-fracs, and infill drilling.

Powder River Basin. The Powder River Basin is a large petroleum province of approximately 88,000 square kilometers (34,000 square miles) located in northeast Wyoming and southeast Montana. This particular basin dates back to 1889 when hydrocarbons were discovered on the Salt Creek Anticline. Since then, approximately 700 additional fields have been discovered. While production in the Powder River Basin was historically focused on coalbed methane, this focus has shifted in recent years to the liquids-rich Niobrara shale play mentioned below as operators have sought to concentrate their efforts in liquids-rich gas and oil plays.

Niobrara Shale Play. Recently, operators have been focused on targeting the liquids-rich Niobrara shale for oil and gas production in and around the Wattenberg field as well as to the northwest part of the Denver-Julesburg basin. The Niobrara shale underlies the Denver-Julesburg and Powder River Basins and, in management’s opinion, is one of the emerging key plays in the Rocky Mountain region. The Niobrara formation has been exploited for natural gas for decades and is composed of alternating levels of organic-rich calcareous shale and chalk. The Niobrara play has a depth of approximately 6,000 to 8,000 feet.

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Wind River Basin

Located in north-central Wyoming, the Wind River Basin is an east-west trending asymmetrical intermontane basin. The basin is estimated to have an area of approximately 30,300 square kilometers (11,700 square miles), and its primary axis stretches to approximately 320 kilometers in length. Over 60% of the production within this basin comes from the Madden field, which is comprised of a series of stacked reservoirs ranging from the shallow Fort Union and Lance formation down to the deep Madison Limestone. The most productive wells in the basin are located in the deep Madison formation, but current developments are now focusing on shallower formations.

Anadarko Basin and the Mississippi Lime Play

Anadarko Basin. According to Wood MacKenzie, the Anadarko Basin is one of the most prolific natural gas-producing basins, spanning from western Oklahoma to northeast of the Texas Panhandle. The basin is approximately 144,000 square kilometers (55,599 square miles) with roughly 54,342 producing wells in December 2012 according to Wood Mackenzie. Although mature and long-lived, the Anadarko Basin has been the focus of increased exploration activity of late. Oil development in the basin has been cyclical, with early activity focusing on oil exploitation and gas production prevailing in the late 1990s and 2000s. Since 2009, operators have been exploring the field’s rich gas fields and older, conventional oil fields with horizontal laterals and enhanced technology, vastly improving recoveries and opening up previously uneconomic plays.

Mississippi Lime Play. The Mississippi Lime play, which underlies the Anadarko Basin, is located primarily within the Mid-Continent area and covers 17 million acres across Northern Oklahoma and Southern and Western Kansas. The formation has a relatively shallow depth, ranging from 3,000 to 6,000 feet. As of June 2012, there were approximately 750 horizontal wells drilled in the area.

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BUSINESS

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 TIGT System and provide processing services for customers in Wyoming through our 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 year ended December 31, 2012, we generated Adjusted EBITDA of approximately $76.4 million and net income of approximately $50.1 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 “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

In November 2012, Tallgrass Development acquired from 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 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 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 each of the remaining 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 when Tallgrass Development will make acquisition opportunities available to us, however, given the significant economic interest 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:

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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 4.3 years and 2.0 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 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

978 MMcf/d

689 MMcf/d

4.3 yrs

Storage

15.1 Bcf(3)

11.1 Bcf

2.0 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 “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

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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 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.

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,

Three-Month
Period Ended
December 31,

Existing

Expansion(2)

2011

2012

138.5

188.5

100%

5.0 yrs

101

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(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 “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

Our Relationship with Tallgrass Development

One of our principal strengths is our relationship with Tallgrass Development, a leading provider of midstream 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).

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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, which is one of the most significant trading hubs for crude oil in North America. The Pony Express Project will consist primarily 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 and is currently contracted for 206,000 barrels per day for five years beginning from the date it is placed in service with an additional 10% of capacity available for walk-up customers.

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We believe Tallgrass Development will offer us the opportunity to acquire substantially all of these remaining assets, but it is not obligated to do so.

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 an affiliate of the general partner of Tallgrass Development. 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.

At the closing of this offering, Tallgrass Development will own a % limited partner interest in us and its affiliates will own a 2% general partner interest in us and all of our 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 each of the Retained Assets. Other than these omnibus agreement provisions, Tallgrass Development is under no obligation, however, to offer to sell us additional assets or to pursue acquisitions jointly with us, and

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we are under no obligation to buy the Retained Assets or any such additional assets or pursue any such joint acquisitions. 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. Tallgrass Development constantly evaluates acquisitions and dispositions and may elect to acquire or dispose of assets in the future without offering us the opportunity to acquire those assets. Tallgrass Development has retained such flexibility because it believes it is in the best interests of its limited partners to do so. We cannot say with any certainty which, if any, opportunities to acquire assets from Tallgrass Development may be made available to us or if we will choose to pursue any such opportunity. Moreover, the consideration to be paid by us for assets offered to us by Tallgrass Development, if any, as well as the consummation and timing of any acquisition by us of these assets, would depend upon, among other things, the timing of Tallgrass Development’s decision to sell, transfer or otherwise dispose of these assets, our ability to successfully negotiate a purchase price and other terms, and our ability to obtain financing.

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, 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.

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 $6.2 billion of total investor commitments (including co-investments) with in excess of $3.1 billion deployed across the energy sector since inception.

Business Strategies

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review acquisition opportunities from third parties as they become available. For a description of Tallgrass Development’s retained midstream asset portfolio and current development projects, please read “—Our Relationship with Tallgrass Development.”

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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. Geographically, we intend to focus our expansion efforts on those regions with attractive characteristics, including regions where permitting, drilling and workover activity is high, there is a strong base of current production and the potential for significant future development, that are currently under-served and regions that can serve as a platform to expand into adjacent areas with existing or new production.

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Maintaining and growing stable cash flows supported by long-term, fee-based contracts. We will seek to maintain and grow cash Plans by increasing utilization of our existing assets in a cost effective manner by focusing on customer service. Additionally, we will seek to generate the majority of our cash flows pursuant to multi-year, firm contracts with creditworthy customers. to minimize our direct commodity price exposure. We will continue to pursue opportunities to increase the fee-based component of our contract portfolio through contract renewal negotiations, acquisitions or other growth projects.

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Competitive Strengths

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

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TIGT System. For the year ended December 31, 2012, a substantial majority of our transportation and storage revenues were generated under long-term, fee-based firm contracts. The customer base we currently serve under these contracts generally has a strong credit rating, with eight of the top ten customers or their parent companies having investment grade credit ratings as of December 31, 2012. Furthermore, our existing customers on the TIGT System have historically renewed business with us when their contracts expire. Of our top ten transportation and storage customers by revenue for the year ended December 31, 2012, which collectively contributed approximately 64% of our total transportation and storage revenue for that period), five have been our customers for at least 20 years, including prior to deregulation of the U.S. natural gas pipeline industry. The revenue-weighted average relationship tenure of the remaining five of our top ten customers for the same period is approximately 10 years, with each having been a customer for at least four years.

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Midstream Facilities. In our processing segment, we maintain a diverse contract portfolio comprised of fee-based, percent-of-proceeds, and keep whole arrangements with established producers, some of which also pay a fixed monthly reservation charge for the right to have a

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specified volume of gas processed regardless of capacity utilization. Furthermore, due in part to the increasing opportunities in the liquids-rich Niobrara shale substantially all these producers are currently processing volumes either at or near their maximum reserved capacity at our facilities or rapidly increasing their utilization, which allows us to benefit from the volume-based compensation provisions under our existing contractual arrangements. As of December 31, 2012, the weighted-average duration of our processing contracts was approximately five years, and more than half of our capacity was reserved under contracts through early 2019.

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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 substantial majority of whom pay FERC-approved recourse rates. Approximately 65% of our transportation and storage revenue for the year ended December 31, 2012 was generated under contracts with on-system customers. In addition, over 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. The TIGT System has 461 delivery points, including 15 interconnections with interstate pipelines and 446 interconnections with LDCs and other users. In addition, the TIGT System indirectly services more than 10,000 third party delivery points. We believe this 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. In addition, we believe our transportation, storage and processing systems consist of high-quality assets that have been well maintained, resulting in efficient operations. As a result, we believe we have established a reputation in the midstream business as a reliable and cost-effective supplier of services to our customers and have a track record of safe and efficient operation of our facilities.

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Acquisition Opportunities. The Retained Assets held by Tallgrass Development, which include the Pony Express Project (following the Pony Express Abandonment), the Trailblazer Pipeline and a 50% interest in the REX Pipeline, are geographically diverse and of strategic interest to us and would complement our existing asset base by expanding and diversifying our cash flow sources. The Retained Assets are also positioned to serve high-growth natural gas, liquids and oil producing basins and shale formations, including the Denver-Julesburg, and Williston Basins and the Bakken, Marcellus and Utica shale formations. 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 each of the Retained Assets. We also believe that our relationship with Tallgrass Development offers the opportunity for increased access to strategic acquisitions of complementary assets from third parties.

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Executive team with significant industry and management expertise. Through our relationship with Tallgrass Development, we have a management team with significant expertise owning, developing and operating midstream assets, as well as significant relationships with participants across the natural gas supply chain. Additionally, our management team has a proven track record of successfully acquiring and developing midstream assets in a reliable and cost-effective manner. The members of our executive management team have collectively been involved in acquisitions in the midstream sector totaling over $10 billion.

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Our Assets

Our assets currently consist of the TIGT System and the Midstream Facilities, each of which is described in more detail below.

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Our transportation and storage rates and services are subject to regulation by the FERC, which reviews and approves the tariff that establishes our rates, cost recovery mechanisms and terms and conditions of service. The rates established under our tariff are a function of our costs of providing services to customers, including a reasonable return on invested capital. The authority of the FERC also extends to certification and construction of transportation and storage facilities, including, but not limited to acquisitions, facility maintenance, pipeline

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extensions and abandonment of services and facilities. FERC regulations also restrict interstate 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.

TIGT System

The TIGT System is a FERC-regulated transportation and storage system serving Wyoming, Colorado, Kansas, Missouri and Nebraska that we own through our wholly-owned subsidiary, Tallgrass Interstate Gas Transmission, LLC. The TIGT System contains 15 interconnects with interstate pipelines, including the Rockies Express Pipeline and the Trailblazer Pipeline. The natural gas currently transported on the TIGT System primarily comes from the Denver-Julesburg Basin and the Niobrara and Mississippi Lime shale formations.

The following tables provide operational information regarding our transportation and storage assets as of December 31, 2012 and for the periods indicated:


					Approximate Average Daily Throughput (MMcf/d)
	Approximate Number of Miles		Approximate Compression (Horsepower)		Year Ended December 31, 2011		Year Ended December 31, 2012
Transportation		4,645		136,608		448		385


	Overall Gas Storage Capacity (Bcf)		Working Gas Storage Capacity (Bcf)		Maximum Withdrawal Rate (MMcf/d)
Storage		35.1		15.1		210

TIGT Customers

The TIGT System is a well-established and operationally flexible natural gas transportation and storage system that has been serving customers in the Midwest for approximately 75 years. The system’s flexibility is derived from its multiple receipt and delivery interconnects, numerous pipeline segments and extensive footprint in the Midwest. TIGT is uniquely positioned to serve on-system customers such as LDCs and industrial users, including ethanol plants, and irrigation and grain drying operations, which value the system’s extensive deliverability options and proximity to customer facilities. As a result, we expect the TIGT System to retain a substantial majority of its current customers at our FERC-approved recourse rate. We also believe there is potential to expand the customer base of the TIGT System due to its geographic location in the agricultural belt of the United States, which positions the TIGT System to support growing demand from fertilizer plants and potential coal-to-gas power plant conversions.

No transportation and storage customers accounted for 10% or more of our revenues for the year ended December 31, 2011.

TIGT Contracts

Under transportation agreements and FERC tariff provisions, TIGT offers its customers firm and interruptible transportation and storage services, including no-notice service and park and loan services.

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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

978 MMcf/d

689 MMcf/d

4.3 yrs

Storage

15.1 Bcf (3)

11.1 Bcf

2.0 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.

Firm Service. Firm transportation contracts obligate our customers to pay a fixed monthly charge to reserve an agreed upon amount of pipeline capacity for transportation regardless of the actual pipeline capacity used by the customer during each month, which we refer to as a monthly reservation charge. In addition to monthly reservation charges, we also collect usage charges when a firm transportation customer uses the capacity it has reserved under these firm transportation contracts. These charges are assessed on the actual volume of natural gas transported on the transportation system. In addition, firm transportation customers are charged an overrun usage charge when the level of natural gas taken for delivery by a firm transportation customer exceeds the quantity of capacity reserved for delivery by such customer.

Firm storage contracts obligate our customers to pay a fixed monthly charge for the firm right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Firm service storage customers are also assessed usage charges based on the actual quantities of natural gas injected into or withdrawn from storage. Firm service storage customers are charged an overrun usage charge when the level of gas withdrawn exceeds a customer’s maximum daily withdrawal limit.

Interruptible Service. The TIGT System derived 2% of its revenues for the year ended December 31, 2012 through interruptible service under which our customers pay fees based on their actual utilization of assets for transportation and storage services. These customers are not assured capacity or service on the TIGT System. If firm service physical capacity is not being fully utilized or if there is excess capacity that has not been contracted for firm service, the TIGT System can allocate such capacity to interruptible services. We also provide natural gas “park and loan” services to assist customers in managing short-term gas surpluses or deficits. Under our park and loan service agreements, customers are charged a usage fee based on the quantities of natural gas they store in (park), or borrow from (loan), our facilities.

Contract Rates. As of December 31, 2012, approximately 31% of our contracted transportation and storage firm capacity was subscribed at the FERC-approved recourse rate. Approximately 33% was subscribed by customers at a specified discount to the FERC-approved recourse rates. The remaining 36% of contracted transportation and storage firm capacity was subscribed by customers under “negotiated rate” agreements that have been filed with and accepted by the FERC.

We have the authority to make gas purchases and sales, as needed for the TIGT System operations, pursuant to our currently effective FERC natural gas tariff. We do not take title to the natural gas transported or stored for our customers, which mitigates our direct commodity price risk. However, our tariff provides that we may retain a portion of our customers’ natural gas as compensation for natural gas used in rendering service to such customer, including natural gas consumed by us in our operations as well as natural gas lost or unaccounted for as a result of venting, inherent measurement inaccuracies or events of force majeure, among other reasons.

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Midstream Facilities

We also own and operate natural gas processing plants in Casper and Douglas, Wyoming and a natural gas treating facility at West Frenchie Draw, Wyoming through our wholly-owned subsidiary, Tallgrass Midstream, LLC. Each of these assets is strategically located to process and treat gas flowing into the TIGT System.

The natural gas processed and treated at these facilities primarily comes from the Wind River Basin in central Wyoming and the liquids-rich Niobrara shale in northern Colorado and Wyoming. Casper and Douglas 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.

Natural gas processing involves the separation of natural gas into pipeline-quality natural gas and a mixed NGLs stream. The Douglas and Casper processing plants produce an unfractionated raw NGL stream that is delivered into an NGL product pipeline at the plant outlet. The Douglas and Casper plants straddle the TIGT System for inlet feed to provide residue gas delivery to the TIGT System. In addition, gathering systems owned by third parties feed into our processing facilities. We recently completed upgrades to the connection with a third-party gathering system to expand inlet capacity and upgrade to newer, more efficient compressors.

Both the Casper and Douglas plants have receiving facilities for trucked in NGLs supplies as well as stabilizer facilities to separate natural gasoline from the mixed NGL stream. Our Casper Plant also includes a 2,000 barrel per day NGL fractionator. Fractionation is the process by which NGLs are further separated into individual, more valuable components including ethane, propane, butane, isobutane and natural gasoline. The expansion of this NGL fractionator to an approximate capacity of 3,500 barrels per day is currently underway and is expected to be completed in the second half of 2013. While we do not currently have this additional capacity contracted, we believe there is significant demand for it and expect it to be fully contracted shortly after it is completed.

The West Frenchie Draw natural gas treating facility is located 50 miles west of Casper, Wyoming. Natural gas is delivered to the West Frenchie Draw facility from two of the areas’ major natural gas producers and is treated to extract or reduce impurities, such as carbon dioxide and sulfur, prior to its delivery to our Casper or Douglas processing plants.

Processing Segment Customers

We provide processing services to some of the largest and most active producers in the Wind River Basin and Niobrara shale. NGLs fractionated by the Casper plant are sold into local markets consisting primarily of retail propane dealers and oil refiners. NGLs processed by the Douglas plant are sold to Phillips 66 Company via its Powder River NGL pipeline. For the year ended December 31, 2011, Phillips 66 Company, as a purchaser of NGLs we produce and sell on behalf of our processing customers, accounted for approximately 33% of our total revenues. While we currently sell a significant amount of our NGLs produced by the Douglas plant to Phillips 66 Company, we believe there is a sufficient market for these NGLs and that if Phillips 66 Company did not purchase them, they would be sold to other buyers who could transport them either on the Powder River NGL pipeline, by truck or rail, among other ways.

Processing Contracts

Our processing services are typically provided pursuant to contracts featuring characteristics of one, or a combination of more than one, of the following contractual arrangements. In addition, many of our processing contracts obligate our customers to pay a fixed monthly reservation charge for the right to have a specified volume of gas processed regardless of the amount of processing capacity actually utilized by the customer.

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Index to Financial Statements

Percent of Proceeds. As of December 31, 2012, approximately 29% of the reserved capacity at the Midstream Facilities was under contracts with a percent of proceeds component, in which we process our customer’s natural gas, sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. The weighted average duration of these contracts is 5.2 years and we retain, on average, approximately 8.2% of the proceeds from the natural gas and NGL sales. Some of our percent of proceeds contracts also require our customer to pay a monthly reservation fee for capacity at our processing facilities.

Fee-based. Another substantial portion of our contracts at the Midstream Facilities are primarily based upon a fixed fee and/or a volumetric-based fee rate, which are typically tied to reserved capacity or inlet volumes. As of December 31, 2012, approximately 34% of our reserved capacity was subject to fee-based contracts with a weighted average duration of 2.6 years.

Keep Whole. Keep whole provisions constitute the third major component of our contract mix at the Midstream Facilities. Under these 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. As of December 31, 2012, approximately 37% of our Midstream Facilities’ reserved capacity was under these “keep whole” contracts, although of those, the majority also require the customer to pay a reservation fee.

We will continue to pursue opportunities to increase the fee-based component of our contract portfolio through contract renewal negotiations, acquisitions or other growth projects to continue to decrease our exposure to commodity price risk. We do not currently hedge our commodity price risk associated with our processing contracts.

As of December 31, 2012, all of our existing processing capacity was fully contracted until 2015, and over half of our existing processing capacity was fully contracted through early 2019.

Competition

Our principal competitors in our natural gas transportation and storage market include companies that own major natural gas pipelines, such as Kinder Morgan and Southern Star Central Gas Pipeline, Inc., many of whom also have existing storage facilities connected to their transportation systems that compete with our storage facilities. Pending and future construction projects, if and when brought on line, may also compete with our natural gas transportation, storage, processing and treating services and certain of our competitors may have capital and other resources greater than ours.

We also experience competition in the natural gas processing business. Our principal competitors for processing business include other facilities that service our supply areas, such as the other regional processing and treating facilities in the Greater Powder River Basin which include plants owned and operated by Kinder Morgan, Merit Energy Company and Western Gas Partners, L.P. Casper and Douglas, however, are currently the only plants that provide straddle processing of natural gas flowing into the TIGT System out of the Niobrara shale and NGL pipeline take-away capacity. In addition, due to the growing nature of the liquids-rich Niobrara shale play, it is possible that one of our competitors could build additional processing facilities that service our supply areas.

In addition, as a provider of midstream services to the natural gas industry, we generally compete with other forms of energy available to consumers, including electricity, coal, propane and fuel oils. Several factors influence the demand for natural gas, including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather.

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Index to Financial Statements

Regulatory Environment

Federal Energy Regulatory Commission

As an interstate transportation and storage system, the rates, terms of service and continued operations of the TIGT System are subject to regulation by the FERC, under among other statutes, the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EP Act 2005.

The FERC has jurisdiction over, among other things, the construction, ownership and commercial operation of pipelines and related facilities used in the transportation and storage of natural gas in interstate commerce, including the modification, extension, enlargement and abandonment of such facilities. The FERC also has jurisdiction over the rates, charges and terms and conditions of service for the transportation and storage of natural gas in interstate commerce.

The rates and terms for access to pipeline transportation services are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of these initiatives, interstate natural gas transportation and marketing entities have been substantially restructured to remove barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from competing effectively with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The FERC’s regulations require, among other things, that interstate pipelines 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 available pipeline capacity and other relevant information, and permit pipeline shippers under certain circumstances to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. The result of the FERC’s initiatives has been to eliminate the interstate pipelines’ historical role of providing bundled sales service of natural gas and to require pipelines to offer unbundled storage and transportation services on a non-discriminatory basis. The rates for such transportation and storage services are subject to the FERC’s ratemaking authority, and the FERC exercises its authority by applying cost-of-service principles to limit the maximum and minimum levels of tariff-based recourse rates; however it also allows for the negotiation of rates as a cost-based alternative rate and may grant market-based rates in certain circumstances, typically with respect to storage services. The FERC regulations also restrict interstate 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.

2011 Section 5 Fuel Settlement

In November 2010, we received notice of a FERC proceeding related to the TIGT System pursuant to Section 5 of the Natural Gas Act. The proceeding set for hearing a determination of whether our current rates, which were approved by the FERC in our last transportation rate case settlement, remain just and reasonable. The FERC made no findings in its order as to what would constitute just and reasonable rates or a reasonable return for TIGT. A proceeding under Section 5 of the Natural Gas Act is prospective in nature and any potential change in the rates charged to customers on the TIGT System can only occur after the FERC has issued a final order.

