Tallgrass Energy, LP - FORM 10-Q

Tallgrass Energy, LP - FORM 10-Q - June 18, 2015

Attached files

Attached files

Tallgrass Energy, LP Reports

file	filename
EXCEL - IDEA: XBRL DOCUMENT - Tallgrass Energy, LP	Financial_Report.xls
EX-3.7 - EXHIBIT 3.7 - Tallgrass Energy, LP	tegp201533110qexhibit37.htm
EX-32.2 - EXHIBIT 32.2 - Tallgrass Energy, LP	tegp201533110qexhibit322.htm
EX-32.1 - EXHIBIT 32.1 - Tallgrass Energy, LP	tegp201533110qexhibit321.htm
EX-31.2 - EXHIBIT 31.2 - Tallgrass Energy, LP	tegp201533110qexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Tallgrass Energy, LP	tegp201533110qexhibit311.htm
EX-4.2 - EXHIBIT 4.2 - Tallgrass Energy, LP	tegp201533110qexhibit42.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2015



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-37365

Tallgrass Energy GP, LP

(Exact name of registrant as specified in its charter)



Delaware				47-3159268
(State or other Jurisdiction of Incorporation or Organization)				(IRS Employer Identification Number)

4200 W. 115th Street, Suite 350
Leawood, Kansas				66211
(Address of Principal Executive Offices)				(Zip Code)

(913) 928-6060

(Registrant's Telephone Number, Including Area Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No ý

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

On June 18, 2015, the Registrant had 47,725,000 Class A shares and 109,504,440 Class B shares outstanding.

TALLGRASS ENERGY GP, LP

TABLE OF CONTENTS



PART 1—FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
CONDENSED COMBINED BALANCE SHEETS	1
CONDENSED COMBINED STATEMENTS OF INCOME	2
CONDENSED COMBINED STATEMENTS OF CASH FLOWS	3
CONDENSED COMBINED STATEMENTS OF CHANGES IN EQUITY	4
NOTES TO CONDENSED COMBINED FINANCIALS STATEMENTS	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3. Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. Controls and Procedures	39
PART II - OTHER INFORMATION	39
Item 1. Legal Proceedings	39
Item 1A. Risk Factors	39
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	73
Item 3. Defaults Upon Senior Securities	74
Item 4. Mine Safety Disclosures	74
Item 5. Other Information	74
Item 6. Exhibits	75
SIGNATURES	78

Glossary of Common Industry and Measurement Terms

Bakken oil production area: Montana and North Dakota in the United States and Saskatchewan and Manitoba in Canada.

Barrel (or bbl): Forty two U.S. gallons.

Base Gas (or Cushion Gas): The volume of gas that is intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates.

BBtu: One billion British Thermal Units.

Bcf: One billion cubic feet.

British Thermal Units or Btus: the amount of heat energy needed to raise the temperature of one pound of water by one degree Fahrenheit.

Condensate: A NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

Contract barrels: Barrels of crude oil that our customers have contractually agreed to ship in exchange for assurance of capacity and deliverability to delivery points.

Delivery point: the point at which product in a pipeline is delivered to the end user.

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.

Dth: A dekatherm, which is a unit of energy equal to 10 therms or one million British thermal units.

End-user markets: The ultimate users and consumers of transported energy products.

Fee Based Processing Contracts: Natural gas processing contracts that are primarily based upon a fixed fee and/or a volumetric-based fee rate, which is typically tied to reserved capacity or inlet volumes.

FERC: Federal Energy Regulatory Commission.

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. Firm transportation contracts obligate our customers to pay a fixed monthly reservation 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. 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.

Fractionation: The process by which NGLs are further separated into individual, more valuable components including ethane, propane, butane, isobutane and natural gasoline.

GAAP: Generally accepted accounting principles in the United States of America.

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 transportation and storage services: Those services pursuant to which customers receive only limited assurances regarding the availability of capacity and deliverability in transportation or storage facilities, as applicable, and pay fees based on their actual utilization of such assets. Under interruptible service contracts, our customers pay fees based on their actual utilization of assets for transportation and storage services. These customers are not assured capacity or service.

Keep Whole Processing Contracts: Natural gas processing contracts in which we are required to replace the Btu content of the NGLs extracted from inlet wet gas processed with purchased dry natural gas.

Line fill: The volume of oil, in barrels, in the pipeline from the origin to the destination.

Liquefied natural gas or 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.

Local distribution company or LDC: LDCs are involved in the delivery of natural gas to consumers within a specific geographic area.

MMBtu: One million British Thermal Units.

Mcf: One thousand cubic feet.

MMcf: One million cubic feet.

Natural gas liquids or 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).

Natural Gas Processing: The separation of natural gas into pipeline-quality natural gas and a mixed NGL stream.

Non-contract barrels: Barrels of crude oil that our customers ship based solely on availability of capacity and deliverability with no assurance of future capacity.

No-notice service: Those services pursuant to which customers receive the right to transport or store natural gas on assets outside of the daily nomination cycle without incurring penalties.

NYMEX: New York Mercantile Exchange.

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.

Percent of Proceeds Processing Contracts: Natural gas processing contracts 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. Some percent of proceeds contracts may also require our customers to pay a monthly reservation fee for processing capacity.

PHMSA: The United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration.

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: 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 or crude oil transported or passing through a pipeline, plant, terminal or other facility during a particular period.

Uncommitted Shippers (or Walk-Up Shippers): Customers that have not signed long-term shipper contracts and have rights under the FERC tariff as to rates and capacity allocation that are different than long-term committed shippers.

Wellhead: The equipment at the surface of a well that is 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 storage 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 base gas and non-cycling working gas.

X/d: The applicable measurement metric per day. For example, MMcf/d means one million cubic feet per day.

PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

TALLGRASS ENERGY GP PREDECESSOR

CONDENSED COMBINED BALANCE SHEETS

(UNAUDITED)



	March 31, 2015		December 31, 2014
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	876	$	867
Accounts receivable, net	46,268		39,768
Receivable from related party	—		73,393
Gas imbalances	911		2,442
Inventories	12,679		13,045
Derivative assets at fair value	90		—
Prepayments and other current assets	2,728		2,766
Total Current Assets	63,552		132,281
Property, plant and equipment, net	1,921,676		1,853,081
Goodwill	343,288		343,288
Intangible asset, net	102,519		104,538
Deferred financing costs	5,119		5,528
Deferred charges and other assets	17,397		18,481
Total Assets	$	2,453,551	$	2,457,197
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities:
Accounts payable	$	64,047	$	62,329
Accounts payable to related parties	3,000		3,915
Gas imbalances	3,490		3,611
Accrued taxes	15,308		3,989
Accrued liabilities	6,447		9,384
Other current liabilities	12,094		13,340
Total Current Liabilities	104,386		96,568
Long-term debt	698,000		559,000
Other long-term liabilities and deferred credits	6,213		6,478
Total Long-term Liabilities	704,213		565,478
Commitments and Contingencies
Equity:
TEGP Predecessor	112,982		146,866
Total Members’ Equity	112,982		146,866
Noncontrolling interests	1,531,970		1,648,285
Total Equity	1,644,952		$	1,795,151
Total Liabilities and Equity	$	2,453,551	$	2,457,197

The accompanying notes are an integral part of these condensed combined financial statements.

TALLGRASS ENERGY GP PREDECESSOR

CONDENSED COMBINED STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended March 31,
	2015			2014
	(in thousands, except per unit amounts)
Revenues:
Natural gas liquids sales	$	21,025		$	48,907
Natural gas sales	844			4,808
Natural gas transportation services	32,148			34,104
Crude oil transportation services	50,381			—
Processing and other revenues	10,277			6,960
Total Revenues	114,675			94,779
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	19,593			48,206
Cost of transportation services (exclusive of depreciation and amortization shown below)	10,715			5,117
Operations and maintenance	9,575			8,013
Depreciation and amortization	20,605			8,309
General and administrative	12,689			6,649
Taxes, other than income taxes	11,297			1,956
Loss on sale of assets	4,483			—
Total Operating Costs and Expenses	88,957			78,250
Operating Income	25,718			16,529
Other (Expense) Income:
Interest expense, net	(3,440		)	(1,296		)
Equity in earnings of unconsolidated investment	—			444
Other income, net	712			940
Total Other (Expense) Income	(2,728		)	88
Net Income	22,990			16,617
less: Net income attributable to noncontrolling interests	(17,868		)	(13,979		)
Net income attributable to TEGP Predecessor	$	5,122		$	2,638

The accompanying notes are an integral part of these condensed combined financial statements.