In September 2011, the FERC approved a settlement among the parties, which resolves all issues in the proceeding and provides shippers on the TIGT System with prospective reductions in the fuel and gas and lost and unaccounted for gas rates, referred to as the Fuel Retention Factors, effective November 1, 2011. The settlement also provides shippers with credits equal to the reduced rates for the period from June 1, 2011 through October 31, 2011. The settlement resulted in a 27% reduction in the Fuel Retention Factors paid by shippers effective June 1, 2011, as compared to the Fuel Retention Factors approved and in effect on March 1, 2011. The settlement also provided for a second stepped reduction effective January 1, 2012, resulting in a total 30% reduction in the Fuel Retention Factors billed to shippers for certain segments of the former Pony Express pipeline system. Except for these reductions to the Fuel Retention Factors, other transportation and storage rates were not altered by the settlement. The settlement also established a moratorium of one year, from November 1,

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Index to Financial Statements

2011 until November 1, 2012, during which neither we nor any of our customers participating in the settlement could initiate a rate proceeding under NGA Sections 4 or 5 to increase or reduce the recourse rates or fuel retainage percentages on the TIGT System. The settlement also required us to file with the FERC a cost and revenue study prior to November 1, 2015, although we have no obligation to file an NGA Section 4 rate proceeding.

Pony Express Abandonment

On August 6, 2012, we filed an application with the FERC to: (1) abandon certain mainline natural gas pipeline facilities that are currently a part of the TIGT System and the natural gas service therefrom for the purpose of converting the facilities into crude oil pipeline facilities; and (2) construct and operate certain replacement-type facilities necessary to continue service to existing natural gas firm transportation customers following the proposed abandonment.

This application, upon FERC approval and implementation, will re-deploy existing pipeline assets to meet the growing market need to transport oil supplies from the Bakken Shale and other nearby oil producing basins, while at the same time continuing to operate our natural gas transportation facilities to meet all current and expected needs of the customers on the TIGT System. Certain customers have filed protests with the FERC challenging the adequacy of replacement natural gas services for existing shippers and the manner in which we intend to reconcile costs for the project. We responded to protests and comments on September 20, 2012 and again on October 24, 2012, and the application for the abandonment and sale remains pending before the FERC. If the FERC approves the application, the order will authorize the Pony Express Abandonment, thereby allowing for the reconversion of the Pony Express Assets back to the transportation of crude oil as it was prior to 1997.

Market Behavior Rules; Posting and Reporting Requirements

The EPAct 2005, among other matters, amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and, furthermore, provides the FERC with additional civil penalty authority. The FERC adopted rules implementing the anti-manipulation provision of the EPAct 2005 that make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas transportation services subject to the jurisdiction of the FERC to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person.

These anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services as well as otherwise non-jurisdictional entities to the extent the activities are conducted ‘‘in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. These anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a ‘‘nexus’’ to jurisdictional transactions. The EPAct 2005 also amended the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes, up to $1,000,000 per day per violation. In connection with this enhanced civil penalty authority, the FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines.

The EPAct of 2005 also amended the NGA to authorize the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. The FERC has taken steps to enhance its market oversight and monitoring of the natural gas industry by adopting rules that (1) require buyers and sellers of annual quantities of 2,200,000 MMBtu or more of gas in any year to report by May on the

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Index to Financial Statements

aggregate volumes of natural gas they purchased or sold at wholesale in the prior calendar year; (2) report whether they provide prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting; and (3) increase the Internet posting obligations of interstate pipelines.

Pipeline and Hazardous Materials Safety Administration

We are also subject to safety regulations imposed by PHMSA, including those regulations requiring us to develop and maintain integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional measures to protect pipeline segments located in areas, which are referred to as high consequence areas where a leak or rupture could potentially do the most harm.

The ultimate costs of compliance with the integrity management rules are difficult to predict. 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 high consequence areas, or 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 U.S. Department of Transportation 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 pipeline.

In addition, we may be subject to enforcement actions and penalties for failure to comply with pipeline regulations. For example, 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.

The President signed into law in January 2012 The Pipeline Safety Act of 2011, which increased penalties for violations of safety laws and rules, among other matters, and may result in the imposition of more stringent regulations in the next few years. PHMSA is also currently considering changes to its regulations. PHMSA issued an Advisory Bulletin in May 2012, which advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data 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 such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipeline. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures.

Pipeline Integrity and Releases

From time to time, our pipeline may experience integrity issues. These integrity issues may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of

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our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

Environmental, Health and Safety Matters

The ownership, operation and expansion of our assets are subject to federal, state and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health. Moreover, we are subject to federal and state laws and regulations, the purpose of which is to maintain the safety of workers and the integrity of our pipeline, both generally and according to the standards applicable to the pipeline industry. The cost of complying with these laws and regulations can be significant, and we expect to incur significant compliance cost increase in the future as new, more stringent requirements are adopted and implemented. For example, regulation of greenhouse gas emissions under the CAA, and its implementing regulations could particularly result in significant cost additions. In addition, permitting requirements arising under these laws and regulations can negatively affect our ability to complete on a timely or cost-effective basis any future projects, for example, pipeline extensions, capacity expansion at processing facilities, and construction of storage facilities. We have an internal program of inspection designed to monitor and enforce compliance with pollution control and pipeline safety requirements.

Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, authorizations and other approvals, or submit to inspections or investigations. Liability under such laws and regulations may be incurred without regard to fault, including, for example, under the CERCLA, the RCRA, and analogous state laws for the remediation of contaminated areas. Private parties, including but not limited to the owners of properties through which our pipeline passes, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with such laws, regulations and permits issued thereunder or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event that an environmental claim is made against us.

Failure to comply with these laws, regulations permits, approvals and authorizations or to meet the requirements of new environmental laws, regulations or permits, approvals and authorizations, may also expose us to civil, criminal and administrative fines, penalties and/or temporary or permanent interruptions in our operations that could influence our business, financial position, results of operations and prospects. For example, if an accidental leak or release of natural gas or other hazardous substance occurs from our pipeline, we may experience significant operational disruptions and we may also have to pay a significant amount in costs to clean up the leak or release, pay for government penalties, address natural resource damages, provide compensation for human exposure or property damage, comply with issued injunctions, which could compel us to take steps such as installing costly pollution control equipment or limiting or ceasing some or all of our operations, or a combination of these and other measures. Further, in March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which includes the addition of “Energy Extraction Activities” to its enforcement priorities list. On January 28, 2013, EPA issued a notice seeking comment on whether to extend the current National Enforcement Initiatives, including the initiative related to Energy Extraction Activities, for the next three years. 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 and increasing its frequency of inspections and evaluations to ensure that energy extraction activities are complying with federal environmental requirements. The costs and liabilities resulting from failure to comply with environmental laws and regulations could negatively affect our business, financial position, results of operations and prospects. In addition, emission controls required under the CAA and other similar federal, state and local laws could require significant capital expenditures at our facilities.

In addition, we have agreed to a number of conditions in our environmental permits, 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

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Index to Financial Statements

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 in the future, and we are unable to predict the effect that any such measures would have on our business, financial position, results of operations or prospects.

We are also subject to the requirements of the OSHA, the Pipeline Safety Improvement Act and other comparable federal and state statutes. In general, we expect that we may have to increase expenditures in the future to comply with higher industry and regulatory safety standards. Such increases in expenditures could become significant over time.

Developments in GHG Regulations

Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of GHGs. Various laws and regulations exist or are under development that seek to regulate the emission of such GHGs, including the EPA programs to regulate 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, EPA concluded that stationary sources would become subject to federal permitting requirements under the CAA starting in 2011. In 2010, the EPA issued a final rule, known as the ‘‘Tailoring Rule,’’ that defined regulatory emissions thresholds at which certain new and modified stationary sources would become subject to permitting and other requirements for GHG emissions under the CAA’s PSD and Title V programs. The EPA has indicated in rulemakings that it may reduce the current Tailoring Rule regulatory thresholds for GHGs, making additional, smaller sources subject to PSD permitting requirements but has declined to do so at this time. Permitting requirements for GHG emissions may also trigger permitting requirements for emissions of other regulated air pollutants as well. Some of our facilities have the potential to emit GHGs in excess of the Tailoring Rule’s 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 NSPS program. The EPA has already proposed to regulate GHG emissions from certain electric generating units under the NSPS program with a final regulation expected in 2013. While these proposed NSPS regulations for electric generating units would not directly apply to our operations, the EPA may propose a GHG NSPS for additional source categories that potentially could include our operations.

In addition, in 2009 the EPA published a final rule requiring that specified 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. 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.

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planned development of emission inventories or regional GHG “cap and trade” programs. Most 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, emit various types of GHGs, primarily methane and carbon dioxide, such new legislation or regulation could increase our costs related to operating and maintaining our facilities. Depending on the particular new law, regulation or program adopted, we could be required to incur capital expenditures for installing new emission controls on our facilities, acquire permits or other authorizations for emissions of GHGs from our 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, as is the case with similarly situated entities in the industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our pipeline, such recovery of costs in all cases is uncertain 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 an adverse effect on our business, financial position, results of operations and prospects.

EPA Regulation of Internal Combustion Engines

Internal combustion engines used in our operations are also subject to EPA regulation under the CAA. The EPA published new regulations on emissions of hazardous air pollutants from reciprocating internal combustion engines on August 20, 2010. On January 14, 2013, the EPA signed a final rule amending these regulations and it was published in the Federal Register on January 30, 2013. The EPA also revised the NSPS for stationary compression ignition and spark ignition internal combustion engines on June 28, 2011 and made minor amendments, included in the January 14, 2013 final rule. Compliance with these new regulations may require significant capital expenditures for physical modifications and may require operational changes as well. We are not able to estimate such increased costs, however, as is the case with similarly situated entities in the industry, they could be significant for us.

Regulation of Hydraulic Fracturing

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 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 instances, adopted and implemented. For example, 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 by the U.S. Department of Energy’s Shale Gas

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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.

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 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. On August 4, 2011 a citizens’ group petitioned the EPA to promulgate rules under the TSCA imposing requirements related to testing, identification, recordkeeping, and disclosure of chemical substances and mixtures in chemicals used in oil and gas exploration and production and hydraulic fracturing operations. The EPA partially granted the petition on November 23, 2011. In partially granting the petition, the EPA explained that it would propose rules using TSCA authorities to obtain data on chemical substances and mixtures regarding hydraulic fracturing. The EPA denied the petition insofar as it requested that the EPA invoke TSCA authorities to collect information on chemicals used in exploration and production sector in addition to those used in hydraulic fracturing. Some states have already imposed disclosure requirements associated with hydraulic fracturing, including states in which we operate.

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, or, in municipal settings, time, place and manner restrictions, on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. 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 adversely affected. Further, additional state legislation or regulation may impact our expansion plans by delaying implementation or by requiring additional approvals or modifications to expansion plans.

Recent EPA Rules Regarding Oil and Natural Gas Air Emissions

In addition, on April 17, 2012, the EPA approved final rules that establish new air emission controls for oil and natural gas production, pipelines and processing operations. These rules were published in the Federal Register on August 16, 2012 and became effective on October 15, 2012. 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 rule requires 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. 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 rules. 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 issued rules cannot be predicted. Additionally, on December 11, 2012, seven states submitted a notice of intent to sue the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and gas sources are appropriate, and, if so, to promulgate performance standards for methane

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emissions from the oil and gas sector, which was not addressed in the EPA rule that became effective on October 15, 2012. The notice of intent also requested EPA issue emission guidelines for the control of methane emissions from existing oil and gas sources. Depending on whether rules are promulgated and the applicability and restrictions in any promulgated rule, compliance with such rules could result in additional costs, including increased capital expenditures and operating costs. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for us. Compliance with such rules may also make it more difficult for our customers to operate, thereby reducing the volume of natural gas transported through our pipelines, which may adversely affect our business.

Hazardous Substances and Waste

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, nonhazardous and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of nonhazardous and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release or threatened release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or analogous state laws, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released or threatened to be released into the environment.

We also generate wastes that are subject to RCRA and comparable state laws. RCRA regulates both nonhazardous and hazardous solid wastes, but it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. It is possible that wastes used in our operations that are currently treated as non-hazardous wastes could be designated as “hazardous wastes” in the future, subjecting us to more rigorous and costly management and disposal requirements. It is also possible that federal or state regulatory agencies will adopt stricter management or disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the locations where these hydrocarbons and wastes have been transported for treatment or disposal. We could also have liability for releases or disposal on properties owned or leased by others. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners and operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.

Water

The federal CWA, the OPA, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including petroleum products, into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Unauthorized discharges can subject owners of regulated facilities to strict, joint, and potentially unlimited liability for containment and removal costs, natural resource damages and other consequences. Spill prevention, control and countermeasure requirements of federal laws and analogous state laws require us to maintain spill prevention control and countermeasure plans. These

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laws also require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. Regulations promulgated pursuant to OPA further require certain facilities to maintain oil spill prevention and oil spill contingency plans. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff and wastewater from certain types of facilities. These permits may require us to monitor and sample the stormwater runoff and wastewater from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Endangered Species

The ESA restricts activities that may affect endangered or threatened species or their habitats. While some our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unlisted endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development in the affected areas.

National Environmental Policy Act

The NEPA establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo a NEPA review. The Council on Environmental Quality has announced its intention to reinvigorate NEPA reviews, and, on March 12, 2012, issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our operations.

Employee Safety

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances.

Seasonality

Weather generally impacts natural gas demand for power generation and heating purposes, which in turn influences the value of transportation and storage. Price volatility also affects gas prices, which in turn influences drilling and production. Peak demand for natural gas typically occurs during the winter months, caused by the heating load. Nevertheless, because a high percentage of our revenues are derived from firm capacity reservation fees under long-term contracts, our transportation and storage revenues are not generally seasonal in nature. We experience some seasonality in our processing segment, as volumes at our processing facilities are slightly higher in the summer months.

Title to Properties and Rights-of-Way

Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and

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facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned much of these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership to such lands. We believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses, and we have no knowledge of any material challenge to our title to such assets or their underlying fee title.

Some of the leases, easements, rights-of-way, permits and licenses to be transferred to us at the closing of this offering require the consent of the grantor of such rights, which in certain instances is a governmental entity. We expect to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects as described in this prospectus.

Tallgrass Development or its affiliates may initially continue to hold record title to portions of certain assets until we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals that are not obtained prior to transfer. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, Tallgrass Development may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for our benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause its affiliates to retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from Tallgrass Development holding the title to any part of such assets subject to future conveyance or as our nominee.

Insurance

We generally share insurance coverage with Tallgrass Development, for which we will reimburse Tallgrass Development and its affiliates pursuant to the terms of the omnibus agreement. The Tallgrass Development insurance program includes general and excess liability insurance, auto liability insurance, workers’ compensation insurance and property insurance. We anticipate our general partner will maintain director and officer liability insurance under a separate policy from Tallgrass Development’s general partner. All insurance coverage is in amounts which management believes are reasonable and appropriate.

Facilities

We own two office buildings in Lakewood, Colorado, a portion of one of which is leased to Kinder Morgan, Inc., pursuant to a lease with an initial term through March 31, 2015. In addition, Tallgrass Development leases its corporate offices in Overland Park, Kansas. We pay a proportionate share of the costs to operate the building to Tallgrass Development pursuant to the omnibus agreement. Please read “Certain Relationships and Related Transactions—Omnibus Agreement.”

Employees

We do not have any employees. We are managed and operated by the board of directors and executive officers of our general partner. All of our executive management personnel will be employees of an affiliate of the general partner of Tallgrass Development and will devote the portion of their time to our business and affairs that is required to manage and conduct our operations. Under the terms of the omnibus agreement, we will reimburse Tallgrass Development for the provision of various general and administrative services for our benefit, for direct expenses incurred by Tallgrass Development on our behalf and for expenses allocated to us as a result of our becoming a publicly traded partnership. Please read “Certain Relationships and Related Transactions—Omnibus Agreement.”

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Legal Proceedings

In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us. While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings. We accrue legal or other direct costs related to loss contingencies when actually incurred. We have established reserves which we believe to be appropriate for pending matters, and after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any matter currently pending against us will not, individually or in the aggregate, materially affect our financial position, results of operations or liquidity.

Tallgrass Interstate Gas Transmission, LLC is the defendant in a lawsuit pending in state court in Douglas County, Nebraska (CI 10 9387384). Plaintiffs in the suit are Cornhusker Energy Lexington, LLC and its insurer, National Union Fire Insurance Company of Pittsburgh, Pennsylvania. The suit was initiated in February 2010. Plaintiffs allege that Cornhusker received natural gas that was transported on the TIGT System that did not meet required pipeline specifications, and that as a result Cornhusker’s ethanol plant suffered an explosion and subsequent fire. Plaintiffs seek monetary relief, attorney’s fees, costs and interest. A trial date of June 10, 2013 has been set by the Court. We plan to vigorously contest all of the claims in this matter.

Tallgrass Midstream, LLC is a party to a lawsuit in Fremont County, Wyoming (Civil No. 36823) arising out of the construction of the West Frenchie Draw amine treating plant. In March of 2009, Elkhorn Construction, Inc., a subcontractor on the project, filed a complaint against Tallgrass Midstream seeking to foreclose a mechanic’s lien. Tallgrass Midstream joined the general contractor, Newpoint Gas Services, Inc., as a defendant asserting a statutory duty to defend and a contractual duty to indemnify. Elkhorn seeks the unpaid portion of its lien claim, attorney’s fees and additional interest. Tallgrass Midstream asserted breach of contractual and statutory duties and indemnification claims against Newpoint seeking monetary damages, attorney’s fees and costs. Newpoint has asserted breach of contract and tort counterclaims against Tallgrass Midstream and seeks monetary damages, attorney’s fees and costs. A hearing was held on the remaining Elkhorn issues on January 16 and 17, 2013. The Newpoint and Tallgrass Midstream claims are scheduled for trial in June 2013. We plan to vigorously contest all remaining claims in this matter.

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MANAGEMENT

Management of Tallgrass Energy Partners, LP

Our general partner, Tallgrass MLP GP, LLC, will manage our operations and activities on our behalf through its directors and officers. References to “our officers” and “our directors” refer to the officers and directors of our general partner. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Directors of our general partner will oversee our operations. Tallgrass GP Holdings, which is owned and controlled by EMG, Kelso and certain members of our management team, 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. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. However, our general partner owes a duty to our unitholders. Our general partner will be 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 expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.

Upon the closing of this offering, we expect that our general partner will have seven directors, one of whom will be independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a publicly-traded limited partnership, such as ours, to have a majority of independent directors on the board of directors of its general partner or to establish a compensation or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the consummation of this offering. Please read “—Director Independence.”

In evaluating director candidates, Tallgrass GP Holdings will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

All of our general partner’s executive officers will also be employees of an affiliate of the general partner of Tallgrass Development and will devote such portion of their productive time to our business and affairs as is required to manage and conduct our operations. We will also utilize a significant number of employees of Tallgrass Management, LLC, an indirect wholly-owned subsidiary of Tallgrass GP Holdings, to operate our business and provide us with general and administrative services. Following the consummation of this offering, neither our general partner nor Tallgrass Development and its affiliates will receive any management fee or other compensation in connection with the management or operation of our business. However, our partnership agreement will require us to reimburse our general partner and its affiliates for all expenses it incurs and payments it makes on our behalf in connection with managing our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. In addition, the omnibus agreement will require us to reimburse Tallgrass Development’s general partner and its affiliates for expenses they incur in providing general and administrative services to us. Neither our partnership agreement nor the omnibus agreement will limit the amount of expenses for which our general partner or Tallgrass Development’s general partner and its affiliates may be reimbursed. Please read “Certain Relationships and Related Transactions—Agreements with Affiliates in Connection with the Transactions” and “The Partnership Agreement—Reimbursement of Expenses.”

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Directors and Executive Officers of Our General Partner

The following table shows information for the directors and executive officers of our general partner as of February 1, 2013.


Name	Age		Position with Tallgrass MLP GP, LLC
David G. Dehaemers, Jr.		52	President, Chief Executive Officer and Director
William R. Moler		46	Executive Vice President, Chief Operating Officer and Director
Gary J. Brauchle		39	Executive Vice President, Chief Financial Officer and Treasurer
George E. Rider		59	Executive Vice President, General Counsel and Secretary
Richard L. Bullock		57	Vice President, Human Resources, Tax and Risk Management
Frank J. Loverro		43	Director
Stanley de J. Osborne		43	Director
Jeffrey A. Ball		38	Director
John T. Raymond		42	Director

Our directors are appointed for a term of one year and hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

David G. Dehaemers, Jr. has been a director and President and Chief Executive Officer of our general partner since February 2013. Mr. Dehaemers has served as a director of the general partner of Tallgrass Development and as the President and Chief Executive Officer of Tallgrass Development and its general partner since August 2012. Prior to joining our general partner, Mr. Dehaemers served as Co-Founder, Chief Executive Officer and Chief Investment Officer of Tallgrass MLP Fund I, L.P., a private MLP Investment Fund from 2008 to 2012. Mr. Dehaemers also served as Executive Vice President of corporate development at Inergy, LP (“NRGY”) from 2003 to 2007. Mr. Dehaemers played a key role in NRGY’s corporate development group, where he focused on developing its long-term expansion strategies in the midstream area, which included acquisitions and expansion projects in excess of $500 million. Mr. Dehaemers also was an owner of Inergy Holdings, L.P. (“NRGP”) when that entity went public in 2005. Before Inergy, Mr. Dehaemers was part of the executive management team of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, LP from 1997 to 2003, where he served as the Chief Financial Officer from 1997 to 2000. In 2000, Mr. Dehaemers assumed responsibility for Kinder Morgan’s corporate development efforts, in which role he and his team developed and executed Kinder Morgan’s growth strategies. Mr. Dehaemers holds an undergraduate degree in Accounting from Creighton University in Omaha, Nebraska and is a Certified Public Accountant. He also holds a Juris Doctorate in Law from University of Missouri-Kansas City. We believe that Mr. Dehaemers’ education and experience, coupled with the leadership qualities demonstrated by his executive background, bring important experience and skill to the board of directors of our general partner.

William R. Moler has been a director and Chief Operating Officer and Executive Vice President of our general partner since February 2013 and has held the same positions for Tallgrass Development and its general partner since October 2012. From 2004 until his departure in October 2012, Mr. Moler served in various capacities with Inergy, L.P. and its affiliates, most recently as Senior Vice President and Chief Operating Officer of Inergy Midstream, L.P. and President and Chief Operating Officer—Natural Gas Midstream Operations of Inergy, L.P. Prior to joining Inergy, L.P., Mr. Moler was with Westport Resources Corporation from 2002 to 2004, where he served as both General Manager of Marketing and Transportation Services and General Manager of Westport Field Services, LLC. Prior to Westport, Mr. Moler served in various leadership positions at Kinder Morgan, Inc. from 1988 to 2002. Mr. Moler earned a Bachelor of Science degree in Mechanical Engineering from Texas Tech University in 1988. We believe that as a result of his background and knowledge, as well as the attributes of leadership demonstrated by his executive experience, Mr. Moler brings substantial experience and skill to the board of directors of our general partner.

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Gary J. Brauchle has been Executive Vice President, Chief Financial Officer and Treasurer of our general partner since February 2013 and has held the same positions for Tallgrass Development and its general partner since November 2012. Prior to joining Tallgrass, Mr. Brauchle was Vice President and Chief Accounting Officer at McDermott International, Inc., a global engineering and construction company serving the oil and gas industry during 2012 and as Corporate Controller from 2010 to 2012. He joined McDermott in 2003 and served in various positions of increasing responsibility, including as Director of Internal Audit from 2005 to 2007 and as Director of Operational Accounting and Assistant Controller for an operating subsidiary from 2007 to 2008 and 2008 to 2010, respectively. Mr. Brauchle also served in the Houston office of PricewaterhouseCoopers’ energy and utilities practice from 1997 to 2003, including as a Manager from 2001 to 2003, and with a focus on midstream master limited partnerships, or MLPs. Mr. Brauchle was a postgraduate technical assistant at the Financial Accounting Standards Board (FASB) from 1996 to 1997. Mr. Brauchle is a Certified Public Accountant and a graduate of Texas A&M University, where he received a Master of Science in Accounting in 1996 and a Bachelor of Business Administration in Accounting in 1995.

George E. Rider has been Executive Vice President, General Counsel and Secretary of our general partner since February 2013 and has held the same positions for Tallgrass Development and its general partner since August 2012. From 2008 to August 2012, Mr. Rider was Vice President and General Counsel for Tallgrass Capital, LLC and its affiliate, Tallgrass MLP Fund I, L.P., a private MLP Investment Fund. From 1986 to 2008, Mr. Rider was an attorney with the law firm of Stinson Morrison Hecker LLP, becoming a partner in 1987. Mr. Rider holds an undergraduate degree from Phillips University and a Juris Doctorate in Law from the University of Kansas, where he was a member of Order of the Coif.

Richard L. Bullock has been Vice President of Human Resources, Tax and Risk Management of our general partner since February 2013 and has held the same positions for Tallgrass Development and its general partner since November 2012. Previously, Mr. Bullock served as the Vice President, Chief Financial Officer and Treasurer of Tallgrass Development and its general partner. Mr. Bullock previously served as Vice President and Chief Financial Officer of Tallgrass MLP Fund I, L.P. from 2008 to 2011. Prior to Tallgrass, Mr. Bullock worked at Kinder Morgan Energy Partners, L.P. Mr. Bullock joined Kinder Morgan Energy Partners, L.P. in 1997 where he served as Vice President, Controller and Chief Accounting Officer through 2002 and, thereafter served as Vice President-Tax through October 2008. In those roles Mr. Bullock was principally responsible for all quarterly and annual SEC filings, integrating the accounting and financial reporting functions for acquisitions, tax compliance and tax planning for both Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. Mr. Bullock is a Certified Public Accountant licensed in Texas and Missouri. He received his undergraduate degree in Accounting from Missouri State University in Springfield, Missouri.

Frank J. Loverro has served as a director of our general partner since February 2013 and has held the same position for the general partner of Tallgrass Development since August 2012. Mr. Loverro joined Kelso in 1993 and has been Managing Director since 2004. He spent the preceding three years in the private equity investment and high yield groups at The First Boston Corporation. Mr. Loverro is also a director of Delphin Shipping LLC, Hunt Marcellus, LLC and Poseidon Containers Holdings LLC. Mr. Loverro received a B.A. in Economics with Distinction from the University of Virginia in 1991. Mr. Loverro has a broad investment management background across a variety of business sectors, as well as experience in the energy sector. We believe that this background provides an important source of insight and perspective to the board of directors of our general partner.

Stanley de J. Osborne has served as a director of our general partner since February 2013 and has held the same position for the general partner of Tallgrass Development since August 2012. Mr. Osborne joined Kelso in 1998 and has been Managing Director since 2007. He spent the preceding two years as an Associate at Summit Partners. He spent the previous three years at J.P. Morgan & Co. as an Associate in the Private Equity Group and an Analyst in the Financial Institutions Group. Mr. Osborne is also a director of Custom Building Products, Inc., Global Geophysical Services, Inc., Hunt Marcellus, LLC, Logan’s Roadhouse, Inc., Traxys S.a.r.l and Volt Power Holdco, LLC. Mr. Osborne was also director of CVR Energy, Inc. Mr. Osborne received a B.A. in

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Government from Dartmouth College in 1993. Mr. Osborne has a broad investment management background across a variety of business sectors, as well as experience in the energy sector. We believe that this background provides an important source of insight and perspective to the board of directors of our general partner.

Jeffrey A. Ball has served as a director of our general partner since February 2013 and has held the same position for the general partner of Tallgrass Development since August 2012. Mr. Ball is a Managing Director at EMG, a diversified natural resource private equity fund manager. Prior to joining EMG in 2007, Mr. Ball was a Director of investment banking at Credit Suisse Securities (USA), LLC covering the energy industry with a particular focus on MLPs and the midstream sector. We believe that Mr. Ball’s experience with mergers & acquisitions and financings of a variety of MLPs and other midstream assets will provide a valuable resource to the board of directors of our general partner.

John T. Raymond has served as a director of our general partner since February 2013 and has held the same position for the general partner of Tallgrass Development since August 2012. Mr. Raymond is an owner and founder of EMG, a diversified natural resource private equity fund manager, and has been Managing Partner and CEO since EMG’s inception in 2006. Previous to that time, Mr. Raymond held leadership positions with various energy companies, including President and CEO of Plains Resources Inc., President and Chief Operating Officer of Plains Exploration and Production Company and Director of Development for Kinder Morgan, Inc. We believe that Mr. Raymond’s experience with investment in and management of a variety of upstream and midstream assets and operations will provide a valuable resource to the board of directors of our general partner.

Committees of the Board of Directors

Audit Committee

Our general partner has an audit committee comprised of three directors, one of whom meets the independence standards and all of whom meet the experience standards established by the NYSE and the Exchange Act. Tallgrass GP Holdings will appoint two additional independent directors within one year following this offering. The non-independent member will step off the committee at that time. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

Conflicts Committee

Our general partner may, from time to time, have a conflicts committee to which the board of directors will appoint at least two independent directors and which may be asked to review specific matters that the board believes may involve conflicts of interest between us, our limited partners and Tallgrass GP Holdings. The conflicts committee will determine if the resolution of any conflict of interest referred to it by our general partner is in the best interests of our partnership. There is no requirement that our general partner seek the approval of the conflicts committee for the resolution of any conflict. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, may not hold an ownership interest in the general partner or its affiliates other than common units or awards under any long-term incentive plan, equity compensation plan or similar plan implemented by the general partner or the partnership, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee in good faith will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Any unitholder challenging any matter approved by the conflicts committee will have the burden of proving that the members of the conflicts committee did not subjectively believe that the

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matter was in the best interests of our partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where our general partner (or any members of the board of directors of our general partner including any member of the conflicts committee) reasonably believes the advice or opinion to be within such person’s professional or expert competence, shall be conclusively presumed to have been done or omitted in good faith.

Executive Compensation

We and our general partner were formed in Delaware in February 2013. Accordingly, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for its directors and executive officers for the 2012 fiscal year or prior periods. Because the executive officers of our general partner are employed by Tallgrass Management, compensation of the executive officers, other than the long-term incentive plan benefits described below, will be set by Tallgrass GP Holdings. The executive officers of our general partner will participate in employee benefit plans and arrangements sponsored by Tallgrass Management, including plans that may be established in the future. Our general partner has not entered into any employment agreements with any of its executive officers. We expect that compensation for our executive officers in 2013 will be structured under Tallgrass Management’s compensation program.

Compensation of Directors

Officers or employees of Tallgrass Development or its affiliates who also serve as directors of our general partner will not receive additional compensation for such service. Directors of our general partner who are not also officers or employees of Tallgrass Development or its affiliates will receive cash compensation on a quarterly basis as a retainer and for attending meetings of the board of directors and committee meetings as follows:

•

An annual cash retainer of $ .

•

For the audit committee chair and the conflicts committee chair, an annual committee chair retainer of $ .

In addition, each non-employee director will be reimbursed for out-of-pocket expenses in connection with attending meetings.

Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to a director indemnification agreement and our partnership agreement.

Directors of our general partner will be eligible to receive grants under the Tallgrass MLP GP, LLC Long-Term Incentive Plan. These non-employee directors are subject to unit ownership guidelines which require them to hold units (or unit equivalents, including phantom units) with a value equal to at least three times the annual cash retainer. Under the guidelines, directors have up to three years to acquire a sufficient number of units (or unit equivalents, including phantom units) to meet this requirement.

Long-Term Incentive Plan

Prior to closing, our general partner will adopt the Tallgrass MLP GP, LLC Long-Term Incentive Plan for officers, directors, employees and consultants of our general partner and its affiliates. We may issue our executive officers long-term equity based awards under the plan, which awards will be intended to compensate the officers based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under the long-term incentive plan to be adopted by us.

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Index to Financial Statements

The long-term incentive plan will consist of the following components: unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The long-term incentive plan will limit the number of units that may be delivered pursuant to vested awards to common units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan will be administered by the board of directors of our general partner or a committee thereof, which we refer to as the plan administrator.

The plan administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire on the earliest of (i) the date common units are no longer available under the plan for grants, (ii) termination of the plan by the plan administrator or (iii) the date 10 years following its date of adoption.

Restricted Units

A restricted unit is a common unit that vests over a period of time and during that time is subject to forfeiture. The plan administrator may make grants of restricted units containing such terms as it determines, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.

Phantom Units

A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives.

Unit Options

The long-term incentive plan will permit the grant of options covering common units. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options must have an exercise price that is not less than the fair market value of the common units on the date of the grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.

Unit Appreciation Rights

The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit appreciation rights must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.

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Index to Financial Statements

Distribution Equivalent Rights

The long-term incentive plan will permit the grant of distribution equivalent rights, or DERs, as a stand-alone award or with respect to phantom unit awards or other awards under the long-term incentive plan. DERs entitle the participant to receive cash or additional awards equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.

Other Unit-Based Awards

The long-term incentive plan will permit the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash or a combination thereof, as provided in the grant agreement.

Unit Awards

The long-term incentive plan will permit the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.

Change in Control; Termination of Service

Awards under the long-term incentive plan may vest and/or become exercisable, as applicable, upon a “change in control” of us or our general partner, if so provided by the plan administrator at the time of the grant. The consequences of the termination of a grantee’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

Source of Units

Common units to be delivered pursuant to awards under the long-term incentive plan may be common units acquired by our general partner in the open market, from any other person, directly from us or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term incentive plan, the total number of common units outstanding will increase.

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Index to Financial Statements

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that will be owned upon the consummation of this offering by:

•

each person known by us to be a beneficial owner of more than 5% of the units;

•

each of the directors of our general partner;

•

each of the named executive officers of our general partner; and

•

all directors and executive officers of our general partner as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

Percentage of total units to be beneficially owned after this offering is based on common units and subordinated units outstanding immediately following this offering. The table assumes that the underwriters’ option to purchase additional units is not exercised.


Name of Beneficial Owner(1)	Common Units To Be Beneficially Owned(2)	Percentage of Common Units To Be Beneficially Owned	Subordinated Units To Be Beneficially Owned	Percentage of Subordinated Units To Be Beneficially Owned	Percentage of Total Common and Subordinated Units To Be Beneficially Owned
Tallgrass Development(3)
David G. Dehaemers, Jr.
William R. Moler
Gary J. Brauchle
George E. Rider
Richard L. Bullock
Frank J. Loverro
Stanley de J. Osborne
Jeffrey A. Ball
John T. Raymond
All directors and executive officers as a group (nine persons)

*	An asterisk indicates that the person or entity owns less than one percent.

(1)	Unless otherwise indicated, the address for all beneficial owners in this table is c/o Tallgrass Energy Partners, LP, 6640 W. 143rd Street, Suite 200, Overland Park, Kansas 66223, Attn: General Counsel.

(2)	Does not include any units that may be purchased in our directed unit program. For further information regarding our directed unit program, please read “Underwriting.”

(3)

Tallgrass Development GP, LLC, as the general partner of Tallgrass Development, LP, has the sole voting and dispositive power with respect to the common units and the subordinated units owned by Tallgrass Development. Tallgrass Development GP, LLC is controlled by its board of directors, which currently consists of the following: David G. Dehaemers, Jr., William R. Moler, Frank J. Loverro, Stanley de J. Osborne, Jeffrey A. Ball and John T. Raymond. Each of the members of the board of directors of Tallgrass Development’s general partner may be deemed to own the common units and the subordinated units owned

by Tallgrass Development; however each disclaims beneficial ownership except to the extent of his pecuniary interest.

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Index to Financial Statements

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

After this offering, Tallgrass Development will own common units and subordinated units representing a % limited partner interest in us. In addition, our general partner will own a 2.0% general partner interest in us and the IDRs.

Distributions and Payments to Our General Partner and Its Affiliates

The following information summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The aggregate consideration received by our general partner and its affiliates, including Tallgrass Development, for the contribution of certain assets and liabilities to us consists of:

•

common units;

•

subordinated units;

•

general partner units representing a 2.0% general partner interest;

•

all of the IDRs;

•

the assumption of $ million of indebtedness from Tallgrass Development; and

•

a cash payment of approximately $ million to Tallgrass Development as reimbursement for certain capital expenditures made in connection with the contributed assets.

Operational Stage

Distributions of available cash to our general partner and its affiliates. We will generally make cash distributions % to unitholders pro rata, including Tallgrass Development as the holder of an aggregate of common units and all of the subordinated units, and 2.0% to our general partner, as the holder of our general partner units. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner, as the holder of the IDRs, will be entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target level. Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $ million on their general partner units and $ million on their common and subordinated units.

Payments to our general partner and its affiliates. Neither our general partner nor Tallgrass Development’s general partner and its affiliates receive a management fee or other compensation for managing us. Our general partner and Tallgrass Development’s general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf pursuant to our partnership agreement and the omnibus agreement. Neither our partnership agreement nor the omnibus agreement limit the amount of expenses for which our general partner or 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.

Withdrawal or removal of our general partner. If our general partner withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

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Index to Financial Statements

Liquidation Stage

Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Agreements with Affiliates in Connection with the Transactions

We have entered into or will enter into various documents and agreements with Tallgrass Development and its affiliates that will effect the transactions relating to our formation, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering, as well as transactions relating to the Pony Express Abandonment. These agreements will not be the result of arm’s-length negotiations. In addition, all of the transaction expenses incurred in connection with our formation transactions will be paid from the proceeds of this offering.

Contribution Agreement

Immediately prior to the closing of this offering, we will enter into a contribution, conveyance and assignment agreement, which we refer to as the contribution agreement, with Tallgrass Development and our general partner under which, among other things, Tallgrass Development will transfer to us 100% of the membership interests in Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC. We will also grant Tallgrass Development the right to receive the net proceeds from any exercise of the underwriters’ option to purchase additional common units as well as the right to receive any common units subject to such option which are not purchased by the underwriters upon the expiration of the option period.

Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with Tallgrass Development, its general partner and our general partner and certain of their affiliates that governs our relationship with them regarding the following matters:

•

the provision by Tallgrass Development’s general partner to us of certain administrative services and our agreement to reimburse it for such services;

•

the provision by Tallgrass Development’s general partner of such employees as may be necessary to operate and manage our business, and our agreement to reimburse it for the expenses associated with such employees;

•

certain indemnification obligations;

•

our use of the name “Tallgrass” and related marks; and

•

our right of first offer to acquire each of the remaining Retained Assets from Tallgrass Development.

Reimbursement of General and Administrative Expense

Pursuant to the omnibus agreement, the general partner of Tallgrass Development will, or will cause its affiliates to, perform centralized corporate, general and administrative services for us, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. In exchange, we will reimburse it for expenses incurred in providing these services. The 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. The omnibus agreement will further provide that we will reimburse the general partner of Tallgrass Development and its affiliates for our allocable portion of the premiums on any insurance policies covering our assets. We anticipate reimbursement to Tallgrass

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Index to Financial Statements

Development’s general partner and its affiliates 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 our current operations.

Right of First Offer

Under the terms of the omnibus agreement, Tallgrass Development will agree and will cause its affiliates to agree, for so long as Tallgrass Development or its affiliates, individually or as part of a group, control our general partner, that if Tallgrass Development or any of its affiliates decide to attempt to sell (other than to another affiliate of Tallgrass Development) any of the Retained Assets, Tallgrass Development or its affiliate will notify us of its desire to sell such Retained Asset and, prior to selling such Retained Asset to a third party, will negotiate with us exclusively and in good faith for a period of 45 days in order to give us an opportunity to enter into definitive documentation for the purchase and sale of such Retained Asset on terms that are mutually acceptable to Tallgrass Development or its affiliate and us. If we and Tallgrass Development or its affiliate have not entered into a letter of intent or a definitive purchase and sale agreement with respect to such Retained Asset within such 45-day period, Tallgrass Development or its affiliate will have the right to sell such Retained Asset to a third party following the expiration of such 45-day period on any terms that are acceptable to Tallgrass Development or its affiliate and such third party. Our decision to acquire or not to acquire a Retained Asset pursuant to this right will require the approval of the conflicts committee of the board of directors of our general partner.

Amendment and Termination

The omnibus agreement can be amended by written agreement of all parties to the agreement. However, we may not agree to any amendment or modification that would, in the determination of our general partner, be adverse in any material respect to the holders of our common units without the prior approval of the conflicts committee. In the event of (i) a “change in control” (as defined in the omnibus agreement) of the partnership or (ii) the removal of Tallgrass MLP GP, LLC as our general partner in circumstances where “cause” (as defined in our partnership agreement) does not exist and the common units held by our general partner and its affiliates were not voted in favor of such removal, the omnibus agreement (other than the indemnification and reimbursement provisions therein) will be terminable by the general partner of Tallgrass Development, and we will have a 180-day transition period to cease our use of the name “Tallgrass” and related marks.

Competition

Under our partnership agreement, Tallgrass Development and its affiliates are expressly permitted to compete with us. Tallgrass Development and any of its affiliates, including EMG and Kelso may acquire, construct or dispose of additional transportation, storage and processing or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

Contracts with Affiliates

Pony Express Abandonment

Tallgrass Interstate Gas Transmission, LLC has entered into a Purchase and Sale Agreement, or the Pony Express PSA, with Tallgrass Pony Express Pipeline, LLC, or Pony Express, whereby, subject to FERC approval, we, through our wholly-owned subsidiary Tallgrass Interstate Gas Transmission, LLC will (i) sell certain natural gas pipelines and related facilities that are currently part of the TIGT System and the natural gas service therefrom to Tallgrass Development for the purpose of converting the facilities into crude oil pipeline facilities serving the Bakken Shale and other nearby oil producing basins and (ii) construct and operate certain replacement-type facilities necessary to continue service to existing natural gas firm transportation customers following the proposed abandonment. The purpose of these coordinated actions is to efficiently re-deploy existing natural gas transmission assets to meet the growing market need to transport oil supplies from the Bakken shale while continuing to operate our natural gas transportation facilities to meet all current and expected needs of its natural gas customers.

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Index to Financial Statements

Specifically, the Pony Express PSA provides that we will sell an approximately 430-mile pipeline segment, three natural gas compressor stations totaling 33,175 horsepower, four meter stations, taps and certain ancillary facilities, collectively referred to in this prospectus as the Conversion System, to Tallgrass Development. Tallgrass Development will then convert, own and operate the Conversion System as a crude oil pipeline and construct an approximately 260-mile extension of the pipeline to provide access to Cushing, Oklahoma, collectively referred to as the Pony Express Project. In addition, we are obligated under the Pony Express PSA to construct one new mainline compressor station, two lateral pipelines, two booster compression units and certain auxiliary facilities, collectively referred to in this prospectus as the Replacement Gas Facilities, in order to continue service to certain existing firm shippers who desire continued firm service.

Pursuant to the Pony Express PSA, Tallgrass Development has agreed to 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 to 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) for costs incurred in obtaining gas pipeline transportation services for existing customers from other interstate pipelines for a minimum period of 5 years, and up to 10 years, 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. We expect to use all proceeds from the upfront payment of the actual net book value of the Pony Express Assets to pay down borrowings under our revolving credit facility.

We initially filed our application for approval of the Pony Express Abandonment with the FERC on August 6, 2012, and requested FERC approval by May 1, 2013. The closing under the Pony Express PSA and transfer of the Pony Express Assets is conditioned upon receipt of approval from the FERC and our completion of the Replacement Gas Facilities by Tallgrass Interstate Gas Transmission, LLC, which we currently anticipate will occur in the fourth quarter of 2013.

Procedures for Review, Approval or Ratification of Transactions with Related Persons

The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy. The transactions described above were not approved by an independent committee of our board of directors and the terms were determined by negotiation among the parties.

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Index to Financial Statements

CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Tallgrass Development, on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage us in a manner it believes is in our best interests. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing 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. Our partnership agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or our limited partners, on the other hand, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner. There is no requirement that our general partner seek the approval of the conflicts committee for the resolution of any conflict, however, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the conflicts committee on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if the resolution of the conflict is:

•

approved by the conflicts committee;

•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of 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 between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner does not seek approval from the conflicts committee and our general partner’s board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner’s board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in the best interests of the partnership or meets the specified standard, for example, a transaction on terms no less favorable to the partnership than those generally being provided to or available from unrelated third parties. Please read “Management—Committees of our Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

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Index to Financial Statements

Conflicts of interest could arise in the situations described below, among others.

Neither our partnership agreement nor any other agreement requires Tallgrass GP Holdings to pursue a business strategy that favors us.

The affiliates of our general partner, including Tallgrass GP Holdings, have fiduciary duties to make decisions in their own best interests and in the best interest of their owners, which may be contrary to our interests. Because some of the officers and directors of our general partner are also directors and/or officers of the ultimate owner of our general partner and of the general partner of Tallgrass Development, such directors and officers have fiduciary duties to affiliates of our general partner that may cause them to pursue business strategies that disproportionately benefit those affiliates or which otherwise are not in our best interests.