TALLGRASS ENERGY GP PREDECESSOR

CONDENSED COMBINED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Three Months Ended March 31,
	2015			2014
	(in thousands)
Cash Flows from Operating Activities:
Net income	$	22,990		$	16,617
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	21,557			8,638
Noncash compensation expense	1,527			941
Loss on sale of assets	4,483			—
Changes in components of working capital:
Accounts receivable and other	(5,678		)	1,356
Gas imbalances	143			321
Inventories	(2,754		)	(887		)
Accounts payable and accrued liabilities	6,546			(6,623		)
Other operating, net	(175		)	7,240
Net Cash Provided by Operating Activities	48,639			27,603
Cash Flows from Investing Activities:
Capital expenditures	(13,300		)	(209,111		)
Acquisition of additional 33.3% membership interest in Pony Express	(700,000		)	—
Other investing, net	(311		)	(1,910		)
Net Cash Used in Investing Activities	(713,611		)	(211,021		)
Cash Flows from Financing Activities:
Proceeds from TEP public offerings, net of offering costs	551,949			—
Borrowings under TEP revolving credit facility, net	139,000			—
Distributions to TEP unitholders	(14,761		)	(6,457		)
(Distributions to) Contributions from TEGP Predecessor, net	(13,533		)	188,674
Other financing, net	2,326			1,201
Net Cash Provided by Financing Activities	664,981			183,418
Net Change in Cash and Cash Equivalents	9			—
Cash and Cash Equivalents, beginning of period	867			—
Cash and Cash Equivalents, end of period	$	876		$	—

Schedule of Noncash Investing and Financing Activities:
Property, plant and equipment acquired via the cash management agreement with TD	$	72,407		$	—
Increase in accrual for payment of property, plant and equipment	$	1,179		$	53,542

The accompanying notes are an integral part of these condensed combined financial statements.

TALLGRASS ENERGY GP PREDECESSOR

CONDENSED COMBINED STATEMENTS OF CHANGES IN EQUITY

(UNAUDITED)



	TEGP Predecessor			Noncontrolling Interests			Total Equity
	TEGP Predecessor			Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2015	$	146,866		$	1,648,285		$	1,795,151
Net income	5,122			17,868			22,990
Issuance of TEP units to public, net of offering costs	63,548			488,401			551,949
Distributions to TEP unitholders	—			(14,761		)	(14,761		)
Distributions to TEGP Predecessor	(4,108		)	(9,425		)	(13,533		)
Noncash compensation expense	—			2,933			2,933
Contributions from noncontrolling interest	—			2,379			2,379
Distributions to noncontrolling interest	—			(2,156		)	(2,156		)
Acquisition of additional 33.3% membership interest in Pony Express	(98,446		)	(601,554		)	(700,000		)
Balance at March 31, 2015	$	112,982		$	1,531,970		$	1,644,952

	TEGP Predecessor			Noncontrolling Interests			Total Equity
	TEGP Predecessor			Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2014	$	150,871		$	1,158,230		$	1,309,101
Net income	2,638			13,979			16,617
Noncash compensation expense	—			2,176			2,176
Distributions to TEP unitholders	—			(6,457		)	(6,457		)
Contributions from TEGP Predecessor	7,652			181,022			188,674
Balance at March 31, 2014	$	161,161		$	1,348,950		$	1,510,111

The accompanying notes are an integral part of these condensed combined financial statements.

TALLGRASS ENERGY GP PREDECESSOR

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(UNAUDITED)

1. Description of Business

Tallgrass Energy GP, LP ("TEGP" or the "Partnership") is a Delaware limited partnership formed in February 2015 that has elected to be treated as a corporation for U.S. federal income tax purposes. TEGP was formed as part of the reorganization of entities controlled by Tallgrass Equity, LLC ("Tallgrass Equity") to effect the initial public offering of Class A shares of TEGP (the "Offering"), which was completed on May 12, 2015 as discussed further in Note 14 – Subsequent Events.

In connection with the closing of the Offering on May 12, 2015, the following transactions (the “Reorganization Transactions”) occurred:


•	Tallgrass Equity distributed its interests in Tallgrass Energy Holdings, LLC ("Holdings") and Holdings distributed its existing limited partner interest in TEGP, respectively, to the owners of Tallgrass Equity that also collectively own 100% of the voting power of Holdings, which are referred to as the “Exchange Right Holders;”


•	TEGP issued 47,725,000 Class A shares to the public for net proceeds of approximately $1.3 billion, including 6,225,000 Class A shares issued in connection with the underwriters' exercise of the overallotment option;


•	The existing limited partner interests in TEGP held by the Exchange Right Holders were converted into 115,729,440 Class B shares, 6,225,000 of which were automatically canceled in connection with the underwriters’ exercise of the overallotment option;


•	Tallgrass Equity issued 41,500,000 Tallgrass Equity units to TEGP in exchange for approximately $1.1 billion in net proceeds from the issuance of TEGP’s Class A shares to the public and amended the limited liability company agreement of Tallgrass Equity to, among other things, provide that TEGP is the managing member of Tallgrass Equity;


•	TEGP used the net proceeds from the purchase of the 6,225,000 overallotment option shares to purchase Tallgrass Equity units from the Exchange Right Holders; and

•

Tallgrass Equity entered into a $150 million revolving credit facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings together with the net proceeds from the Offering that Tallgrass Equity received from TEGP, to purchase 20,000,000 TEP common units from Tallgrass Development, LP ("TD") at $47.68 per TEP common unit (the “Acquired TEP Units”) and pay offering expenses and other transaction costs. Tallgrass Equity distributed the remaining proceeds to the Exchange Right Holders.

TEGP's sole cash-generating asset is an approximate 30.35% controlling interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of direct and indirect partnership interests in Tallgrass Energy Partners, LP ("TEP") described below that were historically owned by entities controlled by Tallgrass Equity, including TD:


•	100% of the outstanding membership interests in Tallgrass MLP GP, LLC ("TEP GP"), which owns the general partner interest in TEP as well as all of the TEP incentive distribution rights ("IDRs"). The general partner interest in TEP is represented by 834,391 general partner units, representing a 1.37% general partner interest in TEP at March 31, 2015.


•	20,000,000 common units of TEP, representing an approximately 32.75% limited partner interest in TEP at March 31, 2015.

The term "TEGP Predecessor" refers to TEGP, as recast to show the effects of the Reorganization Transactions, for the periods prior to completion of the Offering on May 12, 2015. "We," "us," "our" and similar terms refer to TEGP together with its consolidated subsidiaries or to TEGP Predecessor together with its consolidated subsidiaries, as the context requires, including, in both cases, Tallgrass Equity and TEP (and their respective subsidiaries).

2. Summary of Significant Accounting Policies

Basis of Presentation

These unaudited condensed combined financial statements and related notes for the three months ended March 31, 2015 and 2014 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”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The unaudited condensed combined financial statements for the three months ended March 31, 2015 and 2014 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair presentation of the results for the interim periods. 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 or ASC.

Our financial results for the three months ended March 31, 2015 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2015. The accompanying unaudited condensed combined interim financial statements should be read in conjunction with TEGP’s final prospectus dated May 6, 2015 (the “Prospectus”) included in its Registration Statement on Form S-1, as amended (SEC File No. 333-202258) and filed with the United States Securities and Exchange Commission (the “SEC”) pursuant to Rule 424 on May 7, 2015.

These condensed combined financial statements were prepared in contemplation of TEGP's initial public offering of Class A shares completed on May 12, 2015 and the acquisition by TEGP of an approximately 30.35% interest in Tallgrass Equity, which will be accounted for as a transaction between entities under common control in accordance with ASC 805. Significant intra-entity items have been eliminated in the presentation.

Net income or loss from consolidated subsidiaries that are not wholly-owned by TEGP Predecessor are attributed to TEGP Predecessor and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEGP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express") effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million (prorated to approximately $5.4 million for the quarter ended September 30, 2014) through the quarter ending September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ending December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 will be attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests.

A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity’s economic performance. Our assets and liabilities consist solely of our consolidated VIEs, and as such we have not presented separately in its condensed combined balance sheets the assets of our consolidated VIEs that can only be used to settle specific obligations of the consolidated VIEs, and the liabilities of our VIEs for which creditors do not have recourse to our general credit. Tallgrass Equity and Pony Express are considered to be VIEs under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we have the power to direct matters that most significantly impact the activities of Tallgrass Equity and Pony Express and have the right to receive benefits of Tallgrass Equity and Pony Express that could potentially be significant to the respective entities. We have consolidated Tallgrass Equity as we are the primary beneficiary. We also consolidate Pony Express through our indirect investment in TEP, as TEP is the primary beneficiary of Pony Express. For additional information see Note 3 – Variable Interest Entities.