Our general partner’s affiliates may compete with us and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner are permitted to engage in other businesses or activities, including those that might be in direct competition with us. Tallgrass Development and its affiliates, including Kelso and EMG, may acquire, construct or dispose of pipeline, storage, processing or other assets in the future without any obligation to offer us the opportunity to acquire those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement between us and our general partner and its affiliates that does not receive unitholder or conflicts committee approval, must be 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

•

“fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Our general partner is allowed to take into account the interests of parties other than us, such as Tallgrass Development, in resolving conflicts of interest.

Our partnership agreement contains provisions that permissibly modify and reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duty or obligation whatsoever to us and our unitholders, including any duty to act in the best interests of us or 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

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Index to Financial Statements

language in the partnership agreement does not provide for a clear course of action. This 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 any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right, its voting rights with respect to the units it owns, whether to reset target distribution levels, whether to transfer the IDRs or the general partner interests it owns to a third party, whether to exercise its registration rights for the units it owns, and whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.

We do not have any officers or employees and rely solely on officers and employees of our general partner and its affiliates.

Affiliates of our general partner conduct businesses and activities of their own in which we have no economic interest. There could be material competition for the time and effort of the officers and employees who provide services to our general partner.

All of the officers of our general partner are also officers and/or directors of Tallgrass GP Holdings. These officers will devote such portion of their productive time to our business and affairs as is required to manage and conduct our operations. These officers are also required to devote time to the affairs of Tallgrass GP Holdings or its affiliates and are compensated by them for the services rendered to them and may, from time to time, face conflicts regarding the allocation of their time.

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

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable Delaware law. For example, our partnership agreement:

•

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

•

provides that the general partner shall not have any liability to us or our limited partners for decisions made in its capacity so long as such decisions are made in good faith;

•

generally provides that in a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our public 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 is either on terms no less favorable to us than those generally being provided to or available from unrelated third parties or is “fair and reasonable” to us, considering the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

•

provides that 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-

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Index to Financial Statements

appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or 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.

By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “—Duties of the General Partner.”

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

•

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into or exchangeable for equity interests of the partnership, and the incurring of any other obligations;

•

the purchase, sale or other acquisition or disposition of our equity interests, or the issuance of additional options, rights, warrants and appreciation rights relating to our equity interests;

•

the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

•

the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person;

•

the negotiation, execution and performance of any contracts, conveyances or other instruments;

•

the distribution of our cash;

•

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

•

the maintenance of insurance for our benefit and the benefit of our partners and indemnitees;

•

the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

•

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

•

the indemnification of any person against liabilities and contingencies to the extent permitted by law; and

•

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Please read “The Partnership Agreement” for information regarding the voting rights of unitholders.

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Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•

amount and timing of asset purchases and sales;

•

cash expenditures;

•

borrowings;

•

issuance of additional units; and

•

the creation, reduction or increase of reserves in any quarter.

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 capital expenditure, which does not reduce operating surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures” for a discussion on when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units.”

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and the IDRs. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•

enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the IDRs; or

•

hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates, but may not lend funds to our general partner or its affiliates.

Our general partner determines which of the costs it incurs on our behalf are reimbursable by us.

We reimburse our general partner and Tallgrass Development’s general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us pursuant to our partnership agreement and the omnibus agreement. Neither our partnership agreement nor the omnibus agreement will limit the 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. Please read “Certain Relationships and Related Transactions—Omnibus Agreement” and “The Partnership Agreement—Reimbursement of Expenses.”

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Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party to such agreements has recourse only to our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement permits our general partner to limit its or our liability, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner’s limited call right.

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 public unitholders at a price 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 common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. See “The Partnership Agreement—Limited Call Right.”

Limited partners have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the limited partners, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

We may not choose to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner 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 our general partner’s IDRs without the approval of the conflicts committee of our general partner or our unitholders. This may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right, at any time when there are no subordinated units outstanding, it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter, respectively, to reset the initial minimum quarterly distribution and cash target distribution levels at higher levels based on the average cash distribution amount per common unit for the two fiscal quarters prior to the exercise of the reset election. Following a reset election by our general partner, 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 (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 amount. We

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anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may be expected to experience, declines in the cash distributions it receives related to its IDRs and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of 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. 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 new common units to our general partner in connection with resetting the target distribution levels related to our general partner IDRs. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions—General Partner Interest and Incentive Distribution Rights.”

Duties of the General Partner

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Pursuant to these provisions, our partnership agreement contains various provisions replacing 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. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited or restricted by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our general partner in a manner beneficial both to its owner, Tallgrass GP Holdings, as well as to our limited partners. Without these provisions, the general partner’s ability to make decisions involving conflicts of interests would be restricted. These provisions benefit our general partner by enabling it to take into consideration all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions represent a detriment to the limited partners, however, because they restrict the remedies available to limited partners for actions that, without those provisions, might constitute breaches of fiduciary duty, as described below and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

•

the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary;

•

the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware law on our general partner; and

•

certain rights and remedies of limited partners contained in the Delaware Act.

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner of a Delaware limited partnership to use that amount of care that an ordinarily careful and prudent person would use in similar circumstances and to consider all material information reasonably available in making business decisions. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transaction were entirely fair to the partnership.

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Partnership agreement standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties under applicable state law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other standard under applicable law, other than the implied contractual covenant of good faith and fair dealing. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation whatsoever to us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. These standards reduce the obligations to which our general partner would otherwise be held under applicable Delaware law.

Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the public common unitholders or the conflicts committee of the board of directors of our general partner must be 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

•

If our general partner does not seek approval from the public 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 conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner 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. These standards reduce the obligations to which our general partner would otherwise be held. In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person 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.

Rights and remedies of limited partners

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has wrongfully refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of the partnership agreement.

A transferee of or other person acquiring a common unit will be deemed to have agreed to be bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Description of the Common Units—Transfer of Common Units.” The failure of a limited partner to sign our partnership agreement does not render the partnership agreement unenforceable against that person.

Under the partnership agreement, we must indemnify our general partner any person who is or was an affiliate of our general partner and any of their officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent

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jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the Securities and Exchange Commission such indemnification is contrary to public policy and therefore unenforceable. If you have questions regarding the duties of our general partner, please read “The Partnership Agreement—Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

•

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

•

special charges for services requested by a common unitholder; and

•

other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed or a successor has not accepted the appointment within days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer or admission is reflected in our register and such limited partner becomes the record holder of the common units so transferred. Each transferee:

•

will become bound and will be deemed to have agreed to be bound by the terms and conditions of our partnership agreement;

•

represents that the transferee has the capacity, power and authority to enter into our partnership agreement; and

•

makes the consents, acknowledgements and waivers contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

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We are entitled to treat the nominee holder of a common unit as the absolute owner in the event such nominee is the record holder of such common unit. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. Until a common unit has been transferred on our register, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•

with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

•

with regard to the duties of our general partner, please read “Conflicts of Interest and Duties”;

•

with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units”; and

•

with regard to allocations of taxable income and taxable loss, please read “Material Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized on February 6, 2013 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the ownership and operation of midstream energy assets, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

For a discussion of our general partner’s right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read “—Issuance of Additional Securities.”

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:

•

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

•

after the subordination period, the approval of a majority of the outstanding common units.

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In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

Issuance of additional units

No approval right.

Amendment of the partnership agreement

Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership

Unit majority. Please read “—Termination and Dissolution.”

Continuation of our business upon dissolution

Unit majority. Please read “—Termination and Dissolution.”

Withdrawal of the general partner

Under most circumstances, the approval of unitholders holding at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to , 2023 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of the General Partner.”

Removal of the general partner

Not less than 66 2/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of the General Partner.”

Transfer of the general partner interest

Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to , 2023. Please read “—Transfer of General Partner Units.”

Transfer of IDRs

Our general partner may transfer any or all of the IDRs without a vote of our unitholders to an affiliate or another person. Please read “—Transfer of Incentive Distribution Rights.”

Reset of incentive distribution levels

No approval right.

Transfer of ownership interests in our general partner

No approval right. Please read “—Transfer of Ownership Interests in the General Partner.”

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Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and otherwise acts in conformity with the provisions of the partnership agreement, the limited partner’s liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

•

to remove or replace the general partner;

•

to approve some amendments to the partnership agreement; or

•

to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the non-recourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

We conduct business in several states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner or member of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which our operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners or members for the obligations of a limited partnership or limited liability company have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners or members could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

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Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets and operations.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by us or our subsidiaries of equity interests, which may effectively rank senior to the common units.

Upon issuance of additional limited partner interests (other than the issuance of common units upon exercise by the underwriters of their option, or the expiration of the option, to purchase additional common units, the issuance of common units in connection with a reset of the incentive distribution target levels or the issuance of common units upon conversion of outstanding partnership interests), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner’s 2.0% interest in us 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. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The other holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

•

enlarge the obligations of any limited partner without its consent, unless such is deemed to have occurred as a result of an amendment approved by at least a majority of the type or class of limited partner interests so affected; or

•

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without its consent, which consent may be given or withheld at its option.

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The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of this offering, our general partner and its affiliates will own approximately % of the outstanding common and subordinated units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

•

a change in our name, the location of our principal office, our registered agent or our registered office;

•

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

•

a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from, in any manner, being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

•

an amendment that our general partner determines to be necessary or appropriate for the authorization or issuance of additional partnership interests;

•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

•

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

•

any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership or other entity, in connection with our conduct of activities permitted by our partnership agreement;

•

a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of such change;

•

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

•

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

•

do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

•

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

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•

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;

•

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain such an opinion.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our general partner or call a meeting of unitholders, must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

In addition, the partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell any or all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to the partnership agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction, and the partnership interests to be issued by us in such merger do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all

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Index to Financial Statements

of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the general partner determines that the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:

•

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

•

there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

•

the entry of a decree of judicial dissolution of our partnership; or

•

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner, other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal followed by approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

•

the action would not result in the loss of limited liability of any limited partner; and

•

neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes as a result of the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to the first day of the first quarter beginning after the tenth anniversary of this offering without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after the first day of the first quarter beginning after the tenth anniversary of this offering, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon

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90 days’ notice to the limited partners if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Units” and “—Transfer of Incentive Distribution Rights.”

Upon voluntary withdrawal of our general partner by giving written notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 33 1/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own % of the outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:

•

the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•

our general partner will have the right to convert its general partner interest and its IDRs into common units or to receive cash in exchange for those interests based on the fair market value of those interests as of the effective date of its removal.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and IDRs of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its IDRs for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest and its IDRs will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

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In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Except for transfer by our general partner of all, but not less than all, of its general partner units to:

•

an affiliate of our general partner (other than an individual); or

•

another entity as part of the merger or consolidation of our general partner with or into such entity or the transfer by our general partner of all or substantially all of its assets to such entity,

our general partner may not transfer all or any of its general partner units to another person prior to , 2023 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

At any time, the owner of our general partner may sell or transfer all or part of its ownership interest in our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

At any time, our general partner may sell or transfer its IDRs to an affiliate or third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Tallgrass MLP GP, LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of such class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

•

the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

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Index to Financial Statements

•

the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Federal Income Tax Consequences—Disposition of Common Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, a direct transferee of our general partner and its affiliates or a transferee of such direct transferee who is notified by our general partner that it will not lose its voting rights, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes unless the units were acquired in a transaction approved by the board of directors of our general partner. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our register. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

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Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•

our general partner;

•

any departing general partner;

•

any person who is or was an affiliate of a general partner or any departing general partner;

•

any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of our subsidiaries, us or any entity set forth in the preceding three bullet points;

•

any person who is or was serving as director, officer, managing member, manager, general partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates; and

•

any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We will purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against such liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us. Please read “Certain Relationships and Related Transactions—Omnibus Agreement.”

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will mail or make available by any reasonable means (including posting on or accessible through our or the SEC’s website) to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also mail or make available by any reasonable means (including posting on or accessible through our or the SEC’s website) summary financial information within 60 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

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Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

•

a current list of the name and last known address of each record holder;

•

copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and

•

certain information regarding the status of our business and financial condition.

Our general partner may, and intends to, keep confidential from the limited partners, trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Tallgrass MLP GP, LLC as general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

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Index to Financial Statements

UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby and assuming that the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates, including Tallgrass Development, will hold an aggregate of common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. All of the common units and subordinated units held by Tallgrass Development are subject to the lock-up restrictions described below. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

Rule 144

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act other than any units purchased in this offering through the directed unit program, which will be subject to the lock-up restrictions described below. None of the directors or officers of our general partner own any common units prior to this offering; however they may purchase common units through the directed unit program or otherwise. Assuming all of the units reserved for issuance under the directed unit program are sold to participants in the program, common units will be held by persons who have contractually agreed not to sell such units for 180 days following the date of this prospectus. Additionally, any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•

1.0% of the total number of the common units outstanding, which will equal approximately units immediately after this offering; or

•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our Partnership Agreement and Registration Rights

Our partnership agreement provides that we may issue an unlimited number of partnership interests of any type without a vote of the unitholders. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. See “The Partnership Agreement—Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold, which, immediately after this offering, will equal common units and subordinated units. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration

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Index to Financial Statements

rights for two years after it ceases to be our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Our general partner and its affiliates also may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

Lock-Up Agreements

We, our general partner and its affiliates, including Tallgrass Development, and the directors and executive officers of our general partner as well as all participants in the directed unit program have agreed with the underwriters not to sell or offer to sell any common units for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

Registration Statement on Form S-8

We intend to file a registration statement on Form S-8 under the Securities Act following this offering to register all common units issued or reserved for issuance under our long-term incentive plan. We expect to file this registration statement as soon as practicable after this offering. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements described above.

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Index to Financial Statements

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Baker Botts L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations promulgated under the Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Tallgrass Energy Partners, LP and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, trusts, partnerships and entities treated like partnerships for federal income tax purposes, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs), employee benefit plans or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Baker Botts L.L.P. and are based on the accuracy of the representations made by us.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Baker Botts L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Baker Botts L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

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Index to Financial Statements

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Pursuant to Code Section 731, distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and other products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Baker Botts L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code. Instead, we will rely on the opinion of Baker Botts L.L.P. on such matters. It is the opinion of Baker Botts L.L.P. that, based upon the Code, its regulations, published revenue rulings and court decisions and the representations described below that:

•

We will be classified as a partnership for federal income tax purposes; and

•

Each of our operating subsidiaries will be disregarded as an entity separate from us or will be treated as a partnership for federal income tax purposes.

In rendering its opinion, Baker Botts L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Baker Botts L.L.P. has relied are:

•

Neither we nor the operating subsidiaries has elected or will elect to be treated as a corporation; and

•

For every taxable year, more than 90% of our gross income has been and will be income of the type that Baker Botts L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Code.

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

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Index to Financial Statements

If we were taxed as a corporation for federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, pursuant to Code Section 301, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Baker Botts L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders will be treated as partners of Tallgrass Energy Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners Tallgrass Energy Partners, LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to the tax consequences of holding common units in Tallgrass Energy Partners, LP. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Tallgrass Energy Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections,” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. The income we allocate to common unitholders will generally be taxable as ordinary income. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Pursuant to Code Section 731, distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a

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distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, Section 465 of the Code requires the recapture of any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities under Section 752 of the Code, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, depletion recapture and/or substantially appreciated “inventory items,” each as defined in the Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2015, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. However, the ratio of taxable income to distributions for any single year in the projection period may be higher or lower. Thereafter, we anticipate that the ratio of taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the initial quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

•

gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

•

we make a future offering of common units and use the proceeds of this offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

A unitholder’s initial tax basis for his common units will be determined under Sections 722, 742 and 752 of the Code and will generally equal the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased under Section 705 of the Code by his share of our income and by any increases in his share of our nonrecourse liabilities and decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be

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capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value,” as defined in Treasury Regulations under Section 752 of the Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

Under Sections 704 and 465 of the Code, the deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations of Code Section 469 generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

Section 163 of the Code generally limits the deductibility of a non-corporate taxpayer’s “investment interest expense” to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

•

interest on indebtedness properly allocable to property held for investment;

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•

our interest expense attributed to portfolio income; and

•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated in Notice 88-75, 1988-2 C.B. 386, that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, under Section 704 of the Code, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of those distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Section 704(c) of the Code requires us to assign each asset contributed to us in connection with this offering a “book” basis equal to the fair market value of the asset at the time of this offering. Purchasers of units in this offering are entitled to calculate tax depreciation and amortization deductions and other relevant tax items with respect to our assets based upon that “book” basis, which effectively puts purchasers in this offering in the same position as if our assets had a tax basis equal to their fair market value at the time of this offering. In this context, we use the term “book” as that term is used in Treasury regulations under Section 704 of the Code. The “book” basis assigned to our assets for this purpose may not be the same as the book value of our property for financial reporting purposes.

Upon any issuance of units by us after this offering, rules similar to those of Section 704(c) described above will apply for the benefit of recipients of units in that later issuance. This may have the effect of decreasing the amount of our tax depreciation or amortization deductions thereafter allocated to purchasers of units in this offering or of requiring purchasers of units in this offering to thereafter recognize “remedial income” rather than depreciation and amortization deductions.

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In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required under the Section 704(c) principles described above, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•

his relative contributions to us;

•

the interests of all the partners in profits and losses;

•

the interests of all the partners in cash flows; and

•

the rights of all the partners to distributions of capital upon liquidation.

Baker Botts L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election,” “—Disposition of Common Units—Allocations Between Transferors and Transferees,” and “Uniformity of Units,” allocations under our partnership agreement will be given effect under Section 704 of the Code for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

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

•

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

•

any cash distributions received by the unitholder as to those units would be fully taxable; and

•

all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Baker Botts L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units—Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $179,500 ($89,750 for married individuals filing separately) of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

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Tax Rates

Currently, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. These rates are subject to change by new legislation at any time.

Section 1411 of the Code imposes a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “—Disposition of Common Units—Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets, or inside basis, under Section 743(b) of the Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us, including a purchaser of units in this offering. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets, or common basis, and (ii) his Section 743(b) adjustment to that basis.

The timing of deductions attributable to a Section 743(b) adjustment to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Section 704(c) type gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Section 704(c) principles with respect to an asset with respect to which the adjustment is allocable. Please read “—Allocation of Income, Gain, Loss and Deduction.” The timing of these deductions may affect the uniformity of our units. Please read “—Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less

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accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. Under Section 704 of the Code, the federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized under Section 709 of the Code and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to

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time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 20%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income each year, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS ruled in Rev. Rul. 84-53,1984-1 C.B. 159, that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

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Section 1259 of the Code can affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•

a short sale;

•

an offsetting notional principal contract; or

•

a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations under Section 706 of the Code that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Baker Botts L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required by regulations under Section 6050K of the Code to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year

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following the sale). A purchaser of units who purchases units from another unitholder is also generally required under Section 743 of the Code to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a sale may lead to the imposition of penalties under Section 6723 of the Code. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered under Section 708 of the Code to have terminated our tax partnership for federal income tax purposes upon the sale or exchange of our interests that, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced in an Industry Director Communication, LMSB-04-0210-006, a relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. Any non-uniformity could have an impact upon the value of our units. The timing of deductions attributable to Section 743(b) adjustments to the common basis of our assets with respect to persons purchasing units from another unitholder may affect the uniformity of our units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

For example, some types of depreciable assets are not subject to the typical rules governing depreciation (under Section 168 of the Code) or amortization (under Section 197 of the Code). If we were to acquire any assets of that type, the timing of a unit purchaser’s deductions with respect to Section 743(b) adjustments to the common basis of those assets might differ depending upon when and to whom the unit he purchased was originally issued. We do not currently expect to acquire any assets of that type. However, if we were to acquire a material amount of assets of that type, we intend to adopt tax positions as to those assets that will not result in any such lack of uniformity. Any such tax positions taken by us might result in allocations to some unitholders of smaller depreciation deductions than they would otherwise be entitled to receive. Baker Botts L.L.P. has not rendered an opinion with respect to those types of tax positions. Moreover, the IRS might challenge those tax positions. If we took such a tax position and the IRS successfully challenged the position, the uniformity of our units might be affected, and the gain from the sale of our units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

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Index to Financial Statements

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax under Section 511 of the Code on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it. Please read “Investment in Tallgrass Energy Partners, LP By Employee Benefit Plans.”

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered under Section 875 of the Code to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax under Section 884 of the Code at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under Rev. Rul. 91-32, 1991-1 C.B. 107, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take

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Index to Financial Statements

various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Baker Botts L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities under Section 6221 of the Code for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS pursuant to Section 6222 of the Code identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Additional Withholding Requirements

Under recently enacted legislation, the relevant withholding agent may be required to withhold 30% of any interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”) or gross proceeds from the sale of any property of a type which can produce interest or dividends from sources within the United States paid to (i) a foreign financial institution (for which purposes includes foreign broker-dealers, clearing organizations, investment companies, hedge funds and certain other investment entities) unless such foreign financial institution agrees to verify, report and disclose its U.S. accountholders and meets certain other specified requirements or (ii) a non-financial foreign entity that is a beneficial owner of the payment unless such entity certifies that it does not have any substantial U.S. owners or provides the name, address and taxpayer identification number of each substantial U.S. owner and such entity meets certain other specified requirements or otherwise qualifies for an exemption from this withholding. Under recently finalized Treasury Regulations, withholding only applies to payments of FDAP Income which are made after December 31, 2013, and to payments of relevant gross proceeds which are made after December 31, 2016. Non-U.S. and U.S. unitholders are encouraged to consult their own tax advisors regarding the possible implications of this legislation on their investment in our common units.

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Index to Financial Statements

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required under Section 6031 of the Code to furnish to us:

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;

•

a statement regarding whether the beneficial owner is:

•

a person that is not a U.S. person;

•

a foreign government, an international organization or any wholly-owned agency or instrumentality of either of the foregoing; or

•

a tax-exempt entity;

•

the amount and description of units held, acquired or transferred for the beneficial owner; and

•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required under Section 6031 of the Code to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by Section 6722 of the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed under Section 6662 of the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•

for which there is, or was, “substantial authority”; or

•

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Section 482 of the Code is 200% or more (or 50% or less) of the amount determined under Code Section 482 to be the correct amount of such price, or (c) the net Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts.

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Index to Financial Statements

No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20.0% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required under Treasury regulations under Section 6011 of the Code and related provisions to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “—Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions:

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-Related Penalties”;

•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

•

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

Recent Legislative Developments

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation 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 legislative proposal made during 2012 but which was not enacted would have eliminated the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. Please read “—Partnership Status.” We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business or own property in several states, most of which impose personal income taxes on individuals. Most of

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Index to Financial Statements

these states also impose an income tax on corporations and other entities. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. A unitholder may be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Baker Botts L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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Index to Financial Statements

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

An investment in us by an employee benefit plan or individual retirement account (“IRA”) is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and, along with IRAs, the restrictions imposed by Section 4975 of the Code. For these purposes, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities established or maintained by an employer or employee organization. Among other things, consideration should be given to:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

•

whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan or IRA, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan or IRA.

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans and IRAs from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the plan or IRA.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan or IRA should consider whether the plan or IRA will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(1)

the equity interests acquired by employee benefit plans are publicly offered securities (i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws);

(2)

the entity is an “operating company” (i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries); or

(3)

there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, and IRAs that are subject to ERISA or Section 4975 of the Code.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (1) and (2) above. However, no assurance can be given that legislative, administrative or judicial changes will not affect the accuracy of any statements herein with respect to transactions entered into or contemplated prior to the effective date of such changes.

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Index to Financial Statements

Moreover, governmental plans, certain church plans and non-U.S. plans, while not subject to the fiduciary responsibility or prohibited transaction provisions of ERISA or Section 4975 of the Code, may nevertheless be subject to other federal, state, local, non-U.S. or other laws that are substantially similar to the foregoing provisions of ERISA or the Code (“similar laws”).

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Code (and similar laws) in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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Index to Financial Statements

UNDERWRITING

Barclays Capital Inc. and Citigroup Global Markets Inc. are acting as representatives of the underwriters and as joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:


Underwriters		Number of Common Units
Barclays Capital Inc.
Citigroup Global Markets Inc.
Total

The underwriting agreement provides that the underwriters’ obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

•

the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;

•

the representations and warranties made by us and to the underwriters are true;

•

there is no material change in our business or the financial markets; and

•

we and , deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.


	No Exercise	Full Exercise
Per common unit	$	$
Total	$	$

We will pay a structuring fee equal to an aggregate of % of the gross proceeds from this offering (including any proceeds from the exercise of the option to purchase additional common units) to Barclays Capital Inc. and Citigroup Global Markets Inc. for the evaluation, analysis and structuring of our partnership.

The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per common unit. After the offering, the representatives may change the offering price and other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

We estimate that the expenses of this offering incurred by us will be approximately $ (excluding underwriting discounts and commissions and structuring fees).

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Index to Financial Statements

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

Lock-Up Agreements

We, our general partner and its affiliates, including Tallgrass Development, and the directors and executive officers of our general partner have agreed that, without the prior written consent of Barclays Capital Inc. and Citigroup Global Markets Inc., we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any of our common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units (other than (i) the common units being sold in this offering, (ii) common units issued pursuant to employee benefit plans, qualified option plans or other employee compensation plans existing on the date hereof; provided, that any recipient of such common units must agree in writing to be bound by these provisions for the remaining term of the lock-up period, (iii) common units or any securities that are convertible or exchangeable into common units pursuant to an effective registration statement that is filed on Form S-8 pursuant to clause (3) below), (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities (other than any registration statement on Form S-8) or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

The 180-day restricted period described in the preceding paragraph will be extended if:

•

during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or

•

prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of the material event unless such extension is waived in writing by Barclays Capital Inc. and Citigroup Global Markets Inc.

Barclays Capital Inc. and Citigroup Global Markets Inc., in their sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release the common units and other securities from lock-up agreements, Barclays Capital Inc. and Citigroup Global Markets Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

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Index to Financial Statements

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated among the representatives of the underwriters and us. In determining the initial public offering price of our common units, the representatives of the underwriters expect to consider:

•

the history and prospects for the industry in which we compete;

•

our financial information;

•

the ability of our management and our business potential and earning prospects;

•

the prevailing securities markets at the time of this offering; and

•

the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.

Indemnification

We and have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934.

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•

A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

•

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

•

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

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Index to Financial Statements

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Directed Unit Program

At our request, the underwriters have reserved up to % of the common units being offered by this prospectus for sale at the initial public offering price to persons who are directors, officers or employees of our general partner and its affiliates, or who are otherwise associated with us, through a directed unit program. The number of common units available for sale to the general public will be reduced by the number of directed units purchased by participants in the program. Except for certain officers and directors of our general partner who have entered into lock-up agreements as described in “—Lock-Up Agreements,” each person buying common units through the directed unit program has agreed that, for a period of 180 days from the date of this prospectus, he or she will not, without the prior written consent of Barclays Capital Inc. and Citigroup Global Markets Inc., dispose of or hedge any common units purchased in the program. For certain officers and directors of our general partner purchasing common units through the directed unit program, the lock-up agreements described in “—Lock-Up Agreements” shall govern with respect to their purchases. Barclays Capital Inc. and Citigroup Global Markets Inc., in their sole discretion, may release any of the securities subject to these lock-up agreements at any time without notice. Any directed units not purchased will be offered by the underwriters to the general public on the same basis as all other common units offered by this prospectus. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the directed units.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

We intend to apply to list our common units on the New York Stock Exchange under the symbol “TEP.” The underwriters will undertake to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange distribution requirements for trading.

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Index to Financial Statements

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

Stamp Taxes

If you purchase common units offered by this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. Certain of the underwriters and their affiliates have in the past, and the underwriters may in the future, perform investment banking, commercial banking, advisory and other services for us and our respective affiliates from time to time for which they have received, and may in the future receive, customary fees and expenses.

In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investment and securities activities may involve securities and instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

In connection with this offering, we intend to assume $ million of indebtedness from Tallgrass Development and to use a portion of the net proceeds from this offering, together with borrowings under our new revolving credit facility, to repay the debt assumed from Tallgrass Development. Affiliates of Barclays Capital Inc. and Citigroup Global Markets Inc. 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.

FINRA

Because the Financial Industry Regulatory Authority, Inc., or FINRA, is expected to view the common units offered hereby as interests in a direct participation program, there is no conflict of interest between us and the underwriters under Rule 5121 of the FINRA Rules and the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Restrictions

European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a “relevant member state”), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state, an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

217

Index to Financial Statements

•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant dealer or dealers nominated by the issuer for any such offer; or

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

United Kingdom

We may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000, or FSMA, that is not a “recognized collective investment scheme” for the purposes of FSMA, or CIS, and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

•

if we are a CIS and are marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended, or the CIS Promotion Order, or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

•

otherwise, if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended, or Financial Promotion Order, or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

•

in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”).

The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

218

Index to Financial Statements

Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006, or the CISA. Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Germany

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation or an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

219

Index to Financial Statements

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Baker Botts L.L.P., Austin, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The combined financial statements of Tallgrass Energy Partners Predecessor as of December 31, 2012 and for the period from November 13, 2012 to December 31, 2012, included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The combined financial statements of Tallgrass Energy Partners Pre-Predecessor as of December 31, 2011 and for the period from January 1, 2012 to November 12, 2012 and for the year ended December 31, 2011, included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The balance sheet of Tallgrass Energy Partners, LP as of February 6, 2013 included in this Prospectus has been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site and can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

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 any other person 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 only. Our business, financial condition, results of operations and prospects may have changed since that date.

Upon completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website is located at

220

Index to Financial Statements

www. .com and we make our periodic reports and other information filed with or furnished to the SEC available, 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 into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

221

Index to Financial Statements

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “could,” “will,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this prospectus include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our and Tallgrass Development’s infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

•

changes in general economic conditions;

•

competitive conditions in our industry;

•

actions taken by third-party operators, processors and transporters;

•

the demand for natural gas storage and transportation services;

•

our ability to successfully implement our business plan;

•

our ability to complete internal growth projects on time and on budget;

•

the price and availability of debt and equity financing;

•

the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;

•

competition from the same and alternative energy sources;

•

energy efficiency and technology trends;

•

operating hazards and other risks incidental to transporting, storing and processing natural gas;

•

natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•

interest rates;

•

labor relations;

•

large customer defaults;

•

changes in the availability and cost of capital;

•

changes in tax status;

•

the effects of existing and future laws and governmental regulations;

•

the effects of future litigation; and

•

certain factors discussed elsewhere in this prospectus.

Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.

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Index to Financial Statements

INDEX TO FINANCIAL STATEMENTS


TALLGRASS ENERGY PARTNERS UNAUDITED PRO FORMA FINANCIAL STATEMENTS:
Introduction			F-2
Unaudited Pro Forma Balance Sheet as of December 31, 2012			F-4
Unaudited Pro Forma Statement of Income for the Year Ended December 31, 2012			F-5
Notes to Unaudited Pro Forma Financial Data			F-6

TALLGRASS ENERGY PARTNERS PREDECESSOR AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR FINANCIAL STATEMENTS:
Reports of Independent Registered Accounting Firm			F-8
Combined Statements of Income for the period from November 13, 2012 to December 31, 2012 for Tallgrass Energy Partners Predecessor and the period from January 1, 2012 to November 12, 2012 and the year ended December 31, 2011 for Tallgrass Energy Partners Pre-Predecessor			F-10
Combined Statements of Comprehensive Income for the period from November 13, 2012 to December 31, 2012 for Tallgrass Energy Partners Predecessor and the period from January 1, 2012 to November 12, 2012 and the year ended December 31, 2011 for Tallgrass Energy Partners Pre-Predecessor			F-11
Combined Balance Sheets as of December 31, 2012 for Tallgrass Energy Partners Predecessor and as of December 31, 2011 for Tallgrass Energy Partners Pre-Predecessor			F-12
Combined Statements of Member’s Equity at January 1, 2011, December 31, 2011, November 12, 2012 and December 31, 2012 for Tallgrass Energy Partners Predecessor and Tallgrass Energy Partners Pre-Predecessor			F-13
Combined Statements of Cash Flows for the period from November 13, 2012 to December 31, 2012 for Tallgrass Energy Partners Predecessor and the period from January 1, 2012 to November 12, 2012 and the year ended December 31, 2011 for Tallgrass Energy Partners Pre-Predecessor			F-14
Notes to Combined Financial Statements			F-15

TALLGRASS ENERGY PARTNERS, LP FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm			F-39
Balance Sheet as of February 6, 2013			F-40
Notes to the Balance Sheet			F-41

F-1

Index to Financial Statements

TALLGRASS ENERGY PARTNERS

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

Introduction

The unaudited pro forma financial statements of Tallgrass Energy Partners, LP (the Partnership) as of and for the year ended December 31, 2012, are derived from the historical audited financial statements of the Predecessor Entities, our predecessor for accounting purposes set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical financial statements and related notes contained therein. These pro forma financial statements have been prepared to reflect the formation, initial public offering (the Offering) and related transactions of the Partnership. We refer to the Predecessor Entities as Tallgrass Energy Partners Pre-Predecessor, or TEP Pre-Predecessor, for periods prior to their acquisition from Kinder Morgan on November 13, 2012, and as Tallgrass Energy Partners Predecessor, or TEP Predecessor, beginning on November 13, 2012.

In connection with the closing of this Offering, Tallgrass Development, LP will contribute all of the membership interests in Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC, to the Partnership, which contribution will be recorded at historical cost as it is considered to be a reorganization of entities under common control. The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on 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 income statement for the year ended December 31, 2012. The unaudited pro forma financial statements have been prepared on the assumption that the Partnership will be treated as a partnership for federal income tax purposes. The unaudited pro forma financial statements should be read in conjunction with the notes accompanying such unaudited pro forma financial statements and with the historical financial statements and related notes set forth elsewhere in this prospectus.

The unaudited pro forma balance sheet and the unaudited pro forma statements of income were derived by adjusting the historical financial statements of the Predecessor Entities. The adjustments are based upon currently available information and certain estimates and assumptions. Actual effects of these transactions may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments are factually supportable and give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial data.

The unaudited pro forma financial statements give pro forma effect to the following adjustments, among others:

•

the contribution by Tallgrass Development of all of the partnership interests in Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC to us;

•

the repayment by us of $ million of assumed debt owed by a subsidiary of Tallgrass Development;

•

the issuance to a subsidiary of Tallgrass Development of common units and subordinated units, representing an aggregate % limited partner interest in us;

•

the issuance to our general partner of general partner units representing a 2.0% general partner interest in us and all of our IDRs;

•

the issuance of common units to the public in this offering, representing a % limited partner interest in us;

•

our entry into a new $ million revolving credit facility; and

F-2

Index to Financial Statements

•

the use of proceeds of this offering as described in “Use of Proceeds.”

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 FERC abandonment of the Pony Express Assets which we currently expect to occur in the fourth quarter of 2013.

F-3

Index to Financial Statements

TALLGRASS ENERGY PARTNERS

UNAUDITED PRO FORMA BALANCE SHEET

December 31, 2012


	Predecessor Historical		Pro Forma Adjustments				Pro Forma As Adjusted
ASSETS

Current assets
Cash and cash equivalents	$	—	$	261,000		(b)	$	—
				(16,313	)	(c)
				(4,787	)	(d)
				(3,900	)	(e)
				225,000		(f)
				(461,000	)	(g)
Accounts receivable		24,311		—				24,311
Gas imbalances		1,282		—				1,282
Inventories		2,204		—				2,204
Derivative assets at fair value		224		—				224
Prepayments		47		—				47

Total current assets		28,068		—				28,068
Property, plant, and equipment, net		669,476		—				669,476
Goodwill		301,852		—				301,852
Deferred Finance costs		13,352		(13,352	)	(g)		—
Other deferred charges		23,066		3,900		(e)		26,966

Total Assets	$	1,035,814	$	(9,452	)		$	1,026,362

LIABILITIES AND MEMBER’S EQUITY

Current Liabilities
Accounts payable	$	36,883	$	—			$	36,883
Gas imbalances		1,250		—				1,250
Derivative liabilities at fair value		23		—				23
Accrued taxes		3,465		(200	)	(h)		3,265
Current portion of long-term debt		4,000		(4,000	)	(g)		—
Accrued other current liabilities		26,233		—		(a)(g)		26,233

Total current liabilities		71,854		(4,200	)			67,654

Long-term debt		390,491		225,000		(f)		225,000
				(396,000	)	(g)
				5,509		(g)
Other Long-term Liabilities and Deferred Credits		1,635		—				1,635

Members’ equity/partners’ capital
Parent’s net investment		571,834		(61,000	)	(a)		—
				200		(h)
				(511,034	)	(i)
Common unitholders—public ( units issued and outstanding)		—		261,000		(b)		233,884
				(16,313	)	(c)
				(4,787	)	(d)
				(1,757	)	(g)
				(4,259	)	(g)
Common units, subordinated units and general partner interest—Tallgrass Development		—		511,034		(i)		498,189
				(3,752	)	(g)
				(9,093	)	(g)

Total members’ equity/partners’ capital		571,834		160,239				732,073

Total Liabilities and members’ equity/partners’ capital	$	1,035,814	$	(9,452	)		$	1,026,362

F-4

Index to Financial Statements

TALLGRASS ENERGY PARTNERS

UNAUDITED PRO FORMA STATEMENT OF INCOME

For the Year Ended December 31, 2012


	Period From Jan 1 to Nov 12, 2012		Period From Nov 13 to Dec 31, 2012			Basis Adjustment			Combined			Pro Forma Adjustments				Pro Forma As Adjusted
Revenues
Natural gas liquid sales	$	106,355	$	18,554		$	—		$	124,909		$	—			$	124,909
Natural gas sales		15,634		1,910			—			17,544			—				17,544
Transportation services		93,214		13,102			—			106,316			—				106,316
Other operating revenues		5,089		1,722			—			6,811			—				6,811

Total Revenues		220,292		35,288			—			255,580			—				255,580

Operating Costs and Expenses
Cost of sales and transportation services		98,585		17,711			—			116,296			—				116,296
Operations and maintenance		32,768		3,940			—			36,708			—				36,708
Depreciation and amortization		20,647		4,086			429			25,162			—				25,162
General and administrative		11,318		7,133			—			18,451			—				18,451
Taxes, other than income taxes		6,861		1,107			—			7,968			—				7,968

Total Operating Costs and Expenses		170,179		33,977			429			204,585			—				204,585

Operating Income		50,113		1,311			(429	)		50,995			—				50,995

Other Income (Expense)
Interest (expense) income, net		1,661		(3,201	)		—			(1,540	)		(1,436	)	(e)		(9,103	)
													(9,563	)	(f)
													3,436		(j)
													—
Other income (expense)		1		482			—			483			—				483

Total Other Income (Expense)		1,662		(2,719	)		—			(1,057	)		(7,563	)			(8,620	)

Income (loss) before Income Taxes		51,775		(1,408	)		(429	)		49,938			(7,563	)			42,375

Texas Margin Taxes		279		—			—			279			(279	)	(h)		—

Net Income (Loss)	$	51,496	$	(1,408	)	$	(429	)	$	49,659		$	(7,284)			$	42,375

General partner interest in net income
Common unitholders’ interest in net income
Subordinated unitholders’ interest in net income
Net income per common unit (basic and diluted)
Net income per subordinated unit (basic and diluted)

Weighted average number of limited partners’ units outstanding
Common units
Subordinated units

F-5

Index to Financial Statements

NOTES TO UNAUDITED PRO FORMA FINANCIAL DATA

1. Basis of Presentation, Transactions and this Offering

The historical financial information is derived from the audited historical financial statements of the Predecessor. The pro forma adjustments have been prepared as if this offering and the transactions described in this prospectus had taken place on 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 for the year ended December 31, 2012. The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments.

2. Pro Forma Adjustments and Assumptions

The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments. A general description of these transactions and adjustments is provided as follows:

The required reimbursement of $ million of capital expenditure to Tallgrass Development concurrent with the closing of this offering, which is expected to be fully repaid with net proceeds from the offering and borrowings under the revolving credit facility as described in notes f) and g) below.

The gross proceeds of $261.0 million from the issuance and sale of million common units at an initial public offering price of $ per unit. If the underwriters were to exercise their option to purchase additional common units in full, gross proceeds to the Partnership would equal $300 million.

The payment of estimated underwriting discounts and commissions and structuring fees.

The payment of offering expenses other than those discussed in Note c).

The payment of an estimated $3.9 million of fees and expenses on the Partnership’s revolving credit facility, which will be amortized over the life of the facility, and an estimated $0.6 million of annual commitment fees assuming that $ million is undrawn at the closing of this offering with a rate of 0.375% or unfunded commitments. In total, the amortization and commitment fees are estimated to be $1.4 million for the year ended December 31, 2012.

The proceeds of the estimated $ million to be borrowed at closing of this offering and the corresponding payment of interest expense on the Partnership’s revolving credit facility at an assumed interest rate on funded borrowings of 4.25%.

The $ million payment of net proceeds to a subsidiary of Tallgrass Development, representing repayment of $ million of debt, inclusive of $5.5 million of unamortized discount, and reimbursement of capital expenditures of $ million as described in Note a).

The elimination of the impact of Texas Margin Tax as the Partnership is a non-taxable entity and does not have any operations in Texas that would result in the applicability of Texas Margin Tax. As of December 31, 2012, $0.2 million adjustment to accrued taxes eliminates the current liability for this income-based tax. The remaining balance in accrued taxes as of December 31, 2012 primarily relates to property taxes.

Reflects the conversion of the adjusted parent net investment in the Predecessor of $511 million to common and subordinated units and the 2.0% general partner interest in the Partnership.

The elimination of interest expense, amortization of deferred financing costs and amortization of discount on debt assumed in connection with the acquisition of the Predecessor Entities by Tallgrass Development on November 13, 2012 because this debt is expected to be repaid at the closing of this offering as described in g) above.

F-6

Index to Financial Statements

3. Pro Forma Net Income per Unit

Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the net income and loss allocation provisions of the partnership agreement, to the common and subordinated unitholders under the two-class method, after deducting the general partner’s interest of 2% in the pro forma net income, by the number of common and subordinated units expected to be outstanding at the closing of this offering. For purposes of this calculation, we assumed that (1) the initial quarterly distribution was made to all unitholders for each quarter during the periods presented and (2) the number of units outstanding was million common units and million subordinated units. The common and subordinated unitholders represent 98% limited partner interests. All units were assumed to have been outstanding since January 1, 2012. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of the Partnership. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net income (loss) per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the period.

F-7

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

To the Partners of Tallgrass Energy Partners, LP:

In our opinion, the accompanying combined balance sheet and the related combined statement of income, of comprehensive income, of member’s equity and of cash flows present fairly, in all material respects, the financial position of Tallgrass Energy Partners Predecessor (“TEP Predecessor”) at December 31, 2012, and the results of their operations and their cash flows for the period from November 13, 2012 to December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of TEP Predecessor management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 18, 2013

F-8

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

To the Partners of Tallgrass Energy Partners, LP:

In our opinion, the accompanying combined balance sheets and the related combined statements of income, of comprehensive income, of member’s equity and of cash flows present fairly, in all material respects, the financial position of Tallgrass Energy Partners Pre-Predecessor (“TEP Pre-Predecessor”) at December 31, 2011, and the results of their operations and their cash flows for the period from January 1, 2012 to November 12, 2012 and the year ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of TEP Pre-Predecessor management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 18, 2013

F-9

Index to Financial Statements

TALLGRASS ENERGY PARTNERS PREDECESSOR

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

COMBINED STATEMENTS OF INCOME

(In Thousands)


	TEP Predecessor			TEP Pre-Predecessor
	Period from November 13 to December 31, 2012			Period from January 1 to November 12, 2012		Year Ended December 31, 2011
Revenues:
Natural gas liquid sales	$	18,554		$	106,355	$	151,627
Natural gas sales		1,910			15,634		28,339
Transportation services		13,102			93,214		123,018
Other operating revenues		1,722			5,089		4,059

Total Revenues		35,288			220,292		307,043

Operating Costs and Expenses:
Cost of sales and transportation services (exclusive of depreciation and amortization shown below)		17,711			98,585		146,069
Operations and maintenance		3,940			32,768		37,345
Depreciation and amortization		4,086			20,647		22,726
General and administrative		7,133			11,318		16,044
Taxes, other than income taxes		1,107			6,861		9,360

Total Operating Costs and Expenses		33,977			170,179		231,544

Operating Income		1,311			50,113		75,499

Other Income (Expense):
Interest (expense) income, net		(3,201	)		1,661		2,101
Other income		482			1		203

Total Other Income (Expense)		(2,719	)		1,662		2,304

Income (Loss) Before Income Taxes		(1,408	)		51,775		77,803
Texas Margin Taxes		—			279		296

Net Income (Loss) to Member	$	(1,408	)	$	51,496	$	77,507

The accompanying notes are an integral part of these combined financial statements.