Use of Estimates

Certain amounts included in or affecting these condensed 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, liabilities, 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 our 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 and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Net equity contributions and distributions included in the condensed combined statements of cash flows represent transfers of cash as a result of TD’s centralized cash management systems prior to April 1, 2014 for Trailblazer Pipeline Company LLC ("Trailblazer") and September 1, 2014 for Pony Express, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions. Pony Express participates in a cash management agreement with TD, which holds a 33.3% common membership interest in Pony Express, under which cash balances are swept daily and recorded as loans from Pony Express to TD.

All payable and receivable balances between TEGP Predecessor and TD are cash settled with the exception of certain balances payable from Pony Express to TD, which have been settled against the receivable from TD via the Pony Express cash management agreement discussed in the prior paragraph.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are carried at their estimated collectible amounts. We 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. Our allowance for doubtful accounts totaled $0.5 million at March 31, 2015 and December 31, 2014.

Inventories

Inventories primarily consist of gas in underground storage, materials and supplies, natural gas liquids and crude oil. Gas in underground storage, sometimes referred to as working gas, and natural gas liquids are recorded at the lower of historical cost or market using the average cost method. As discussed further under "Revenue Recognition" below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil, which we can then sell. As pipeline allowance oil is accumulated, it is recorded as inventory at the lower of historical cost or market using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. For additional information, see "Gas in Underground Storage" below.

Accounting for Regulatory Activities

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. We had recorded regulatory assets of approximately $1.3 million and $1.4 million included in "Deferred charges and other assets" in the condensed combined balance sheets at March 31, 2015 and December 31, 2014, respectively. Regulatory assets at March 31, 2015 and December 31, 2014 were primarily attributable to costs associated with Trailblazer’s 2013 Rate Case Filing as more fully described in Note 11 – Regulatory Matters.

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 and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs.

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 value 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 or 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.

Intangible Assets

We account for intangible assets in accordance with ASC 805, which established that an intangible asset is identifiable if it meets either the separability criterion or the contractual-legal criterion. Further, in accordance with ASC 805, contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of the Tallgrass Interstate Gas Transmission, LLC ("TIGT") natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years, the period of expected future benefit. Intangible assets arose at BNN Redtail, LLC ("Redtail") as a result of a significant customer contract with favorable market terms which was acquired as part of the BNN Water Solutions, LLC ("Water Solutions") transaction discussed in Note 4 – Acquisitions. This intangible asset is amortized on a straight-line basis over a period of 1.6 years, the remaining term of the contract at the time of acquisition.

Impairment of Long-Lived Assets

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. We assess our 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, we first assesses 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, which refers to the volumes necessary to maintain pressure and deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment.

We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our storage services but do not reflect the value of third party gas in the accompanying condensed combined financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost or market.

Depreciation and Amortization - Regulated Assets

For our regulated assets at TIGT and Trailblazer, we have elected to compute 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 annualized rate of depreciation ranges from 0.70% to 12.00% for the various classes of depreciable, regulated assets.

Depreciation and Amortization - Non-regulated Assets

For non-regulated assets, we have elected to use the straight-line method of depreciation. The useful lives for the various classes of non-regulated depreciable assets are as follows:



	Range of Useful Lives
	(in years)
Crude oil pipelines	35
Processing & Treating	30
Natural gas pipelines ⁽¹⁾	10
General & Other	3-13 1/3


⁽¹⁾	Includes the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 11 – Regulatory Matters.

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. Imbalances are valued at the Average Monthly Index Price ("AMIP") of the Colorado Interstate Gas Index ("CIG") and Panhandle Eastern Pipeline Gas Index ("PEPL").

Deferred Financing Costs

Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method.

Goodwill

We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include the magnitude of the excess of the fair value over the carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31st. We evaluate goodwill for impairment at the 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. If we, after performing the qualitative assessment, determine 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 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.

Investment in Unconsolidated Affiliates

We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence.

We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary.

Our investment in Grasslands Water Services I, LLC ("GWSI"), which owns a water transportation pipeline, was initially recorded under the equity method of accounting as we had the ability to exercise significant influence, but not control, over this investment. There was $0.4 million equity in earnings recognized for the three months ended March 31, 2014. There was no equity in earnings recognized for the three months ended March 31, 2015. As discussed in Note 4 - Acquisitions, during the year ended December 31, 2014, TEGP Predecessor acquired a controlling interest in GWSI, which was subsequently renamed BNN Redtail, LLC ("Redtail"), and consolidated its investment in Redtail as of May 13, 2014 accordingly.

Revenue Recognition

We 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. We provide various types of natural gas storage and transportation services and crude oil transportation services to our customers in which the commodity remains the property of these customers at all times.

Natural gas liquids sales occur in the Processing & Logistics segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We keep the difference between the proceeds received and the amount remitted back to the producer. We generally report gross revenues in the condensed combined statements of income, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent processing fees for processing, treating and fractionation of natural gas earned under fee-based arrangements and revenue from water services earned in the Processing & Logistics segment.

Natural gas sales occur in both the Natural Gas Transportation & Logistics segment and in the Processing & Logistics segment. In the Natural Gas Transportation & Logistics segment, transportation services revenue is recognized 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. 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, we occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing & Logistics 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.

Natural gas transportation and storage services occur in the Natural Gas Transportation & Logistics 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 customers’ agreed upon delivery point, or when the volumes are injected into/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 "firm" and "interruptible" transportation services, we also 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.

Crude oil transportation services occur in the Crude Oil Transportation & Logistics segment. We provide various types of crude oil transportation services to our customers and, other than pipeline allowance oil, do not take title to the crude oil and do not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels per month. For barrels physically received by us and delivered to the customers’ agreed upon destination point, revenue is recognized in the period the service is provided. Shipper deficiencies, or barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers’ agreed upon destination point are charged at the committed tariff rate per barrel and recorded as a deferred liability until the barrels are physically transported and delivered. In the case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and delivered. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered from the customer. When pipeline loss allowance oil is eventually sold we record revenue at the contractual sales price and cost of sales and transportation services at average cost as discussed in "Inventories" above. There were no sales of pipeline allowance oil during the three months ended March 31, 2015.

Commitments and Contingencies

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss.

Environmental Costs

We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We 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. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information.

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. We 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 we 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 8 – Risk Management. For information regarding the fair value of financial instruments not measured at fair value in the condensed combined balance sheets, see Note 9 – Long-term Debt.

Risk Management Activities

We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas. We record derivative contracts at their estimated fair values as of each reporting date. For more information on our risk management activities, see Note 8 – Risk Management.

Equity-Based Compensation

Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. A portion of the expense recognized relating to equity-based compensation grants is charged to TD.

Income Taxes

TEGP Predecessor is comprised solely 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 TEGP Predecessor and the tax effects of our activities accrue to their parents. TEGP has elected to be treated as a corporation for U.S. federal income tax purposes, and will record a provision for federal and state income taxes beginning May 12, 2015 upon effectiveness of the Reorganization Transactions.

Accounting Pronouncements Issued But Not Yet Effective

Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers (Topic 606)"

In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.

The amendments in ASU 2014-09 are effective for public entities for annual reporting periods beginning after December 15, 2016, and for interim periods within that reporting period. Early application is not permitted. We are currently evaluating the impact of ASU 2014-09.

ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period"

In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved.

ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The adoption of ASU 2014-12 is not expected to have a material impact on our financial position and results of operations.

ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis"

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis. ASU 2015-02 will change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 will modify the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminate the presumption that a general partner should consolidate a limited partnership, and change certain aspects of the consolidation analysis for reporting entities that are involved with VIEs, particularly for those with fee arrangements and related party relationships.

The amendments in ASU 2015-02 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early application is permitted, including adoption in an interim period. We are currently evaluating the impact of ASU 2015-02.

3. Variable Interest Entities

TEGP, as the managing member of Tallgrass Equity, has voting rights disproportionate to its ownership interest. As a result, we have determined that Tallgrass Equity is a VIE of which we are the primary beneficiary and we consolidate Tallgrass Equity accordingly. We have not provided any additional financial support to Tallgrass Equity other than our initial capital contribution and have no contractual commitments or obligations to provide additional financial support.