F-10

Index to Financial Statements

TALLGRASS ENERGY PARTNERS PREDECESSOR

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

COMBINED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)


	TEP Predecessor			TEP Pre-Predecessor
	Period from November 13 to December 31, 2012			Period from January 1 to November 12, 2012			Year Ended December 31, 2011
Net (Loss) Income to Member	$	(1,408	)	$	51,496		$	77,507
Other Comprehensive Income:
Reclassification of change in fair value of derivatives to net income		—			(4,187	)		(3,410	)
Change in fair value of derivatives utilized for hedging purposes		—			1,024			6,146

Total Other Comprehensive (Loss) Income		—			(3,163	)		2,736

Comprehensive (Loss) Income	$	(1,408	)	$	48,333		$	80,243

The accompanying notes are an integral part of these combined financial statements.

F-11

Index to Financial Statements

TALLGRASS ENERGY PARTNERS PREDECESSOR

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

COMBINED BALANCE SHEETS

(In Thousands)


	TEP Predecessor		TEP Pre-Predecessor
	December 31, 2012		December 31, 2011
ASSETS
Current Assets:
Accounts receivable, net	$	24,311	$	23,832
Gas imbalances		1,282		5,221
Inventories		2,204		1,961
Derivative assets at fair value		224		3,721
Prepayments		47		33

Total Current Assets		28,068		34,768

Property, plant and equipment, net		669,476		719,009
Goodwill		301,852		—
Deferred finance costs allocated from TD		13,352		—
Other deferred charges		23,066		19,119

Total Assets	$	1,035,814	$	772,896

LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Accounts payable	$	36,883	$	19,523
Gas imbalances		1,250		720
Derivative liabilities at fair value		23		630
Accrued taxes		3,465		3,259
Current portion of long-term debt allocated from TD		4,000		—
Accrued other current liabilities		26,233		10,924

Total Current Liabilities		71,854		35,056

Long-term Debt Allocated from TD		390,491		—
Other Long-term Liabilities and Deferred Credits		1,635		1,032

Total Long-term Liabilities		392,126		1,032

Commitments and Contingencies (Notes 9 and 14)

Member’s Equity:
Member’s Capital		571,834		733,717
Accumulated other comprehensive income		—		3,091

Total Member’s Equity		571,834		736,808

Total Liabilities and Member’s Equity	$	1,035,814	$	772,896

The accompanying notes are an integral part of these combined financial statements.

F-12

Index to Financial Statements

TALLGRASS ENERGY PARTNERS PREDECESSOR

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

COMBINED STATEMENTS OF MEMBER’S EQUITY

(In Thousands)


	TEP Pre- Predecessor Member’s Capital			TEP Predecessor Member’s Capital			Accumulated Other Comprehensive Income			Total Member’s Equity
Member’s Equity at January 1, 2011	$	736,755		$	—		$	355		$	737,110

Net income to Member		77,507			—			—			77,507
Distributions to Member, net		(80,545	)		—			—			(80,545	)
Total change in fair value of derivatives, including a reclassification to earnings		—			—			2,736			2,736

Member’s Equity at December 31, 2011		733,717			—			3,091			736,808

Net income to Member		51,496			—			—			51,496
Distributions to Member, net		(57,661	)		—			—			(57,661	)
Total change in fair value of derivatives, including a reclassification to earnings		—			—			(3,163	)		(3,163	)


Member’s Equity at November 12, 2012	$	727,552		$	—		$	(72	)	$	727,480

TEP Predecessor’s acquisition of TIGT and TMID		—			573,242			—			573,242
Net loss to Member		—			(1,408	)		—			(1,408	)

Member’s Equity at December 31, 2012	$	—		$	571,834		$	—		$	571,834

The accompanying notes are an integral part of these combined financial statements.

F-13

Index to Financial Statements

TALLGRASS ENERGY PARTNERS PREDECESSOR

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS

(In Thousands)


	TEP Predecessor			TEP Pre-Predecessor
	Period from November 13 to December 31, 2012			Period from January 1 to November 12, 2012			Year Ended December 31, 2011
Cash Flows from Operating Activities:
Net (loss) income to Member	$	(1,408	)	$	51,496		$	77,507
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		4,481			20,647			22,726
(Gain) loss from sale of gas in underground storage		—			85			(6,903	)
Changes in components of working capital:
Accounts receivable		3,271			(3,749	)		3,879
Gas imbalances		(465	)		4,551			(4,212	)
Inventories		(145	)		(98	)		(205	)
Prepayments		416			(430	)		—
Accounts payable and accrued liabilities		4,226			6,286			(4,361	)
Regulatory assets		90			(250	)		1,018
Other, net		239			2,797			1,056

Net Cash Provided by Operating Activities		10,705			81,335			90,505

Cash Flows from Investing Activities:
Capital expenditures		(12,631	)		(19,540	)		(22,788	)
Net cash received for sale and purchase of gas in underground storage		—			(2,249	)		14,669
Disposal of property, plant and equipment (net of removal costs)		(56	)		97			(1,841	)

Net Cash Used in Investing Activities		(12,687	)		(21,692	)		(9,960	)

Cash Flows from Financing Activities:
Contributions from (distributions to) Member, net		—			(57,661	)		(80,545	)

Net Cash Used in Financing Activities		—			(57,661	)		(80,545	)

Net (Decrease) Increase in Cash and Cash Equivalents		(1,982	)		1,982			—
Cash and Cash Equivalents, beginning of period		1,982			—			—

Cash and Cash Equivalents, end of period	$	—		$	1,982		$	—

Schedule of Noncash Investing and Financing Activities:
Fair value of TIGT and TMID assets acquired by TEP Predecessor	$	1,029,399		$	—		$	—
Fair value of TIGT and TMID liabilities assumed by TEP Predecessor	$	(456,157	)	$	—		$	—

The accompanying notes are an integral part of these combined financial statements.

F-14

Index to Financial Statements

TALLGRASS ENERGY PARTNERS PREDECESSOR

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

1. Description of Business

The “Predecessor Entities” refers to both Tallgrass Energy Partners Predecessor (“TEP Predecessor”) and Tallgrass Energy Partners Pre-Predecessor (“TEP Pre-Predecessor”), which are comprised of the businesses described below that were historically owned by Kinder Morgan Energy Partners, LP (“KMP”). The general partner interest in KMP is owned by Kinder Morgan, Inc. (“KMI”). Kinder Morgan Operating L.P. “A” (“KMOLPA”) is a wholly-owned subsidiary of KMP. On May 1, 2012, the Federal Trade Commission (“FTC”) voted to accept a proposed settlement order regarding KMI’s then pending acquisition of El Paso Corporation (“EP”). The settlement order required KMI to divest certain assets held by KMP to an FTC-approved buyer within 180 days from May 25, 2012, the date that KMI consummated the EP acquisition. On August 20, 2012, KMP announced that it had entered into a purchase and sale agreement with Tallgrass Development, LP (“TD”) to sell those assets, a part of which comprise the Predecessor Entities, to TD for approximately $1.8 billion in cash and approximately $1.5 billion in assumed debt. The sale transaction closed on November 13, 2012.

The Predecessor Entities are referred to as TEP Predecessor for the period in which they were owned by TD, beginning November 13, 2012, and as TEP Pre-Predecessor for periods in which they were owned by KMOLPA, prior to November 13, 2012.

The businesses included in the Predecessor Entities consist of:

•

Kinder Morgan Interstate Gas Transmission LLC (“KMIGT”) was a wholly-owned subsidiary of KMOLPA which is regulated by the Federal Energy Regulatory Commission (“FERC”). KMIGT provides natural gas transportation and storage services to third-party natural gas distribution utilities and other shippers. KMIGT owns approximately 5,250 miles of natural gas transmission lines in Colorado, Kansas, Missouri, Nebraska and Wyoming.

•

Kinder Morgan Upstream LLC (“KMULLC”) is a Delaware limited liability company that owns and operates one treating and two processing plants in Wyoming. The sole member of KMULLC was KMOLPA.

As of the sale of these assets to TD on November 13, 2012, KMIGT was renamed Tallgrass Interstate Gas Transmission, LLC (“TIGT”) and KMULLC was renamed Tallgrass Midstream, LLC (“TMID”).

For additional information regarding the acquisition of TIGT and TMID, see Note 3 – Business Combinations.

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying combined financial statements were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America (“GAAP”). In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification. Certain prior period amounts have been reclassified to conform to the current presentation.

The combined financial statements of the Predecessor Entities include legal entities, as detailed above, that are indirect wholly-owned subsidiaries of the Predecessor Entities. As the combined financial statements reflect the TEP Predecessor and TEP Pre-Predecessor as single entities, significant intra-entity items have been

F-15

Index to Financial Statements

eliminated in the presentation. Net equity distributions of the Predecessor Entities included in the Combined Statements of Equity and Combined Statements of Cash Flows represent transfers of cash as a result of TD and KMI’s centralized cash management systems (described below).

The accompanying combined financial statements for TEP Predecessor as of December 31, 2012 and for the period from November 13, 2012 to December 31, 2012, and for TEP Pre-Predecessor as of December 31, 2011 and for the period from January 1, 2012 to November 12, 2012 and for the year ended December 31, 2011, are presented on a “held in use” basis. The combined financial statements were prepared in contemplation of the Predecessor Entities being contributed by TD to Tallgrass Energy Partners, LP (“TEP”), an entity formed on February 6, 2013 that is expected to initiate an initial public offering in 2013. TD’s conveyance of TIGT and TMID to TEP will be accounted for as a transfer of businesses between entities under common control in accordance with ASC 805. The combined financial statements for TEP Predecessor for the period from November 13, 2012 to December 31, 2012 reflect certain purchase accounting adjustments pursuant to the acquisition of TIGT and TMID as discussed in Note 1 – Description of Business. The TEP Predecessor’s financial data as presented on the combined statements of income, comprehensive income and cash flows and the combined balance sheets have been separated from the TEP Pre-Predecessor’s financial data by a bold black line.

Use of Estimates

Certain amounts included in or affecting these combined financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets and liabilities, the revenues and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on the Predecessor Entities’ business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Cash Equivalents and Supplemental Cash Flow Information

Prior to November 12, 2012, KMI employed a centralized cash management system that was utilized by KMP and its wholly-owned subsidiaries, including KMIGT and KMULLC. Subsequent to November 13, 2012, TIGT and TMID entered into similar cash management agreements with TD. In accordance with the cash management agreements, the subsidiary companies make loans on each business day equal to the amount swept from their depository bank accounts. At the beginning of the following month, the total of these loans for each company, less reimbursement payments under the agency agreements described below in Note 4 – Related Party Transactions, is transferred to an interest bearing account and are subsequently, periodically recorded as equity distributions.

The Predecessor Entities consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. TEP Predecessor made no cash payments for interest during the period from November 13, 2012 to December 31, 2012. TEP Pre-Predecessor made no cash payments for interest during the period from January 1, 2012 to November 12, 2012 or the year ended December 31, 2011.

The TEP Predecessor’s investing activities during the period from November 13, 2012 to December 31, 2012 include an increase in the accrual of liabilities for payment of property, plant and equipment of $5.3 million. The TEP Pre-Predecessor’s investing activities during the period from January 1, 2012 to November 12, 2012 include an increase in the accrual of liabilities for payment of property, plant and equipment of $1.9 million. There was no increase in the accrual of liabilities for payment of property, plant and equipment for the TEP Pre-Predecessor for the year ended December 31, 2011.

F-16

Index to Financial Statements

Accounts Receivable

The amounts reported in “Accounts receivable” in the accompanying Combined Balance Sheets as of December 31, 2012 and 2011 primarily consist of amounts due from unrelated third parties. For information on receivables due to us from related parties, see Note 4 – Related Party Transactions.

The Predecessor Entities make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The allowance for doubtful accounts was approximately $0 and $958,000 at December 31, 2012 and 2011, respectively.

Inventory

The Predecessor Entities’ inventories primarily consist of natural gas liquids, materials and supplies. Natural gas liquids are valued at historical cost adjusted for lower of cost or market. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence.

Accounting for Regulatory Activities

The Predecessor Entities’ regulated activities are accounted for in accordance with the “Regulated Operations” Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses to the Predecessor Entities associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. TEP Predecessor had recorded regulatory assets of $2.8 million included in “other deferred charges” in the Combined Balance Sheets at December 31, 2012. TEP Pre-Predecessor had recorded regulatory assets of $3.7 million included in “other deferred charges” in the Combined Balance Sheet at December 31, 2011. Regulatory assets at TEP Predecessor and TEP Pre-Predecessor at December 31, 2012 and 2011, respectively, were primarily attributable to unamortized FERC annual charge adjustments and costs associated with the Predecessor Entities’ participation in the TEP Pre-Predecessor Entity’s postemployment benefit plans. The regulatory assets at December 31, 2011 also included TIGT’s (formerly KMIGT) Section 5 rate case costs.

Property, Plant and Equipment

Property, plant and equipment for the TEP Predecessor was adjusted to fair value on November 13, 2012, the date the acquisition of TIGT and TMID by TEP Predecessor was completed. For additional information see Note 3 – Business Combinations.

Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage and any gain or loss recognized, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred.

Impairment of Long-Lived Assets

The Predecessor Entities review their long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset’s use and its eventual disposition are less than its carrying amount. Any such impairment losses at TIGT would be recorded as a regulatory asset until regulatory approval is received, at which time it would be recognized.

F-17

Index to Financial Statements

The Predecessor Entities assess their long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value.

Examples of long-lived asset impairment indicators include:

•

a significant decrease in the market value of a long-lived asset or group;

•

a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;

•

a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;

•

an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;

•

a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and

•

a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

When an impairment indicator is present, the Predecessor Entities first assess the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset to the carrying amount of the asset. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the assets is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized.

Gas in Underground Storage

Gas in underground storage represents the cost of base gas and cushion gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in the Predecessor Entities’ storage facilities. The Predecessor Entities record base gas and cushion gas as a component of property, plant and equipment.

The Predecessor Entities maintain working gas in its underground storage facilities on behalf of certain third parties. The Predecessor Entities receive a fee for its storage services but does not reflect the value of third party gas in the accompanying combined financial statements. The Predecessor Entities occasionally acquire volumes of working gas for its own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost of market.

F-18

Index to Financial Statements

Depreciation and Amortization

The TEP Pre-Predecessor computes depreciation using a composite method employed by applying a single depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The TEP Predecessor has elected to continue to use the composite depreciation method for its regulated assets at TIGT. The annualized rate of depreciation at TIGT ranges from 2.50% to 15.00% for the various classes of depreciable, regulated assets. For non-regulated assets at TMID, the TEP Predecessor has elected to use the straight-line method of depreciation. The useful lives for the various classes of depreciable assets at TMID are as follows:


		Range of Useful Lives (in years)
Processing & Treating		30
Vehicles		10
General & Other		3 - 13 ¹/₃

Gas Imbalances

Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements.

Deferred Financing Costs

Costs incurred in connection with the issuance of long-term debt were allocated from TD to the TEP Predecessor as discussed in Note 3 – Business Combinations and Note 8 – Long-term Debt. Deferred financing costs are deferred and amortized over the related financing period using the effective interest method.

Goodwill

As discussed in Note 3 – Business Combinations, the TEP Predecessor recorded approximately $301.9 million of goodwill on November 13, 2012 as a result of TD’s acquisition of TIGT and TMID. The TEP Predecessor evaluates goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. The TEP Predecessor’s annual impairment testing date is August 31^st.

The TEP Predecessor evaluates goodwill impairment by reporting unit level, which is an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach depending on facts and circumstances of the reporting unit. Examples of such facts and circumstances include the excess of fair value or carrying amount in the last valuation or changes in business environment. If the TEP Predecessor determines it is “more likely than not” that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two step test, the carrying amount of the reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When a Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss.

F-19

Index to Financial Statements

Revenue Recognition

The Predecessor Entities recognize revenues as services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. The Predecessor Entities provide various types of natural gas storage and transportation services to their customers in which the natural gas remains the property of these customers at all times.

Natural gas liquids sales occur in the Processing segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are purchased from our suppliers. Natural gas liquids revenues are recognized when goods are delivered and title has passed to the customer.

Natural gas sales occur in both the Gas Transportation and Storage segment and in the Processing segment. In the Gas Transportation and Storage segment, transportation services revenue is recognized when a portion of the natural gas transported by customers is collected as a contractual fee to compensate the Predecessor Entities for fuel consumed by pipeline and storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold we record natural gas sales revenue at the contractual sales price and cost of sales and transportation services at average cost. In addition, when operational conditions allow the Predecessor Entities occasionally sell “cushion gas,” which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our business needs.

Transportation services occur in the Gas Transportation and Storage segment. In many cases (generally described as “firm service”), the customer pays a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in the Predecessor Entities’ facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from the Predecessor Entities’ storage facilities. In other cases (generally described as “interruptible service”), there is no fee associated with the services because the customer accepts the possibility that service may be interrupted at the Predecessor Entities’ discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to the Predecessor Entities’ “firm” and “interruptible” transportation services, the Predecessor Entities also provides natural gas park and loan services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts.

Other operating revenues represent processing fees earned in the Processing segment. These fees are recognized when services are provided.

Environmental Costs

The Predecessor Entities expense or capitalize, as appropriate, environmental expenditures that relate to current operations. The Predecessor Entities expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. The Predecessor Entities do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. The Predecessor Entities had recorded environmental accruals of $4.0 million and $1.1 million at December 31, 2012 and 2011, respectively.

F-20

Index to Financial Statements

Fair Value

Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. The Predecessor Entities apply the fair value measurement guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill.

The fair value measurement accounting guidance requires that the Predecessor Entities make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments’ fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity.

Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments’ complexity.

To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:

•

Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;

•

Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and

•

Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).

Any transfers between levels within the fair value hierarchy are recognized at the end of the reporting period.

For information regarding financial instruments measured at fair value on a recurring basis, see Note 7 – Risk Management. For information regarding the fair value of financial instruments not measured at fair value in the combined balance sheets, see Note 8 – Long-term Debt.

Risk Management Activities

The Predecessor Entities utilize energy derivatives for the purpose of mitigating its risk resulting from fluctuations in the market price of natural gas and associated transportation. The Predecessor Entities record derivative contracts at their estimated fair values as of each reporting date. TEP Pre-Predecessor designated certain derivative instruments as qualifying hedges. TEP Predecessor has elected not to apply hedge accounting for these derivative instruments. For more information on The Predecessor Entities’ risk management activities, see Note 7 – Risk Management.

F-21

Index to Financial Statements

Income Taxes

The Predecessor Entities are comprised of limited liability companies that have elected to be treated as partnerships for income tax purposes. Accordingly, no provision for federal or state income taxes has been recorded in the financial statements of the Predecessor Entities and the tax effects of the Predecessor Entities’ activities accrue to their parents. TEP Pre-Predecessor historically incurred Texas Margin Taxes because it was a part of an affiliated group that generated sales in the State of Texas. Subsequent to the acquisition of TEP Pre-Predecessor by Tallgrass in November 2012, the TEP Predecessor is no longer a part of an affiliated group with sales in Texas and therefore will no longer be subject to Texas Margin Taxes or any other income-based taxes based on currently enacted tax legislation.

New Accounting Pronouncements Adopted

Accounting Standards Update (“ASU”) ASU No. 2011-04, Fair Value Measurements (Topic 820), “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” and ASU No. 2013-03, Financial Instruments (Topic 825), “Clarifying the Scope and Applicability of a Particular Disclosure to Nonpublic Entities”

On May 12, 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820), “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and IFRSs,” which amends the guidance for fair value measurements resulting in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and international financial reporting standards (“IFRS”). The amendment clarifies the guidance used to measure fair values and provides expanded disclosure requirements related to the valuation process of Level 3 measurements and sensitivity of Level 3 measurements to changes in unobservable inputs. In February 2013, the FASB issued ASU No. 2013-03, Financial Instruments (Topic 825), “Clarifying the Scope and Applicability of a Particular Disclosure to Nonpublic Entities,” which clarifies that the requirement under ASU No. 2011-04 to disclose the level of the fair value hierarchy within which the fair value measurements are categorized does not apply to nonpublic entities for items that are not measured at fair value in the statement of financial position but for which fair value is disclosed. ASU No. 2011-04 was effective January 1, 2012 for the Predecessor Entities. The adoption of ASU 2011-04 did not have a material impact on the financial statements of the Predecessor Entities.

Accounting Pronouncements Issued But Not Yet Effective

The following accounting standards have been issued, but are not yet effective for, and have not been adopted by the Predecessor Entities.

ASU No. 2013-02, Comprehensive Income (Topic 220), “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220), “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”. ASU 2013-02 does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, the amendments require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component, either on the face of the statement where net income is presented or in the notes, depending on whether or not the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. ASU 2013-02 is effective for nonpublic entities prospectively for reporting periods beginning after December 15, 2013, or January 1, 2014 for the Predecessor Entities. The adoption of ASU 2013-02 is not expected to have a material impact on the financial statements of the Predecessor Entities.

ASU No. 2011-11, Balance Sheet (Topic 210), “Disclosures about Offsetting Assets and Liabilities” and ASU No. 2013-01, Balance Sheet (Topic 210), “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities”

F-22

Index to Financial Statements

On December 16, 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210), “Disclosures about Offsetting Assets and Liabilities”. ASU 2011-11 requires entities to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. In January 2013, the FASB issued ASU No. 2013-01, Balance Sheet (Topic 210), “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarifies that the scope of ASU No. 2011-11 applies to derivatives accounted for in accordance with the Codification guidance for derivatives and hedging transactions, including bifurcated embedded derivatives, repurchase agreements and reverse purchase agreements, and certain securities borrowing and securities lending transactions. Entities are required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. All disclosures provided by those amendments are required to be provided retrospectively for all comparative periods presented. The adoption of ASU 2011-11 is not expected to have a material impact on the financial statements of the Predecessor Entities.