We also consolidate Pony Express through our indirect ownership of TEP. TEP does not have the obligation to absorb losses from Pony Express during the preference period as a result of the minimum quarterly preference payments as discussed in Note 4 – Acquisitions. In addition, for the period from the acquisition of the initial 33.3% membership interest effective September 1, 2014 to the acquisition of an additional 33.3% membership interest effective March 1, 2015, TEP, as the managing member of Pony Express, had voting rights disproportionate to its ownership interest. As a result, we determined that Pony Express is a VIE of which TEP is the primary beneficiary and consolidated Pony Express accordingly. TEP has not provided any additional financial support to Pony Express other than its initial capital contribution of $570 million and has no contractual commitments or obligations to provide additional financial support. In the event that the costs of construction of the crude oil pipeline system owned and operated by Pony Express, which we refer to as the Pony Express System, including the lateral on the Pony Express System in Northeast Colorado, exceed the $270 million retained by Pony Express as discussed in Note 4 – Acquisitions, TD is obligated to fund the remaining costs.

All of the assets and liabilities reported on our condensed combined balance sheets as of March 31, 2015 and December 31, 2014 represent assets and liabilities of our consolidated VIEs.

4. Acquisitions

TEP Acquisition of Trailblazer

On April 1, 2014, TEP closed the acquisition of Trailblazer from a wholly owned subsidiary of TD for total consideration valued at approximately $164 million, consisting of $150 million in cash and the issuance of 385,140 TEP common units (valued at approximately $14 million based on the March 31, 2014 closing price of TEP’s common units). On that same date, the general partner contributed additional capital in the amount of approximately $263,000 in exchange for the issuance of 7,860 TEP general partner units in order to maintain its 2% general partner interest. The acquisition of Trailblazer represents a change in reporting entity and a transaction between entities under common control. The excess purchase price over the net book value of Trailblazer's assets and liabilities was accounted for as a deemed distribution to TEP's general partner.

TEP Acquisitions of 66.7% of Pony Express

Effective September 1, 2014, TEP acquired a controlling 33.3% membership interest in Pony Express for total consideration of approximately $600 million. At closing, Pony Express, TD, and TEP entered into a Second Amended and Restated Limited Liability Company Agreement of Pony Express effective September 1, 2014, which sets forth the relative rights of TD and TEP as the owners of Pony Express. Of the total consideration of $600 million, TEP directly paid TD $30 million, consisting of $27 million in cash and 70,340 TEP common units with an aggregate fair value of approximately $3 million, in exchange for the transfer by TD to TEP of a 1.9585% membership interest in Pony Express (computed before giving effect to the issuance of the new membership interest by Pony Express to TEP). TEP also contributed cash of $570 million to Pony Express in exchange for a newly issued membership interest which, when combined with the membership interest transferred from TD and the parties' entry at closing into the Second Amended and Restated Limited Liability Company Agreement of Pony Express, constituted TEP's 33.3% membership interest in Pony Express, which represented 100% of the preferred membership units issued by Pony Express. Of the $570 million cash consideration received by Pony Express, $300 million was immediately distributed to TD at closing and $270 million was retained by Pony Express to fund the estimated remaining costs of construction for the Pony Express System and the lateral in Northeast Colorado. The $270 million cash balance was subsequently swept to TD under a cash management agreement between Pony Express and TD and was recorded as a related party loan which bears interest at TD's incremental borrowing rate. There was no remaining balance outstanding on the related party loan at March 31, 2015.

The terms of TEP's first acquisition of a 33.3% membership interest in Pony Express provided TEP a minimum quarterly preference payment of $16.65 million through the quarter ending September 30, 2015 (prorated to approximately $5.4 million for the quarter ended September 30, 2014) with distributions thereafter shared in accordance with the terms of the Second Amended Pony Express LLC Agreement. At the effective date of that transaction, TEP determined that Pony Express was a VIE of which TEP was the primary beneficiary, and consolidated Pony Express accordingly. For additional discussion and disclosure, see Note 3 – Variable Interest Entities. The acquisition of the initial 33.3% membership interest in Pony Express represented a transaction between entities under common control and a change in reporting entity.

Effective March 1, 2015, TEP acquired an additional 33.3% membership interest in Pony Express for cash consideration of $700 million. At closing, Pony Express, TD, and TEP entered into the Pony Express LLC Agreement effective March 1, 2015, which sets forth the relative rights of TD and TEP as the owners of Pony Express. The terms of the transaction increased the minimum quarterly preference payment provided to TEP to $36.65 million through the quarter ending December 31, 2015 (prorated to approximately $23.5 million for the quarter ended March 31, 2015) with distributions thereafter shared in accordance with the terms of the Pony Express LLC Agreement.

Upon the effective date of the transaction, TEP reevaluated its VIE assessment and determined that Pony Express continues to be considered a VIE of which TEP is the primary beneficiary. The acquisition of the additional 33.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction have not been recast to reflect the additional 33.3% membership interest.

Formation of BNN Water Solutions, LLC

On November 26, 2013, TEP, through its wholly-owned subsidiary Tallgrass Energy Investments, LLC ("TEI"), entered into a joint venture agreement with BNN Energy LLC ("BNN") to form GWSI, which subsequently built and began operating an intrastate water pipeline in Colorado. TEP accounted for its 50% equity interest in GWSI as an equity method investment. On May 13, 2014, TEI entered into a contribution agreement with BNN and several other parties to form a new entity known as Water Solutions. Under the terms of the contribution agreement, TEI agreed to contribute its existing 50% interest in GWSI, along with $7.6 million cash, in exchange for an 80% membership interest in Water Solutions. As part of the transaction, GWSI was renamed BNN Redtail, LLC ("Redtail"), became a subsidiary of Water Solutions, and issued preferred equity interests to TEI. Among the assets contributed by BNN and the other parties to the transaction were the other 50% interest in Redtail and a 100% equity interest in Alpha Reclaim Technology, LLC ("Alpha"), a company which sources treated wastewater from municipalities in Texas. Alpha is wholly-owned by Redtail.

Upon closing of the transaction, TEP obtained a controlling financial interest in Water Solutions and accordingly has accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously held 50% equity interest in Redtail to its fair value of $11.9 million, recognized a gain of $9.4 million, and consolidated Water Solutions. The 20% equity interest in Water Solutions held by noncontrolling interests was recorded at its acquisition date fair value of $1.4 million. The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis. These fair value measurements are based on significant inputs that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.

At March 31, 2015, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. TEP 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 adjusted if necessary 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.

Pro forma revenue and net income attributable to TEGP Predecessor for the three months ended March 31, 2014 was $96.7 million and $2.9 million, respectively. This unaudited pro forma financial information is presented as if the acquisition of Water Solutions had been completed on January 1, 2014. The pro forma financial information is not necessarily indicative of what our actual results of operations or financial position would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project our results of operations or financial position 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. The pro forma revenue and net income includes adjustments for the three months ended March 31, 2014 to give effect to the following:


(a)	Reduction in net income attributable to TEGP Predecessor to remove equity in earnings of GWSI recorded for the period from January 1, 2014 to March 31, 2014.


(b)	Increase in revenue and net income attributable to TEGP Predecessor to reflect TEP's consolidated 80% interest in the operations of GWSI for the period from January 1, 2014 to March 31, 2014.

5. Related Party Transactions

We have no employees. TD, through its wholly-owned subsidiary Tallgrass Operations, LLC ("Tallgrass Operations"), provided and charged us for direct and indirect costs of services provided to us or incurred on our behalf including employee labor costs, information technology services, employee health and retirement benefits, and all other expenses necessary or appropriate to the conduct of our business. We recorded these costs on the accrual basis in the period in which TD incurred them. On May 17, 2013, in connection with the closing of TEP’s initial public offering, TEP and its general partner entered into an Omnibus Agreement with TD and certain of its affiliates, including Tallgrass Operations (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse TD and its affiliates for all expenses they incur and payments they make on TEP’s behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by TD, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the closing of the Offering, we entered into an Omnibus Agreement (the “TEGP Omnibus Agreement”) with TEGP Management, LLC, Tallgrass Equity and Holdings (which acts as the general partner of TD).

For the first quarter of 2015, TEP’s general and administrative costs under the TEP Omnibus Agreement were $5.4 million, excluding costs attributable to Pony Express. Pony Express had general and administrative costs for the first quarter of 2015 of $5.2 million. TEP also pays a quarterly reimbursement to TD for costs associated with being a public company. TEP's quarterly public company reimbursement was $635,000 for the first quarter of 2015. It is anticipated that, pursuant to the TEGP Omnibus Agreement, Tallgrass Equity will also pay a reimbursement for costs associated with TEGP being a public company beginning in the second quarter of 2015 for the period from May 12, 2015 to June 30, 2015. These amounts will be periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEP and TEGP, respectively.

Due to the cash management agreements discussed in Note 2 – Summary of Significant Accounting Policies, intercompany balances were periodically settled and treated as equity distributions prior to April 1, 2014 for Trailblazer and prior to September 1, 2014 for Pony Express. Balances lent to TD under the Pony Express cash management agreement effective September 1, 2014 are classified as related party receivables in the condensed combined balance sheets. We recognized interest income from TD of $0.4 million during the three months ended March 31, 2015 on the receivable balance under the Pony Express cash management agreement.

Totals of transactions with affiliated companies are as follows:



	Three Months Ended March 31,
	2015		2014
	(in thousands)
Charges to TEGP Predecessor: ⁽¹⁾
Property, plant and equipment, net	$	1,307	$	3,400
Operation and maintenance	$	5,423	$	4,348
General and administrative	$	9,256	$	4,927


⁽¹⁾	Charges to TEGP Predecessor, inclusive of TEP and Pony Express, include directly charged wages and salaries, other compensation and benefits, and shared services.

Details of balances with affiliates included in "Receivable from related party" and "Accounts payable to related parties" in the condensed combined balance sheets are as follows:



	March 31, 2015		December 31, 2014
	(in thousands)
Receivable from related party:
Tallgrass Operations, LLC	$	—	$	73,393
Total receivable from related party	$	—	$	73,393
Accounts payable to related parties:
Tallgrass Operations, LLC	$	2,980	$	3,894
Rockies Express Pipeline LLC	11		21
Deeprock Development, LLC	9		—
Total accounts payable to related parties	$	3,000	$	3,915

Balances of gas imbalances with affiliated shippers are as follows:



	March 31, 2015		December 31, 2014
	(in thousands)
Affiliate gas balance receivables	$	168	$	275
Affiliate gas balance payables	$	410	$	455

6. Inventory

The components of inventory at March 31, 2015 and December 31, 2014 consisted of the following:



	March 31, 2015		December 31, 2014
	(in thousands)
Gas in underground storage	$	6,055	$	8,896
Materials and supplies	4,600		3,049
Crude oil	1,592		581
Natural gas liquids	432		519
Total inventory	$	12,679	$	13,045

7. Property, Plant and Equipment

A summary of net property, plant and equipment by classification is as follows:



	March 31, 2015			December 31, 2014
	(in thousands)
Crude oil pipelines	$	961,288		$	939,536
Natural gas pipelines	553,425			548,482
Processing and treating assets	237,049			241,671
General and other	52,666			42,719
Construction work in progress	194,638			139,873
Accumulated depreciation and amortization	(77,390		)	(59,200		)
Total property, plant and equipment, net	$	1,921,676		$	1,853,081

8. Risk Management

We occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. Specifically, the risks associated with changes in the market price of natural gas include, among others (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.

Fair Value of Derivative Contracts

The following table summarizes the fair values of our derivative contracts included in the condensed combined balance sheets:



	Balance Sheet Location	March 31, 2015		December 31, 2014
		(in thousands)
Energy commodity derivative contracts	Current assets	$	90	$	—

As of March 31, 2015, the fair value shown for commodity contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.9 Bcf. As of December 31, 2014 there were no derivative contracts outstanding.

Effect of Derivative Contracts in the Statements of Income

The following table summarizes the impact of derivative contracts for the three months ended March 31, 2015 and 2014:



		Amount of gain (loss) recognized in income on derivatives
	Location of gain (loss) recognized in income on derivatives	Three Months Ended March 31,
	Location of gain (loss) recognized in income on derivatives	2015		2014
		(in thousands)
Derivatives not designated as hedging contracts:
Energy commodity derivative contracts	Natural gas sales	$	90	$	(351	)

Credit Risk

We have counterparty credit risk as a result of our use of derivative contracts. Our counterparties consist of major financial institutions. This concentration of counterparties may impact our 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.

We maintain credit policies that we believe minimize our overall credit risk. These policies include (i) 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 our policies and exposure, our management does not currently anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.

Our over-the-counter swaps are entered into with counterparties outside central trading organizations such as a futures, options or stock exchange. These contracts are with financial institutions with investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is 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 our derivative contracts at March 31, 2015 was:



	Asset Position
	(in thousands)
Gross	$	90
Netting agreement impact	—
Cash collateral held	—
Net Exposure	$	90

In addition, when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. Accordingly, entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account current credit spreads for its comparative industry sector, as well as any change in such spreads since the last measurement date. As of March 31, 2015 and December 31, 2014, we did not have any outstanding letters of credit or cash in margin accounts in support of our hedging of commodity price risks associated with the sale of natural gas nor did we have margin deposits with counterparties associated with energy commodity contract positions.

Fair Value

Derivative assets and liabilities are measured and reported at fair value. 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. We 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 and commodity and interest rate curves. 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. We 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; as such, 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 our 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.

The following table summarizes the fair value measurements of our energy commodity derivative contracts as of March 31, 2015 based on the fair value hierarchy established by the Codification:



			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)
	(in thousands)
As of March 31, 2015
Energy commodity derivative contracts	$	90	$	—	$	90	$	—

9. Long-term Debt

The following table sets forth the outstanding borrowings, letters of credit issued, and available borrowing capacity under TEP's revolving credit facility as of March 31, 2015 and December 31, 2014:



	March 31, 2015			December 31, 2014
	(in thousands)
Total capacity under the TEP revolving credit facility	$	850,000		$	850,000
Less: Outstanding borrowings under the TEP revolving credit facility	(698,000		)	(559,000		)
Available capacity under the TEP revolving credit facility	$	152,000		$	291,000

The TEP revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP’s ability (as well as the ability of TEP’s restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of TEP’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of March 31, 2015, TEP is in compliance with the covenants required under the TEP revolving credit facility.

The unused portion of the revolving credit facility is subject to a commitment fee, which ranges from 0.300% to 0.500%, based on TEP’s total leverage ratio. As of March 31, 2015, the weighted average interest rate on outstanding borrowings was 2.20%.

Fair Value

The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed combined balance sheets as of March 31, 2015 and December 31, 2014, but for which fair value is disclosed:



	Fair Value
	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount
	(in thousands)
March 31, 2015	$	—	$	698,000	$	—	$	698,000	$	698,000
December 31, 2014	$	—	$	559,000	$	—	$	559,000	$	559,000

The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of March 31, 2015 and December 31, 2014, the fair value approximates the carrying amount for the borrowings under the revolving credit facility using a discounted cash flow analysis. We are not aware of any factors that would significantly affect the estimated fair value subsequent to March 31, 2015.

10. Member's Equity

TEP February Public Offering

On February 27, 2015, TEP sold 10,000,000 common units representing limited partner interests in an underwritten public offering at a price of $50.82 per unit, or $49.29 per unit net of the underwriter's discount, for net proceeds of approximately $492.6 million after deducting the underwriter's discount and offering expenses paid by TEP. TEP used the net proceeds from the offering to fund a portion of the consideration for the acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions. Pursuant to the underwriters' option to purchase additional units, TEP sold an additional 1,200,000 common units representing limited partner interests to the underwriters at a price of $50.82 per unit, or $49.29 per unit net of the underwriter’s discount, for net proceeds of approximately $59.3 million after deducting the underwriter’s discount and offering expenses paid by TEP. TEP used the net proceeds from this additional purchase of common units to reduce borrowings under its revolving credit facility, a portion of which were used to fund the March 2015 acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions.

Other Contributions and Distributions

During the three months ended March 31, 2015, we made net distributions to members of $13.5 million. During the three months ended March 31, 2014, we recognized net contributions from members of $188.7 million. This activity represents transfers of cash as a result of TD’s centralized cash management systems as discussed in Note 1 – Description of Business, as well as the TEP distributions paid on the Acquired TEP Units.

11. Regulatory Matters

There are currently no proceedings challenging the rates of Pony Express, TIGT, or Trailblazer. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable regulations, to challenge the rates that TIGT and Trailblazer charge. Further, the statute governing service by Pony Express allows parties having standing to file complaints in regard to existing tariff rates and provisions. If the complaint is not resolved, the FERC may conduct a hearing and order a crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. We can provide no assurance that current rates will remain unchallenged. Any successful challenge could have a material, adverse effect on our future earnings and cash flows.