ASU No. 2012-02, Intangibles—Goodwill and Other (Topic 350), “Testing Indefinite-Lived Intangible Assets for Impairment”

On July 27, 2012, the FASB issued ASU No. 2012-02, Intangibles—Goodwill and Other (Topic 350), “Testing Indefinite-Lived Intangible Assets for Impairment” (“ASU 2012-02”). ASU 2012-02, which provides an entity with the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If after qualitative assessment, an entity concludes that it is not more likely than not (defined as having a likelihood of greater than 50%) that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount. An entity also has the option to bypass the qualitative assessment for any indefinite-lived intangible asset in any period and proceed directly to performing the quantitative impairment test. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, or January 1, 2013 for the Predecessor Entities. Early adoption is permitted. The adoption of ASU 2012-02 is not expected to have a material impact on the financial statements of the Predecessor Entities.

3. Business Combinations

On November 13, 2012, TD completed the acquisition of certain assets from KMP, including a 100% equity interest in both KMIGT and KMULLC, for approximately $1.8 billion in cash and approximately $1.5 billion of assumed debt as discussed in Note 1 – Description of Business. On November 13, 2012, KMIGT and KMULLC were renamed TIGT and TMID, respectively. Of the approximately $1.8 billion in cash paid to acquire the net assets, approximately $573.2 million was allocated to TIGT and TMID. The contribution of assets and liabilities from TD to TEP will be accounted for as a transaction with entities under common control under ASC 805.

F-23

Index to Financial Statements

The following represents the fair value of assets and liabilities at November 13, 2012 to be contributed by TD to TEP upon consummation of the transaction. The fair value is based on TD’s allocation of the purchase price for TIGT and TMID to the assets acquired and liabilities assumed (in thousands):


Cash	$	1,982
Accounts receivable and gas imbalances		29,821
Inventories		2,306
Other current assets		382
Property, plant and equipment		655,722
Other noncurrent assets		37,334
Accounts payable, accrued liabilities and gas imbalances		(34,137	)
Current portion of long-term debt		(4,000	)
Other current liabilities		(26,113	)
Long-term debt		(390,373	)
Other long-term liabilities and deferred credits		(1,534	)

Net identifiable assets acquired		271,390
Goodwill		301,852

Net assets acquired	$	573,242

At December 31, 2012, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. TD is in the process of obtaining additional information to identify and measure all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be retrospectively adjusted to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts.

On November 13, 2012, the carrying amount of property, plant and equipment was adjusted to its fair value on the date of acquisition.

A portion of the long-term debt held by TD is guaranteed by TIGT and TMID and expected to be assumed by the TEP Predecessor, and was therefore allocated to TIGT and TMID along with the related deferred finance costs at November 13, 2012. For additional information regarding long-term debt, see Note 8 – Long-term Debt.

The goodwill recorded at November 13, 2012 is expected to be deductible for tax purposes. Of the $301.9 million of goodwill, $73.7 million was assigned to the Processing segment and $228.2 million was assigned to the Gas Transportation and Storage segment. The goodwill is primarily attributable to (i) strategic location of the assets, including access to key supply sources and major customer demand markets; (ii) the complementary location of the assets relative to each other and relative to key market areas; (iii) growth opportunities through production growth requiring processing in the Rockies; (iv) future pipeline interconnects and fertilizer and power plant conversions that may potentially provide volume growth opportunities; and (v) a trained workforce.

The following unaudited pro forma financial information for the historical periods are presented as if the acquisition of TIGT and TMID had been completed on January 1, 2011. The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of the TEP Predecessor would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of KMI for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements.


	TEP Predecessor			TEP Pre-Predecessor
	Period from November 13 to December 31, 2012			Period from January 1 to November 12, 2012		Year Ended December 31, 2011
Revenue	$	35,288		$	220,292	$	307,043
Net (loss) income	$	(1,408	)	$	22,025	$	44,171

F-24

Index to Financial Statements

The pro forma revenue and net income includes adjustments for the period from January 1, 2012 to December 31, 2012 and the year ended December 31, 2011 to give effect to the following:

(a)

Reduction in net income to reflect additional depreciation expense associated with the increase in the cost of property, plant and equipment resulting from the allocation of the purchase price to the fair value of the assets and liabilities acquired.

(b)

Reduction in net income to reflect interest expense on the long-term debt allocated to TIGT and TMID in connection with the acquisition of TIGT and TMID by TD.

4. Related Party Transactions

The Predecessor Entities have no employees. KMI and KMP have historically provided and charged TEP Pre-Predecessor for all direct and indirect costs of services provided to us or incurred on our behalf including employee labor costs, information technology services, employee health and life benefits and insurance for property and casualty risks, and all other expenses necessary or appropriate to the conduct of our business. Beginning November 13, 2012, TEP provided and charged TEP Predecessor for similar direct and indirect costs of services. The Predecessor Entities record these costs on the accrual basis in the period in which KMI and KMP (or TEP, beginning November 13, 2012) incurs them. Each of the wholly-owned companies within the Predecessor Entities have agency arrangements with KMI and KMP (prior to November 13, 2012) and TEP (beginning November 13, 2012) under which KMI, KMP and TEP pay costs and expenses incurred by the companies of the Predecessor Entities, acting as agents for the Predecessor Entities’ companies, and are reimbursed by the companies of the Predecessor Entities for such payments. While the substance of the operating agreement remains the same, the cost structure under new management has changed, which affected the basis of certain allocations when the agreements transitioned from KMI and KMP to TEP.

Due to the cash management agreements discussed under “—Cash Equivalents and Supplemental Cash Flow Information” in Note 2 – Summary of Significant Accounting Policies, intercompany balances between TEP Pre-Predecessor entities are settled and treated as distributions.

Totals of transactions with affiliated companies are as follows (in thousands):


	TEP Predecessor			TEP Pre-Predecessor
	Period from November 13 to December 31, 2012			Period from January 1 to November 12, 2012		Year Ended December 31, 2011
Cost of sales and transportation services	$	(220	) ⁽¹⁾	$	3,893	$	(2,669	) ⁽¹⁾
Charges from the Predecessor Entities:
Directly charged wages and salaries:
Transportation services	$	156		$	844	$	994
Other deferred charges	$	46		$	95	$	55
Operation and maintenance	$	2,557		$	12,402	$	14,865
General and administrative	$	287		$	1,109	$	1,542
Other compensation and benefits:
Property, plant and equipment, net	$	34		$	208	$	254
Other deferred charges	$	10		$	35	$	20
Operation and maintenance	$	(6	)	$	472	$	1,143
General and administrative	$	478		$	4,848	$	9,442
Shared services:
General and administrative	$	4,713		$	2,003	$	2,172
Charges for other professional services:
Operation and maintenance	$	—		$	—	$	8
Property, plant and equipment purchases from:
The Predecessor Entities	$	—		$	—	$	1
Property, plant and equipment sales to:
The Predecessor Entities	$	—		$	1,948	$	—
NGPL PipeCo LLC	$	—		$	—	$	4

F-25

Index to Financial Statements

(1)

The TEP Predecessor has certain transactions with related parties in which activity relating to gas imbalance payables and receivables are recorded as “Cost of sales and transportation services.” For the period from November 13, 2012 to December 31, 2012 and the year ended December 31, 2011, gas imbalance payables to related parties decreased, resulting in negative cost of sales for those periods.

Details of balances with affiliates included in “Accounts receivable” and “Accounts payable” in the Combined Balance Sheets are as follows (in thousands):


	TEP Predecessor		TEP Pre-Predecessor
	December 31, 2012		December 31, 2011
Accounts receivable from affiliated companies:
Tallgrass Operations, LLC	$	6,244	$	—
NGPL PipeCo LLC		—		12
Rockies Express Pipeline LLC		219		—

Total accounts receivable from associated companies	$	6,463	$	12

Payables to affiliated companies:
Note payable to TD	$	1,381	$	—
Interest payable to TD		6		—
Accounts payable to Deeprock North, LLC		—		—	*
Accounts payable to River Consulting, LLC		—		7
Accounts payable to Rockies Express Pipeline LLC		—		3

Total payables to associated companies	$	1,387	$	10

*	Less than $1,000.

Balances of gas imbalances with affiliated shippers are as follows (in thousands):


	TEP Predecessor		TEP Pre-Predecessor
	December 31, 2012		December 31, 2011
Affiliate gas balance receivables	$	—	$	3,100

Affiliate gas balance payables	$	276	$	400

5. Inventory

The components of inventory at December 31, 2012 and 2011 consisted of the following (in thousands):


	TEP Predecessor		TEP Pre-Predecessor
	December 31, 2012		December 31, 2011
Materials and supplies	$	1,567	$	1,459
Natural gas liquids		637		502

Total inventory	$	2,204	$	1,961

F-26

Index to Financial Statements

6. Property, Plant and Equipment

Property, plant and equipment, net consisted of the following (in thousands):


	TEP Predecessor			TEP Pre-Predecessor
	December 31, 2012			December 31, 2011
Natural gas pipelines	$	421,644		$	669,323
Processing and treating assets		195,108			77,067
Buildings		15,518			23,389
Vehicles		3,138			8,616
Storage gas		2,345			6,654
Land		1,534			1,534
General and other		1,207			19,001
Construction work in progress		32,932			8,543
Accumulated depreciation and amortization		(3,950	)		(95,118	)

Total property, plant and equipment, net	$	669,476		$	719,009

Under a lease agreement effective November 13, 2012, TIGT leases a portion of its office space to KMI. Rental income for the period from November 13, 2012 to December 31, 2012 was approximately $145,000 and was recorded as other income in the accompanying combined income statements. As of December 31, 2012, future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands):


Year	Total
2013	$	1,090
2014		1,090
2015		817
2016		—
2017		—
Thereafter		—

Total	$	2,997

7. Risk Management

The Predecessor Entities enter into derivative contracts with third parties for the purpose of hedging exposures that accompany its normal business activities. The Predecessor Entities’ normal business activities expose it to risks associated with changes in the market price of natural gas. Specifically, these risks are associated with (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. Prior to November 13, 2012, the TEP Pre-Predecessor applied hedge accounting to these derivative contracts. As discussed below, the TEP Predecessor elected not to apply hedge accounting.

During the period from January 1, 2012 to November 12, 2012 and the year ended December 31, 2011, the TEP Pre-Predecessor recognized no gain or loss as a result of ineffectiveness of these hedges. The TEP Pre-Predecessor did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness. As the hedged sales and purchases take place and the TEP Pre-Predecessor records them into earnings, the TEP Pre-Predecessor also reclassifies the associated gains and losses included in accumulated other comprehensive income into earnings. During the period from January 1, 2012 to November 12, 2012 and the year ended December 31, 2011, no gain or loss was reclassified into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period.

F-27

Index to Financial Statements

The TEP Predecessor has elected not to apply hedge accounting for these derivative instruments, and the remaining amount of accumulated other comprehensive income was eliminated in purchase accounting. The TEP Predecessor has elected to mark to market derivative instruments and record changes in fair value in earnings effective November 13, 2012. As a result, the TEP Predecessor has no accumulated other comprehensive income as of December 31, 2012 expected to be reclassified to earnings in the next twelve months.

Fair Value of Derivative Contracts

The following table summarizes the fair values of the Predecessor Entities’ derivative contracts included in the accompanying Combined Balance Sheets (in thousands):

Fair Value of Derivative Contracts


		Derivative Assets
		TEP Predecessor			TEP Pre-Predecessor
		December 31, 2012			December 31, 2011
	Balance Sheet Location	Fair Value			Fair Value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Current assets	$	—		$	3,721

Derivatives not designated as hedging contracts
Derivative instruments	Current assets	$	224		$	—

Total derivative assets		$	224		$	3,721


		Derivative Liabilities
		TEP Predecessor			TEP Pre-Predecessor
		December 31, 2012			December 31, 2011
	Balance Sheet Location	Fair Value			Fair Value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Current liabilities	$	—		$	(630	)

Derivatives not designated as hedging contracts
Derivative instruments	Current liabilities	$	(23	)	$	—

Total derivative liabilities		$	(23	)	$	(630	)

As of December 31, 2012, the fair value shown for commodity contracts was comprised of derivative volumes totaling 1.7 billion cubic feet (“Bcf”) of both fixed-price swaps and basis swaps.

F-28

Index to Financial Statements

Effect of Derivative Contracts on the Income Statement

The following tables summarize the impact of the Predecessor Entities’ derivative contracts included in the accompanying Combined Statements of Income for the periods from November 13, 2012 to December 31, 2012, January 1, 2012 to November 12, 2012, and the year ended December 31, 2011 (in thousands):


Derivatives in cash flow hedging relationships:	Amount of gain/(loss) recognized in OCI on derivative (effective portion)
	TEP Predecessor		TEP Pre-Predecessor
	Period from November 13 to December 31, 2012		Period from January 1 to November 12, 2012		Year Ended December 31, 2011
Energy commodity derivative contracts	$	—	$	1,024	$	6,146

Derivatives in cash flow hedging relationships:

Amount of gain/(loss) reclassified from
Accumulated OCI into income
(effective portion)

Location of gain/
(loss) reclassified
from AOCI
into income
(effective portion)

TEP Predecessor

TEP Pre-Predecessor

Period from
November 13 to
December 31,
2012

Period from
January 1 to
November 12,
2012

Year Ended
December 31,
2011

Energy commodity derivative contracts

Natural gas sales

—

4,187

3,410

Derivatives not designated as hedging contracts:

Location of gain/
(loss) recognized in
income on
derivative

Amount of gain/(loss) recognized in income on
derivative

TEP Predecessor

TEP Pre-Predecessor

Period from
November 13 to
December 31, 2012

Period from
January 1 to
November 12, 2012

Year Ended
December 31, 2011

Energy commodity derivative contracts

Natural gas sales

416

—

Credit Risk

The Predecessor Entities have counterparty credit risk as a result of their use of financial derivative contracts. The Predecessor Entities’ counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may impact the Predecessor Entities’ overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

The Predecessor Entities maintain credit policies with regard to their counterparties that it believes minimize its overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings), (ii) collateral requirements under certain circumstances and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on its policies, exposure, credit and other reserves, the Predecessor Entities’ management does not anticipate a material adverse effect on their financial position, results of operations, or cash flows as a result of counterparty performance.

The Predecessor Entities’ over-the-counter swaps and options are entered into with counterparties outside central trading organizations such as a futures, options or stock exchange. These contracts are with a number of parties, all of which have investment grade credit ratings. While the Predecessor Entities enter into derivative transactions principally with investment grade counterparties and actively monitors their ratings, it is

F-29

Index to Financial Statements

nevertheless possible that from time to time losses will result from counterparty credit risk in the future. The maximum potential exposure to credit losses on the Predecessor Entities’ derivative contracts as of December 31, 2012 were (in thousands):


	Asset Position
Gross exposure	$	224
Netting agreement impact		—
Cash collateral held		—

Net exposure	$	224

In addition, in conjunction with the purchase of exchange-traded derivative contracts or when the market value of the Predecessor Entities’ derivative contracts with specific counterparties exceeds established limits, the Predecessor Entities are required to provide collateral to their counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2012 and 2011, the Predecessor Entities did not have any outstanding letters of credit in support of its hedging of commodity price risks associated with the sale of natural gas. As of December 31, 2012, the TEP Predecessor had no margin deposits with counterparties associated with energy commodity contract positions. As of December 31, 2011, the TEP Pre-Predecessor had margin deposits of $42,000 with counterparties associated with energy commodity contract positions. The Predecessor Entities also have agreements with certain counterparties to its derivative contracts that contain provisions requiring it to post additional collateral upon a decrease in its credit rating. As of December 31, 2012, TEP Predecessor had no derivative instruments with credit-risk-related contingent features in a net liability position and would not have to post additional collateral if a downgrade was triggered.

Fair Value

Derivative assets and liabilities are measured and reported at fair value as discussed in Note 2 – Summary of Significant Accounting Policies. Derivative contracts can be exchange-traded or over-the-counter (“OTC”). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. The Predecessor Entities value exchange-traded derivative contracts using quoted market prices for identical securities.

OTC derivatives are valued using models utilizing a variety of inputs including contractual terms; commodity and interest rate curves; and measures of volatility. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. The Predecessor Entities use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.

Certain OTC derivative contracts trade in less liquid markets with limited pricing information, and the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to the Predecessor Entities’ financial statements.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.

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Index to Financial Statements

The following tables summarize the fair value measurements of the Predecessor Entities’ energy commodity derivative contracts as of December 31, 2012 and 2011 based on the fair value hierarchy established by the Codification (in thousands):


	Asset fair value measurements using
	Total			Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
TEP Predecessor as of December 31, 2012
Energy commodity derivative contracts	$	224		$	—	$	224		$	—

TEP Pre-Predecessor as of December 31, 2011
Energy commodity derivative contracts	$	3,721		$	—	$	3,709		$	12

	Liability fair value measurements using
	Total			Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)			Significant unobservable inputs (Level 3)
TEP Predecessor as of December 31, 2012
Energy commodity derivative contracts	$	(23	)	$	—	$	(23	)	$	—

TEP Pre-Predecessor as of December 31, 2011
Energy commodity derivative contracts	$	(630	)	$	—	$	(266	)	$	(364	)

The table below provides a summary of changes in the fair value of the Predecessor Entities’ significant unobservable inputs (Level 3) energy commodity derivative contracts (in thousands):


	TEP Predecessor		TEP Pre-Predecessor
	Period from November 13 to December 31, 2012		Period from January 1 to November 12, 2012			Year Ended December 31, 2011
Derivatives-net asset (liability):
Beginning of period	$	—	$	(352	)	$	(124	)
Total gains or (losses)
Included in other comprehensive income		—		(61	)		(1,099	)
Settlements		—		156			871
Transfers out of Level 3		—		257			—

End of period	$	—	$	—		$	(352	)

The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets held at the reporting date	$	—	$	—		$	—

As of December 31, 2011, the TEP Pre-Predecessor’s natural gas basis swaps were reported at fair value using Level 3 inputs due to such derivatives not having observable market prices. Fair value of natural gas basis swaps is determined using a third party pricing service which assimilates transactional data through multiple broker sources, applies seasonality shaping, and eliminates outliers through a rigorous quality control process. During the period from January 1, 2012 to November 12, 2012, derivative liabilities with a fair value of $257,000 were transferred from Level 3 to Level 2 as the level of observable inputs used to value those instruments was deemed to be significant.

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Index to Financial Statements

8. Long-term Debt

As discussed in Note 3 – Business Combinations, long-term debt with outstanding principal of $400 million, along with the corresponding discount and deferred financing costs, were allocated to the TEP Predecessor on November 13, 2012. The long-term debt is held by TD and guaranteed by TIGT and TMID. The TEP Predecessor is expected to assume the debt subsequent to December 31, 2012.

On November 13, 2012, TD entered into a credit agreement with a syndicate of lenders which includes a term loan, a delayed draw term loan and a revolving credit facility. As of December 31, 2012, only the term loan had been drawn. The term loan bears interest at a variable rate equal to LIBOR + 4.00% and matures November 13, 2018. The variable interest rate is subject to a LIBOR floor of 1.25%. In 2013, TD purchased interest rate caps to limit exposure to the floating rate.

The Predecessor Entities’ long-term debt, all of which has been allocated from TD, consisted of the following at December 31, 2012 and 2011 (in thousands):


	TEP Predecessor			TEP Pre-Predecessor
	December 31, 2012			December 31, 2011
LIBOR + 4.00% term loan due 2018	$	400,000		$	—
Unamortized discount		(5,509	)		—

Total principal allocated from TD		394,491			—
Current maturities		(4,000	)		—

Total long-term debt allocated from TD	$	390,491		$	—

The following table presents the scheduled maturities of principal amounts of TD’s long-term debt allocated to the TEP Predecessor (in thousands):


Year	Total
2013	$	4,000
2014		4,000
2015		4,000
2016		4,000
2017		4,000
Thereafter		380,000

Total	$	400,000

The debt allocated from TD is carried at amortized cost. The carrying amount and fair value of the debt at December 31, 2012 was approximately $394.5 million and $404.0 million, respectively. The fair value of the debt is estimated based on quoted market prices. The TEP Predecessor is not aware of any factors that would significantly affect the estimated fair value since December 31, 2012.

9. Commitments and Contingent Liabilities

Leases

Rent expense under operating leases totaled approximately $79,000, $511,000 and $248,000 for the periods from November 13, 2012 to December 31, 2012, January 1, 2012 to November 12, 2012 and the year ended December 31, 2011, respectively.

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Index to Financial Statements

At December 31, 2012, future minimum rental commitments under major non-cancelable operating leases were as follows (in thousands):


Year	Total
2013	$	100
2014		103
2015		104
2016		105
2017		79
Thereafter		86

Total	$	577

Capital Expenditures

Approximately $31.3 million had been committed for the future purchase of property, plant and equipment at December 31, 2012.

10. Member’s Equity

As discussed in Note 1 – Description of Business, TEP Predecessor completed the acquisition of the TEP Pre-Predecessor subsidiary entities on November 12, 2012. During the year ended December 31, 2011, there were no material changes in TEP Pre-Predecessor’s ownership interests in its subsidiaries.

Distributions and Contributions

As discussed in Note 2 – Summary of Significant Accounting Policies, the net amount of transfers for loans made each day through the centralized cash management system, less reimbursement payments under the agency agreement described in 4 – Related Party Transactions, is recognized periodically as equity distributions or contributions. There were no distributions to the TEP Predecessor members during the period from November 13, 2012 to December 31, 2012. Net distributions to the TEP Pre-Predecessor members for the period from January 1, 2012 to November 12, 2012 and the year ended December 31, 2011 were $57.7 million and $80.5 million, respectively.

11. Major Customers and Concentration of Credit Risk

During the period from November 13, 2012 to December 31, 2012, one non-affiliated customer accounted for $11.2 million (32%) of TEP Predecessor’s total operating revenues. During the period from January 1, 2012 to November 12, 2012, one non-affiliated customer accounted for $68.9 million (31%) of TEP Pre-Predecessor’s total operating revenues. In 2011, one non-affiliated customer accounted for $101.3 million (33%) of TEP Pre-Predecessor’s total operating revenues.