TIGT

Pony Express Abandonment – FERC Docket CP12-495

On August 6, 2012, TIGT filed an application to: (1) abandon for FERC purposes approximately 433 miles of mainline natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the "Pony Express Assets"), and the natural gas service therefrom, by transferring those assets to Pony Express, which subsequently converted the Pony Express Assets 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 conversion, which we refer to as the Replacement Gas Facilities. This project is referred to as the "Pony Express Abandonment." The FERC abandonment does not constitute an abandonment for accounting purposes. Pursuant to the terms of the Purchase and Sale Agreement filed with the FERC and cited by the FERC in approving the Pony Express Abandonment, Pony Express is required to reimburse TIGT for the net book value of the Pony Express Assets plus other TIGT incurred costs required to construct the Replacement Gas Facilities and to arrange substitute gas transportation services to certain TIGT shippers.

The Pony Express Abandonment and completion of the Pony Express Project by Pony Express re-deployed existing pipeline assets to meet the growing market need to transport oil supplies while at the same time continuing to operate TIGT’s natural gas transportation facilities to meet all current and expected needs of its natural gas customers. By a FERC order issued September 12, 2013, TIGT was granted authorization to abandon the Pony Express Assets and construct the Replacement Gas Facilities. On October 7, 2013 TIGT commenced the mobilization of personnel and equipment for the construction of the Replacement Gas Facilities necessary to complete the Pony Express Abandonment to continue service to existing TIGT customers. In December 2013, TIGT removed the Pony Express Assets from gas service and sold those assets to Pony Express. On May 1, 2014, TIGT commenced commercial service through all of the Replacement Gas Facilities, with the exception of Units 3 and 4 at the Tescott Compressor Station. Service through Units 3 and 4 at the Tescott Compressor Station commenced on May 30, 2014.

Trailblazer

2013 Rate Case Filing - Docket No. RP13-1031

On July 1, 2013, Trailblazer made a rate filing with the FERC pursuant to Section 4 of the Natural Gas Act in Docket No. RP13-1031. In this filing, Trailblazer proposed an overall cost of service of $25.7 million, an increase of the base rates, rolled-in base and fuel rates, an overall rate of return of 10.94% and new depreciation rates. On July 31, 2013, the FERC issued an order accepting Trailblazer’s filing and suspending the filed tariff rates, subject to refund, for the full statutorily permitted five-month suspension period and setting certain issues for hearing. The FERC resolved the non-rate aspects of Trailblazer’s rate case in an order dated December 30, 2013.

In conjunction with this filing for rolled-in fuel rates, Trailblazer elected to not seek recovery of unrecovered fuel costs incurred prior to January 1, 2014. Consequently, Trailblazer has recognized expenses related to unrecovered fuel costs of $578,000 for the period from November 13, 2012 to December 31, 2012, $6.0 million for period from January 1, 2012 to November 12, 2012 and $8.4 million during the year ended December 31, 2013.

On January 22, 2014, Trailblazer, the FERC’s Trial Staff, and the active parties in the pipeline’s general rate case finalized a settlement in principle resolving the pending rate issues, including: (i) establishing transportation rates, as well as fuel and lost and unaccounted for charges; (ii) providing a limited profit sharing arrangement for certain revenues earned from interruptible and short-term firm transport; and (iii) setting the minimum and maximum time that can elapse before Trailblazer’s next rate case at the FERC. Trailblazer filed a motion with FERC’s Chief Administrative Law Judge to accept the

settlement rates on an interim basis ("Interim Rates") while the participants finalized a definitive settlement. The Chief Administrative Law Judge accepted the Interim Rates effective February 1, 2014. On February 24, 2014, Trailblazer filed an uncontested offer of settlement ("Stipulation and Agreement") among active party shippers. The Stipulation and Agreement established the Interim Rates as final settlement rates effective February 1, 2014, subject to the issuance of refunds to certain shippers for January 2014 transportation services and revised fuel and lost and unaccounted for rates, effective July 1, 2014. On March 11, 2014, the Presiding Administrative Law Judge certified the Stipulation and Agreement. On May 29, 2014, the FERC approved the Stipulation and Agreement. On June 30, 2014, Trailblazer filed tariff sheets to implement the Stipulation and Agreement effective July 1, 2014. Estimated refunds were reserved from revenues recorded in January 2014. On July 1, 2014, Trailblazer submitted refunds to its customers for amounts collected in excess of amounts that would have been collected under the Settlement Rates, with interest, and on July 18, 2014, filed a report of refunds with the FERC. The FERC issued orders accepting the tariff sheets with the requested effective date of July 1, 2014 and accepting the refund report filing on July 25, 2014 and August 7, 2014, respectively.

2015 Annual Fuel Tracker Filing - Docket No. RP15-841-000

On April 1, 2015, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2015 in Docket No. RP15-841-000. This filing incorporates the revised fuel tracker and power cost tracker mechanisms agreed to in the 2013 Rate Case Filing settlement, which resolves all outstanding issues related to Trailblazer fuel recoveries. The FERC approved this filing on April 23, 2015.

Pony Express

In anticipation of placing the Pony Express System into service, several petitions for declaratory orders were submitted to the FERC by Pony Express and certain upstream pipelines interconnected with the Pony Express System to address considerations related to the Pony Express System and other matters. In response to these petitions, the FERC issued three declaratory orders (two in 2012 and one in 2014) approving the proposed rate structures and terms of service for the Pony Express System.

On September 19, 2014 Pony Express filed with the FERC to adopt a tariff for initial local non-contract rates as well as initial Rules and Regulations in accordance with the Interstate Commerce Act to be effective starting on October 1, 2014. Local Contract Tariff rates were filed with the FERC on October 29, 2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express System from the Belle Fourche Pipeline were filed on October 16, 2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express pipeline system from Hiland Pipeline Company were filed on February 27, 2015 and effective April 1, 2015.

12. Legal and Environmental Matters

Legal

In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on our business, financial position, results of operations or cash flows.

We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, had aggregate reserves for legal claims of approximately $0.6 million as of March 31, 2015 and December 31, 2014.

TIGT

Prairie Horizon

On July 3, 2014, Prairie Horizon Agri-Energy LLC ("Prairie Horizon") filed an action in the District Court of Phillips County, Kansas against TIGT seeking damages from an alleged intrusion of foreign material and oil from TIGT into Prairie Horizon's ethanol plant. The matter was removed to the US District Court for the District of Kansas. Prairie Horizon asserts that this intrusion caused substantial damage to Prairie Horizon's ethanol production facilities and resulted in corresponding business income losses. Prairie Horizon also claims that the intrusion was a violation of TIGT's FERC gas tariff. Prairie Horizon alleges that it has suffered damages in the amount of approximately $2.0 million. TIGT believes Prairie Horizon's claims are without merit and plans to vigorously contest all of the claims in this matter.

System Failure

On June 13, 2013, a failure occurred on a segment of the TIGT pipeline system in Goshen County, Wyoming, resulting in the release of natural gas. The line was promptly brought back into service and the failure did not cause any known injuries, fatalities, fires or evacuations. We are currently working with PHMSA to develop a plan to close the Corrective Action Order received from PHMSA regarding the Goshen County failure and does not believe the cost of anticipated remediation activities will be material.

Pony Express

System Failures

On August 31, 2014, a leak occurred at the Sterling Pump Station on the Pony Express System in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on our property and the costs to remediate were not material. In April 2015, PHSMA granted our request to consider the Sterling Pump Station incident closed with no further action.

On March 12, 2015, an event occurred at the Yoder Pump Station in Goshen County, Wyoming, related to repair and replacement activities resulting in a spill of approximately 300 bbls of crude oil. We have presented our incident investigation findings to PHMSA and are currently working with PHMSA to resolve the matter. We do not believe the cost of anticipated remediation activities will be material.

Environmental

We 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. We believe that compliance with these laws will not have a material adverse impact on our 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 us to incur significant costs. We had environmental accruals of $5.2 million and $5.3 million at March 31, 2015 and December 31, 2014, respectively.

TMID

Casper Plant, U.S. EPA Notice of Violation

In August 2011, the U.S. EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC ("TMID") 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. TMID received a letter from the U.S. EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the U.S. EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including attempted resolution of more recently identified LDAR issues.

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 we have requested that the portion of the site attributable to us be delisted from the National Priorities List.

Casper Gas Plant

On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing.

13. Reporting Segments

Our operations are located in the United States. We are organized into three reporting segments: (1) Natural Gas Transportation & Logistics, (2) Crude Oil Transportation & Logistics, and (3) Processing & Logistics.

Natural Gas Transportation & Logistics

The Natural Gas Transportation & Logistics segment is engaged in ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. As discussed in Note 2 – Summary of Significant Accounting Policies, results for prior periods have been recast to reflect the operations of Trailblazer.

Crude Oil Transportation & Logistics

The Crude Oil Transportation & Logistics segment is engaged in ownership, construction, and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in April 2015. As discussed in Note 2 – Summary of Significant Accounting Policies, results for prior periods have been recast to reflect the operations of Pony Express.

Processing & Logistics

The Processing & Logistics segment is engaged in 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, as well as water business services provided primarily to the oil and gas exploration and production industry.

Corporate and Other

Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with TEP’s revolving credit facility, public company costs reimbursed to TD, and equity-based compensation expense.

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 their respective operations. We measure segment profit using Operating Income.

The following tables set forth our segment information for the periods indicated:



	Three Months Ended March 31, 2015							Three Months Ended March 31, 2014
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
			(in thousands)							(in thousands)
Natural Gas Transportation & Logistics	$	33,610	$	(1,346	)	$	32,264	$	39,631	$	(1,255	)	$	38,376
Crude Oil Transportation & Logistics	50,381		—			50,381		—		—			—
Processing & Logistics	32,030		—			32,030		56,403		—			56,403
Corporate and Other	—		—			—		—		—			—
Total revenue	$	116,021	$	(1,346	)	$	114,675	$	96,034	$	(1,255	)	$	94,779



	Three Months Ended March 31, 2015									Three Months Ended March 31, 2014
Operating Income:	Total Operating Income			Inter- Segment			External Operating Income			Total Operating Income			Inter- Segment			External Operating Income
				(in thousands)									(in thousands)
Natural Gas Transportation & Logistics	$	12,553		$	(1,346	)	$	11,207		$	12,966		$	(1,255	)	$	11,711
Crude Oil Transportation & Logistics	14,273			1,346			15,619			(757		)	—			(757		)
Processing & Logistics	1,054			—			1,054			7,141			—			7,141
Corporate and Other	(2,162		)	—			(2,162		)	(1,566		)	—			(1,566		)
Total Operating Income	$	25,718		$	—		$	25,718		$	17,784		$	(1,255	)	$	16,529
Reconciliation to Net Income:
Interest expense, net							(3,440		)							(1,296		)
Equity in earnings of unconsolidated investment							—									444
Other income, net							712									940
Net Income							$	22,990								$	16,617



	Three Months Ended March 31,
Capital Expenditures:	2015		2014
			(in thousands)
Natural Gas Transportation & Logistics	$	3,865	$	9,626
Crude Oil Transportation & Logistics	6,480		196,437
Processing & Logistics	2,955		3,048
Corporate and Other	—		—
Total capital expenditures	$	13,300	$	209,111



Assets:	March 31, 2015		December 31, 2014
	(in thousands)
Natural Gas Transportation & Logistics	$	719,510	$	716,106
Crude Oil Transportation & Logistics	1,391,417		1,394,793
Processing & Logistics	337,303		340,620
Corporate and Other	5,321		5,678
Total assets	$	2,453,551	$	2,457,197

14. Subsequent Events

Initial Public Offering

On May 12, 2015, TEGP closed the Offering of 47,725,000 Class A shares at a price of $29.00 per Class A share, which included 6,225,000 of Class A shares from the exercise of the over-allotment option by the underwriters. Proceeds to TEGP from the sale of the Class A shares were approximately $1.3 billion, net of certain offering costs and underwriters’ commissions. In connection with the closing of the Offering on May 12, 2015, the Reorganization Transactions occurred as outlined in Note 1 – Description of Business.

Tallgrass Equity Revolving Credit Facility

In connection with the Offering, Tallgrass Equity entered into a new $150 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 12, 2020. The Tallgrass Equity credit facility includes a $10 million sublimit for letters of credit and a $10 million sublimit for swing line loans. The Tallgrass Equity revolving credit facility may be used (i) to pay transaction costs and any fees and expenses incurred in connection with the revolving credit facility and certain transactions relating to the Offering, (ii) to fund the purchase of the Acquired TEP Units and (iii) for general company purposes, including distributions. The Tallgrass Equity revolving credit facility also contains an accordion feature whereby Tallgrass Equity can increase the size of the credit facility to an aggregate of $200 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent.

Upon the close of the Offering, Tallgrass Equity had $150 million in outstanding borrowings under the credit facility, leaving no remaining capacity available for future borrowings or letter of credit issuances. The initial borrowings under the credit facility were used to fund a portion of the purchase of the Acquired TEP Units and to pay origination and arrangement fees associated with the new revolving credit facility and transaction costs associated with the Offering. Tallgrass Equity’s obligations under the revolving credit facility are secured by a first priority lien on all of the present and after acquired equity interests held by Tallgrass Equity in TEP GP and TEP. Borrowings under the credit facility bear interest, at Tallgrass Equity’s 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 is 1.50%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is 2.50%.

TEGP Partnership Agreement

In connection with the Offering, TEGP entered into an amended and restated partnership agreement on May 12, 2015. The partnership agreement requires TEGP to distribute its available cash to Class A shareholders on a quarterly basis, subject to certain terms and conditions, beginning with the quarter ending June 30, 2015. No distributions were declared by TEGP for the three months ended March 31, 2015. We anticipate declaring a prorated distribution in the second quarter of 2015 for the period from May 12, 2015 to June 30, 2015.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The historical financial statements included in this Quarterly Report reflect the combined results of operations of Tallgrass Energy GP, LP ("TEGP")'s 30.35% interest in Tallgrass Equity, LLC ("Tallgrass Equity"), Tallgrass Equity's 100% membership interest in Tallgrass MLP GP, LLC ("TEP GP"), which owns all of the Incentive Distribution Rights, or IDRs, and all of the outstanding general partner units in Tallgrass Energy Partners, LP ("TEP"), and Tallgrass Equity's 20 million TEP common units it acquired at the closing of the initial public offering of Class A shares of TEGP (the "Offering"). In connection with the closing of the Offering on May 12, 2015, the following transactions (the “Reorganization Transactions”) occurred (i) Tallgrass Equity distributed its interests in Tallgrass Energy Holdings, LLC ("Holdings") and Holdings distributed its existing limited partner interest in TEGP, respectively, to the existing owners of Tallgrass Equity that also collectively own 100% of the voting power of Holdings, which are referred to as the “Exchange Right Holders;” (ii) TEGP issued 47,725,000 Class A shares to the public (including 6,225,000 Class A shares issued in connection with the underwriters' exercise of the overallotment option) for net proceeds of approximately $1.3 billion; (iii) the existing limited partner interests in TEGP held by the Exchange Right Holders were converted into 115,729,440 Class B shares, 6,225,000 of which were automatically cancelled in connection with the underwriters’ exercise of its overallotment option; (iv) Tallgrass Equity issued 41,500,000 Tallgrass Equity units to TEGP in exchange for approximately $1.1 billion in net proceeds from the issuance of TEGP’s Class A shares to the public and amended the limited liability company agreement of Tallgrass Equity to, among other things, provide that TEGP is the managing member of Tallgrass Equity; (v) TEGP used the net proceeds from the purchase of the 6,225,000 overallotment option shares to purchase a like amount of Tallgrass Equity units from the Exchange Right Holders; and (vi) Tallgrass Equity entered into a $150 million revolving credit facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings, together with the net proceeds from the Offering that Tallgrass Equity received from TEGP, to purchase 20 million TEP common units from Tallgrass Development, LP ("TD") at $47.68 per TEP common unit (the “Acquired TEP Units”) and pay offering expenses and other transaction costs. Tallgrass Equity distributed the remaining proceeds to the Exchange Right Holders. The following discussion analyzes the financial condition and results of operations of TEGP Predecessor, which refers to TEGP, as recast to show the effects of the Reorganization Transactions, for the periods prior to completion of the Offering.

In certain circumstances and for ease of reading we discuss the financial results of these entities prior to their respective acquisitions as being "our" financial results during historic periods, although Trailblazer Pipeline Company LLC ("Trailblazer") was owned by TD from November 13, 2012 to March 31, 2014, and Tallgrass Pony Express Pipeline, LLC ("Pony Express") was wholly-owned by TD from November 13, 2012 to August 31, 2014. As used in Item 2 of this Quarterly Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEGP" and similar terms refer to Tallgrass Energy GP, LP, together with its consolidated subsidiaries (including Tallgrass Equity, TEP and their respective subsidiaries). The term our "general partner" refers to TEGP Management, LLC. References to "TD" refer to Tallgrass Development, LP.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed combined financial statements and related notes thereto included elsewhere in this Quarterly Report and the audited TEP financial statements and notes thereto, the related "Management's Discussion and Analysis of Financial Condition and Results of Operations," the discussion of "Risk Factors" and the discussion of TEGP's "Business" in our final prospectus dated May 6, 2015 (the “Prospectus”) and filed with the United States Securities and Exchange Commission (the “SEC”) on May 7, 2015.