TIGT’s (formerly KMIGT) principal delivery market area encompasses the states of Colorado, Kansas, Missouri, Nebraska and Wyoming. TIGT is a large transporter of natural gas to the mid-continent market. For the year ended December 31, 2012, TIGT delivered an average of 396,000 MMBtus per day of natural gas to this market. TIGT has a number of individually significant customers, including local natural gas distribution companies in the mid-continent area and major natural gas marketers. Over 80% of TIGT’s total system firm transport capacity is currently subscribed, with 63% of TIGT’s transport business in 2012 being conducted with its top ten shippers. TIGT mitigates credit risk by requiring collateral or financial guarantees and letters of credit from customers with specific credit concerns. In support of credit extended to certain customers, TIGT/KMIGT had received prepayments of $3.4 million and $3.3 million at December 31, 2012 and 2011, respectively, included in the caption “Accrued other current liabilities” in the accompanying Combined Balance Sheets.

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Index to Financial Statements

12. Reporting Segments

Our operations are located in the United States and are organized into two reporting segments: (1) Gas Transportation and Storage, and (2) Processing.

Gas Transportation and Storage

The Predecessor Entities’ Gas Transportation and Storage segment is engaged in ownership and operation of interstate natural gas pipelines and related natural gas storage facilities that provide services to third-party natural gas distribution utilities and other shippers.

Processing

The Predecessor Entities’ Processing segment is engaged in ownership and operation of natural gas processing and treating facilities that produce natural gas liquids and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets.

These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations.

The following tables set forth the Predecessor Entities’ segment information for the periods indicated, in thousands:


TEP Predecessor for period from November 13, 2012 to December 31, 2012	Gas Transportation and Storage			Processing		Eliminations			Total
Revenues from external customers	$	13,316		$	21,972	$	—		$	35,288
Inter-segment revenues		96			—		(96	)		—

Total revenues		13,412			21,972		(96	)		35,288

Operating costs and expenses		10,759			19,228		(96	)		29,891
Depreciation and amortization		3,263			823		—			4,086

Total operating costs and expenses		14,022			20,051		(96	)		33,977

Operating (loss) income		(610	)		1,921		—			1,311

Interest expense, net		(3,201	)		—		—			(3,201	)
Other income		482			—		—			482

Net (loss) income	$	(3,329	)	$	1,921	$	—		$	(1,408	)

Total assets	$	741,595		$	294,219	$	—		$	1,035,814

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Index to Financial Statements


TEP Pre-Predecessor for period from January 1, 2012 to November 12, 2012	Gas Transportation and Storage			Processing			Eliminations			Total
Revenues from external customers	$	103,306		$	116,986		$	—		$	220,292
Inter-segment revenues		696			—			(696	)		—

Total revenues		104,002			116,986			(696	)		220,292

Operating costs and expenses		51,544			98,684			(696	)		149,532
Depreciation and amortization		17,895			2,752			—			20,647

Total operating costs and expenses		69,439			101,436			(696	)		170,179

Operating income		34,563			15,550			—			50,113

Interest income, net		1,661			—			—			1,661
Other income		1			—			—			1
Texas Margin Taxes		(213	)		(66	)		—			(279	)

Net income	$	36,012		$	15,484		$	—		$	51,496

Total assets	$	676,426		$	91,255		$	—		$	767,681


TEP Pre-Predecessor for the Year Ended December 31, 2011	Gas Transportation and Storage			Processing			Eliminations			Total
Revenues from external customers	$	148,535		$	158,508		$	—		$	307,043
Inter-segment revenues		601			—			(601	)		—

Total revenues		149,136			158,508			(601	)		307,043

Operating costs and expenses		76,475			132,944			(601	)		208,818
Depreciation and amortization		19,751			2,975			—			22,726

Total operating costs and expenses		96,226			135,919			(601	)		231,544

Operating income		52,910			22,589			—			75,499

Interest income, net		2,101			—			—			2,101
Other income		203			—			—			203
Texas Margin Taxes		(296	)		—			—			(296	)

Net income	$	54,918		$	22,589		$	—		$	77,507

Total assets	$	690,404		$	82,492		$	—		$	772,896

13. Regulatory Matters

TIGT (formerly KMIGT)

Section 5 Proceeding

On November 18, 2010, KMIGT was notified by the Federal Energy Regulatory Commission (“FERC”) of a proceeding against it pursuant to Section 5 of the Natural Gas Act. The proceeding set for hearing a determination of whether KMIGT’s current rates, which were approved by the FERC in KMIGT’s last transportation rate case settlement, remain just and reasonable. The FERC made no findings in its order as to what would constitute just and reasonable rates or a reasonable return for KMIGT. A proceeding under Section 5 of the Natural Gas Act is prospective in nature and any potential change in rates charged customers by KMIGT can only occur after the FERC has issued a final order. Prior to that, an administrative law judge presides over an evidentiary hearing and makes an initial decision (which the FERC has directed to be issued within 47 weeks).

On March 23, 2011, the Chief Judge suspended the procedural schedule in this proceeding because all parties reached a settlement in principle that will resolve all issues set for hearing. On May 5, 2011, KMIGT filed

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Index to Financial Statements

a formal settlement document, referred to in this Note as the Settlement and which is supported or not opposed by all parties of record, and on September 22, 2011, the FERC approved the Settlement.

The Settlement resolves all issues in the proceeding and provides shippers on KMIGT’s system with prospective reductions in the fuel and gas and lost and unaccounted for rates, referred to as the Fuel Retention Factors, effective June 1, 2011. The Settlement results in a 27% reduction in the Fuel Retention Factors billed to shippers effective June 1, 2011, as compared to the Fuel Retention Factors approved and in effect on March 1, 2011. The Settlement also provides 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. Except for these reductions to the Fuel Retention Factors, other transportation and storage rates will not be altered by the Settlement.

Franklin to Hastings Expansion Project

KMIGT has filed a prior notice request to expand and replace certain mainline pipeline facilities to create up to 10,000 dekatherms per day of firm transportation capacity to serve an ethanol plant located near Aurora, Nebraska. The final cost of the facilities was $20.8 million. The project was constructed and went into service on April 13, 2011.

Pony Express Pipeline Conversion Project

On August 6, 2012, KMIGT filed an application to: (1) abandon for FERC purposes certain mainline natural gas pipeline facilities and the natural gas service therefrom by transfer to an affiliate, Kinder Morgan Pony Express Pipeline LLC, for the purpose of converting the facilities into crude oil pipeline facilities; and (2) construct and operate certain replacement-type facilities necessary to continue service to existing natural gas firm transportation customers following the proposed conversion. The FERC abandonment does not constitute an abandonment for accounting purposes.

This application upon FERC approval and implementation will re-deploy existing pipeline assets to meet the growing market need to transport oil supplies from the Bakken Shale while, at the same time continuing to operate KMIGT’s natural gas transportation facilities to meet all current and expected needs of its natural gas customers. Such application, upon approval by the FERC, will authorize the reconversion of a portion of the Pony Express Pipeline back to the transportation of crude oil as it was prior to 1997.

Other Regulatory Matters

Except for the orders mentioned above, there are currently no proceedings challenging the rates of KMIGT.

14. Legal and Environmental Matters

Legal

Other than the matters discussed below, the Predecessor Entities are defendants in various lawsuits arising from the day-to-day operations of their business. Although no assurance can be given, the Predecessor Entities believe, based on their experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on its business, financial position, results of operations or cash flows.

TMID (formerly KMULLC)

West Frenchie Draw

KMULLC has been a party to the following legal actions pertaining to its West Frenchie Draw treating plant:

Elkhorn Construction, Inc. v. KM Upstream LLC and Newpoint Gas Services, Inc., Civil Action No. 36823 in the District Court of Fremont County, Wyoming (9^th Judicial District)(the “Trial Court Action”);

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Index to Financial Statements

Elkhorn Construction, Inc. v. KM Upstream LLC, Appeal No. S-11-0186 and S-11-0208 in the Wyoming Supreme Court (the “Appeal”);

In Re: Newpoint Gas, L.P., Case No. 10-16104 in the U.S. Bankruptcy Court for the Western District of Oklahoma (Oklahoma City)(“the Newpoint Bankruptcy”).

Elkhorn Construction, Inc., a sub-contractor to Newpoint Gas Services, Inc. (“Newpoint Gas Services”) filed suit on March 23, 2009 in Fremont County, Wyoming to enforce liens against KMULLC in the principal amount of approximately $4.9 million plus “interest, late charges, attorney’s fees and costs from January 16, 2009.” Elkhorn’s claim arises out of construction costs incurred in building the West Frenchie Draw Amine Plant in Fremont County, Wyoming. On November 24, 2009, Newpoint Gas Services was added to the litigation as a defendant. KMULLC and Newpoint Gas Services filed cross-claims against each other. Newpoint Gas Services’ cross-claim against KMULLC seeks damages in excess of $11.0 million (although it includes Elkhorn’s claimed damages of $4.9 million). KMULLC’s cross-claim seeks indemnification from Newpoint Gas Services for any damages awarded to Elkhorn as against KMULLC, as well as the costs of defense.

On July 1, 2011, the District Court entered an Order granting Elkhorn’s motion for summary judgment on foreclosure of its mechanic’s lien in the principal amount of approximately $4.7 million plus interest. On June 6, 2012, the Wyoming Supreme Court affirmed that portion of the District Court’s Order which awarded Elkhorn the principal amount of $4.7 million plus interest. The Wyoming Supreme Court remanded the case to the District Court, where the case is currently pending, for further proceedings consistent with the Wyoming Supreme Court’s opinion. On September 21, 2012, KMULLC paid the adjudicated portion of Elkhorn’s mechanics lien of $4.7 million plus 7% interest from the date of the lien for a total payment of $5.9 million. A hearing concerning the remaining disputed amount with Elkhorn, a motion regarding other remaining issues with Elkhorn and motions for summary judgment between KMULLC and Newpoint Gas Services were held on January 16 and 17, 2013. The court has not issued an order on those issues at this time.

Newpoint Gas L.P. (“Newpoint LP”), a closely held affiliate of Newpoint Gas Services, commenced the above-referenced bankruptcy court proceeding under Chapter 7 of the Bankruptcy Code. KMULLC has filed a claim in the bankruptcy action seeking to consolidate the assets and liabilities of Newpoint Gas Services with Newpoint LP. The judge has not yet issued an order responding to KMULLC’s motion.

ConocoPhillips Off-Spec Product Deliveries

In April and May of 2009, KMULLC delivered to ConocoPhillips NGL product that was alleged to contain fluoride levels that exceeded contract tolerances. In February 2012, KMULLC paid $1.1 million to settle this issue with the affiliated refinery that received the product from ConocoPhillips. KMULLC recognized the full settlement amount of $1.1 million in 2009. In 2012, KMULLC recovered $350,000 from two parties who delivered the contested product to KMULLC and this matter is now concluded.

TIGT (formerly KMIGT)

Cornhusker Energy Lexington Plant Explosion

KMIGT is the defendant in a lawsuit pending in state court in Douglas County, Nebraska (CI 10 9387384). Plaintiffs in the suit are Cornhusker Energy Lexington, LLC and its insurer, National Union Fire Insurance Company of Pittsburgh, Pennsylvania. The suit was initiated in February 2010. Plaintiffs allege that Cornhusker received natural gas that was transported on the KMIGT System that did not meet required pipeline specifications, and that as a result Cornhusker’s ethanol plant suffered an explosion and subsequent fire. Plaintiffs seek monetary relief, attorney’s fees, costs and interest of approximately $3.9 million. A trial date of June 10, 2013 has been set by the Court.

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Index to Financial Statements

Environmental

The Predecessor Entities are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. The Predecessor Entities believe that compliance with these laws will not have a material adverse impact on their business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause the Predecessor Entities to incur significant costs.

TMID (formerly KMULLC)

Casper and Douglas Plants, United States Environmental Protection Agency Notice of Violation

In March 2011, the United States Environmental Protection Agency (“U.S. EPA”) and the Wyoming Department of Environmental Quality (“WDEQ”) conducted an inspection at the Douglas and Casper Gas Plants in Wyoming. In June 2011, KMULLC received two letters from the U.S. EPA alleging violations at both gas plants of the Risk Management Program requirements under the Clean Air Act. KMULLC has executed Combined Complaint and Consent Agreements with the U.S. EPA, including monetary penalties of $158,000 for each facility, to resolve these allegations, which were approved by the U.S. EPA in September 2012.

Casper Plant, U.S. EPA Notice of Violation

In August 2011, the U.S. EPA and the WDEQ conducted an inspection of the Leak Detection and Repair Program at the Casper Gas Plant in Wyoming. In September 2011, KMULLC received a letter from the U.S. EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. KMULLC is working with the U.S. EPA to resolve these allegations.

Casper Mystery Bridge Superfund Site

The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and the Predecessor Entities have requested that the portion of the site attributable to the Predecessor Entities be delisted from the National Priorities List.

15. Subsequent Events

Subsequent events, which are events or transactions that occurred after December 31, 2012 through the issuance of the accompanying combined financial statements, have been evaluated through March 18, 2013.

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Index to Financial Statements

Report of Independent Registered Public Accounting Firm

To the Partners of Tallgrass Energy Partners, LP:

In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of Tallgrass Energy Partners, LP at February 6, 2013 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of the Company’s management; our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

February 11, 2013

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Index to Financial Statements

TALLGRASS ENERGY PARTNERS, LP

BALANCE SHEET

(In Thousands)


	February 6, 2013
ASSETS
Cash	$	1,000

Total Assets	$	1,000

PARTNER’S EQUITY
Partner’s Equity
Limited Partner’s Equity	$	980
General Partner’s Equity		20

Total Partner’s Equity	$	1,000

The accompanying note is an integral part of this balance sheet.

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Index to Financial Statements

TALLGRASS ENERGY PARTNERS, LP

NOTE TO BALANCE SHEET

1. Nature of Operations

Tallgrass Energy Partners, LP (the Partnership) is a Delaware limited partnership formed on February 6, 2013 to acquire certain assets from a wholly-owned subsidiary of Tallgrass Development, LP.

The Partnership intends to offer common units, representing limited partner interests, pursuant to a public offering and to concurrently issue common units and subordinated units, representing additional limited partner interests in the Partnership to Tallgrass Development, LP, and general partner units representing an aggregate 2% general partner interest in the Partnership to Tallgrass MLP GP, LLC, an affiliate of the Partnership.

Tallgrass MLP GP, LLC, as general partner, contributed $20 and Tallgrass Operations, LLC, as the organizational limited partner, contributed $980, all in the form of cash, to the Partnership on February 6, 2013. There have been no other transactions involving the Partnership as of February 6, 2013.

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Index to Financial Statements

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

[to be filed by amendment]

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Index to Financial Statements

APPENDIX B—GLOSSARY OF TERMS

Adjusted EBITDA: A supplemental non-GAAP financial measure defined by us as net income (loss) plus net interest expense, income tax expense, depreciation and amortization expense and non-cash long-term compensation expense less other income.

BBtu: One billion British Thermal Units.

Bcf: One billion cubic feet.

condensate: A NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

current market price: For any class of limited partner interests, the average daily closing prices per limited partner interest of such class for the 20 consecutive trading days immediately prior to such date.

dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

end-user markets: The ultimate users and consumers of transported energy products.

FERC: Federal Energy Regulatory Commission.

firm storage contracts: Under firm storage contracts, customers receive an assured, or “firm,” right to store natural gas (or, if applicable, NGLs) in our facilities over a defined period.

firm transportation and storage services: Those services pursuant to which customers receive firm assurances regarding the availability of capacity and deliverability of natural gas on our assets up to a contracted amount at specified receipt and delivery points.

GAAP: Generally accepted accounting principles.

GHGs: Greenhouse gases.

header system: Networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large diameter high pressure long-haul transportation pipelines.

HP: Horsepower.

interruptible storage services: Those services pursuant to which customers receive only limited assurances regarding the availability of capacity and deliverability in our storage facilities and pay fees based on their actual utilization of our assets.

local distribution company or LDC: LDCs are companies involved in the delivery of natural gas to consumers within a specific geographic area.

LNG: Natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.

Mcf: One thousand cubic feet.

MMbtu: One million British Thermal Units.

MMbtu/d: One million British Thermal Units per day.

MMcf: One million cubic feet.

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Index to Financial Statements

MMcf/d: One million cubic feet per day.

NGLs: Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).

no-notice service: Those services pursuant to which customers receive the right to transport or store natural gas on our assets outside of the daily nomination cycle without incurring penalties.

NYMEX: New York Mercantile Exchange.

off-system customers: Those customers who use the TIGT System to access other pipelines for ultimate delivery to consuming markets outside the geographic areas served by the TIGT System.

on-system customers: Those customers who take delivery of gas for use or delivery to consuming markets within the geographic areas served by the TIGT System.

park and loan services: Those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our facilities on a seasonal basis.

play: A proven geological formation that contains commercial amounts of hydrocarbons.

receipt point: The point where production is received by or into a gathering system or transportation pipeline.

reservoir: A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

residue gas: The natural gas remaining after being processed or treated.

shale gas: Natural gas produced from organic (black) shale formations.

tailgate: Refers to the point at which processed natural gas and NGLs leave a processing facility for end-user markets.

TBtu: One trillion British Thermal Units.

Tcf: One trillion cubic feet.

throughput: The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

wellhead: The equipment at the surface of a well used to control the well’s pressure; also, the point at which the hydrocarbons and water exit the ground.

working gas: The volume of gas in the reservoir that is in addition to the cushion or base gas. It may or may not be completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be used more than once during any season.

working gas storage capacity: The maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes cushion gas and non-cycling working gas.

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Index to Financial Statements

LOGO

Tallgrass Energy Partners, LP

Common Units

Representing Limited Partner Interests

Prospectus

, 2013

Barclays

Citigroup

Through and including , 2013 (the 25th day after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to their unsold allotments or subscriptions.

Index to Financial Statements

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.

Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and the structuring fee) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.


SEC registration fee	$	42,988
FINRA filing fee		45,500
NYSE listing fee		*
Printing and engraving expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*

Total	$	*

*	To be filed by amendment.

Item 14.

Indemnification of Directors and Officers.

Tallgrass Energy Partners, LP

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of the underwriters and their officers and directors by Tallgrass Energy Partners, LP, our general partner and our subsidiaries for certain liabilities under the Securities Act.

Tallgrass MLP GP, LLC

Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

•

any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

•

any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;

Index to Financial Statements

•

any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and

•

any person designated by our general partner.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Item 15.

Recent Sales of Unregistered Securities.

On February 6, 2013, in connection with our formation, we issued to (i) our general partner a 2.0% general partner interest in us in exchange for $20 and (ii) Tallgrass Development a % limited partner interest in us in exchange for $980. These transactions were exempt from registration under Section 4(2) of the Securities Act.

Item 16.

Exhibits and Financial Statement Schedules.

The following documents are filed as exhibits to this registration statement:

Index to Financial Statements

INDEX TO EXHIBIT


Number			Description

	1.1		—Form of Underwriting Agreement

	3.1		—Certificate of Limited Partnership of the partnership

	3.2		—Certificate of Amendment to Certificate of Limited Partnership of the partnership

	3.3	*	—Form of Amended and Restated Agreement of Limited Partnership of Tallgrass Energy Partners, LP (included as Appendix A to the prospectus)

	3.4		—Certificate of Formation of Tallgrass MLP GP, LLC

	3.5	*	—Form of Amended and Restated Limited Liability Company Agreement of Tallgrass MLP GP, LLC

	5.1	*	—Opinion of Baker Botts L.L.P. as to the legality of the securities being registered

	8.1	*	—Opinion of Baker Botts L.L.P. relating to tax matters

	10.1	*	—Form of Contribution, Conveyance and Assumption Agreement

	10.2	*	—Form of Omnibus Agreement

	10.3	*	—Form of Revolving Credit Agreement

	10.4	*	—Form of Tallgrass Management, LLC 2013 Long-Term Incentive Plan

	10.5	*	—Form of Award Agreement

	10.6	*	—Form of Director Indemnification Agreement

	10.7	*	—Employment Agreement between Tallgrass Management, LLC and David G. Dehaemers, Jr., dated November 13, 2012

	10.8	*	—Form of Purchase and Sale Agreement between Kinder Morgan Interstate Gas Transmission LLC and Kinder Morgan Pony Express Pipeline LLC

	21.1		—List of Subsidiaries of Tallgrass Energy Partners, LP

	23.1		—Consent of PricewaterhouseCoopers LLP

	23.2	*	—Consent of Baker Botts L.L.P. (contained in Exhibit 5.1)

	23.3	*	—Consent of Baker Botts L.L.P. (contained in Exhibit 8.1)

	23.4		—Consent of Wood Mackenzie

	24.1		—Powers of Attorney (contained on the signature pages to this Registration Statement)

*	To be filed by amendment

Index to Financial Statements

Item 17.

Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i)

Any preliminary prospectus or prospectus of the undersigned registrant relating to this offering required to be filed pursuant to Rule 424;

(ii)

Any free writing prospectus relating to this offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii)

The portion of any other free writing prospectus relating to this offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(iv)

Any other communication that is an offer in this offering made by the undersigned registrant to the purchaser.

The undersigned registrant hereby undertakes that:

(1)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

Index to Financial Statements

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with our general partner, or any of their affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner, or any of their affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

Index to Financial Statements

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Overland Park, State of Kansas, on March 28, 2013.


Tallgrass Energy Partners, LP

By: Tallgrass MLP GP, LLC its general partner

By:		/s/ David G. Dehaemers, Jr.
Name: David G. Dehaemers, Jr. Title: President and Chief Executive Officer

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SIGNATURES

Each person whose signature appears below appoints David G. Dehaemers, Jr., George E. Rider and Gary J. Brauchle, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and the dates indicated.


Name	Title	Date

/s/ David G. Dehaemers, Jr. David G. Dehaemers, Jr.	Director, President and Chief Executive Officer (Principal Executive Officer)		March 28, 2013

/s/ Gary J. Brauchle Gary J. Brauchle	Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)		March 28, 2013

/s/ Frank J. Loverro Frank J. Loverro	Director		March 28, 2013

/s/ Stanley de J. Osborne Stanley de J. Osborne	Director		March 28, 2013

/s/ Jeffrey A. Ball Jeffrey A. Ball	Director		March 28, 2013

/s/ John T. Raymond John T. Raymond	Director		March 28, 2013

/s/ William R. Moler William R. Moler	Director		March 28, 2013

Tallgrass Energy Partners, LP - FORM S-1 - March 28, 2013

Attached files