A reference to a "Note" herein refers to the accompanying Notes to Condensed Combined Financial Statements contained in Item 1.—Financial Statements. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report and the documents incorporated by reference herein contain forward-looking statements concerning our operations, economic performance and financial condition. 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 Quarterly Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our and TD’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 Quarterly Report. 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:


•	our ability to complete and integrate acquisitions from TD or from third parties, including our acquisition of an additional 33.3% interest in Pony Express that was completed in March 2015;


•	changes in general economic conditions;


•	competitive conditions in our industry;


•	actions taken by third-party operators, processors and transporters;


•	the demand for natural gas transportation, storage and processing services and crude oil 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 and crude oil, and fuels derived from both, 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 crude oil and 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 tax status;


•	the effects of existing and future laws and governmental regulations;


•	the effects of future litigation; and


•	certain factors discussed elsewhere in this Quarterly Report.

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.

Overview

TEGP is a recently formed Delaware limited partnership that has elected to be treated as a corporation for U.S. federal income tax purposes. Our only cash-generating assets consist of an approximately 30.35% controlling interest in Tallgrass Equity. Tallgrass Equity owns, through its ownership of TEP GP, all of TEP's IDRs and 834,391 TEP general partner units, representing an approximate 1.37% general partner interest in TEP as of March 31, 2015. Tallgrass Equity also owns directly 20 million TEP limited partner common units, representing an approximate 32.75% limited partner interest in TEP as of March 31, 2015.

TEP is a publicly traded, growth-oriented Delaware limited partnership formed in 2013 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 the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the “TIGT System”), and a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the “Trailblazer Pipeline”). We provide crude oil transportation to customers in Wyoming and the surrounding region, servicing the Bakken oil production area of North Dakota and eastern Montana through our membership

interest in Pony Express, which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma (the “Pony Express System”). We also provide services for customers in Wyoming at the Casper and Douglas natural gas processing facilities and the West Frenchie Draw natural gas treating facility, or, collectively, the Midstream Facilities, and we provide water business services to customers in Colorado and Texas through BNN Water Solutions, LLC ("Water Solutions"). Our operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations.

We intend to continue to leverage our relationship with TD and utilize the significant experience of our management team to execute our growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of our existing assets and expanding our systems through construction of additional assets. Our reportable business segments are:


•	Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities;


•	Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system; and


•	Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, as well as water business services provided primarily to the oil and gas exploration and production industry.

Financial Presentation

TEGP has no operations outside of its indirect ownership interests in TEP. TEGP is the managing member of and therefore controls Tallgrass Equity. Tallgrass Equity, in turn, controls TEP through the direct ownership of 100% of TEP GP, TEP’s general partner. As a result, under generally accepted accounting principles, TEGP consolidates Tallgrass Equity, TEP GP, TEP, and TEP's subsidiaries. As such, TEGP's results of operations will not differ materially from the results of operations of TEP. The most noteworthy reconciling items between TEGP's condensed combined financial statements and TEP's condensed consolidated financial statements primarily relate to (i) the inclusion of the Tallgrass Equity revolving credit facility, (ii) the impact of TEGP's election to be treated as a corporation for U.S. federal income tax purposes and (iii) the presentation of noncontrolling interests in Tallgrass Equity and TEP. The interests in Tallgrass Equity and TEP that are not directly or indirectly owned by TEGP will be reflected as being attributable to noncontrolling interests in TEGP's condensed combined financial statements.

In addition, TEP’s historical results of operations do not reflect TEGP's anticipated incremental general and administrative costs associated with becoming a separate publicly traded entity, including expenses associated with (i) compensation for new directors, (ii) incremental director and officer liability insurance, (iii) listing on the NYSE, (iv) investor relations, (v) legal, (vi) tax and (vii) accounting.

Recent Developments

TEP Distribution Declared

On April 14, 2015, the Board of Directors of TEP's general partner declared a cash distribution for the quarter ended March 31, 2015 of $0.52 per common unit. The distribution was paid on May 14, 2015, to TEP unitholders of record on April 24, 2015.

Pony Express Lateral In-Service

In April 2015, Pony Express placed in service the approximately 66-mile lateral in northeast Colorado commencing in Weld County, Colorado to interconnect with the existing Pony Express System just east of Sterling, Colorado.

Initial Public Offering

On May 12, 2015, TEGP closed the Offering of 47,725,000 Class A shares at a price of $29.00 per Class A share, which included 6,225,000 of Class A shares from the exercise of the over-allotment option by the underwriters. Proceeds from the sale of the Class A shares were approximately $1.3 billion, net of certain offering costs and underwriters’ commissions. In connection with the closing of the Offering on May 12, 2015, the Reorganization Transactions occurred as outlined above.

Tallgrass Equity Revolving Credit Facility

TEGP Partnership Agreement

U.S. Crude Oil and Natural Gas Supply and Demand Dynamics

Crude oil, natural gas and products derived from both continue to be critical components of energy supply and demand in the United States. Although crude oil and natural gas prices have declined in the latter part of 2014 and early 2015, we believe that the long-term prospects for continued crude oil and natural gas production increases are favorable and will be driven in part by increased domestic demand resulting from population and economic growth, higher industrial consumption in the U.S. and a desire to reduce domestic reliance on imports. We expect natural gas to continue to displace coal-fired electricity generation due to the low prices of natural gas and stricter environmental regulations on the mining and burning of coal. For additional information, please read Item 3.-Quantitative and Qualitative Disclosures About Market Risk.

How We Evaluate Our Operations

We evaluate our results using, among other measures, cash distributions received from Tallgrass Equity, TEP's contract profile and volumes, and operating costs and expenses of TEGP and its consolidated subsidiaries.

Cash Distributions Received from Tallgrass Equity

TEGP's cash flow is generated solely from distributions received from Tallgrass Equity. Tallgrass Equity currently receives all of its cash flows from distributions on its direct and indirect partnership interests in TEP. Tallgrass Equity is therefore entirely dependent upon the ability of TEP to make cash distributions to its partners.

TEP's Contract Profile and Volumes

Our results are driven primarily by the volume of crude oil transportation capacity under firm contracts, 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.

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 costs. Our operating expenses are driven primarily by expenses related to the operation, maintenance and growth of our asset base.

Results of Operations

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



	Three Months Ended March 31,
	2015			2014
	(in thousands, except operating data)
Revenues:
Natural gas liquids sales	$	21,025		$	48,907
Natural gas sales	844			4,808
Natural gas transportation services	32,148			34,104
Crude oil transportation services	50,381			—
Processing and other revenues	10,277			6,960
Total Revenues	114,675			94,779
Operating Costs and Expenses:
Cost of sales	19,593			48,206
Cost of transportation services	10,715			5,117
Operations and maintenance	9,575			8,013
Depreciation and amortization	20,605			8,309
General and administrative	12,689			6,649
Taxes, other than income taxes	11,297			1,956
Loss on sale of assets	4,483			—
Total Operating Costs and Expenses	88,957			78,250
Operating Income	25,718			16,529
Other (Expense) Income:
Interest expense, net	(3,440		)	(1,296		)
Equity in earnings of unconsolidated investment	—			444
Other income, net	712			940
Total Other (Expense) Income	(2,728		)	88
Net Income	22,990			16,617
less: Net income attributable to noncontrolling interests	(17,868		)	(13,979		)
Net income attributable to TEGP Predecessor	$	5,122		$	2,638
Operating Data
Gas transportation firm contracted capacity (MMcf/d)	1,609			1,604
Crude oil transportation average throughput (Bbls/d)	165			N/A
Natural gas processing inlet volumes (MMcf/d)	145			151

Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

Revenues. Total revenues were $114.7 million for the three months ended March 31, 2015, compared to $94.8 million for the three months ended March 31, 2014, which represents an increase of $19.9 million, or 21%, in total revenues. The overall increase in revenue was largely driven by revenues of $50.4 million in the Crude Oil Transportation & Logistics segment for the three months ended March 31, 2015. There were no revenues in that segment for the three months ended March 31, 2014 as Pony Express had not yet commenced commercial operations. Revenue in the Processing & Logistics and Natural Gas Transportation & Logistics segments decreased $24.4 million, or 43%, and $6.0 million, or 15%, respectively.

Operating costs and expenses. Operating costs and expenses were $89.0 million for the three months ended March 31, 2015 compared to $78.3 million for the three months ended March 31, 2014, which represents an increase of $10.7 million, or 14%. The increase in operating costs and expenses is primarily driven by an overall increase in operating costs and expenses of $35.4 million in the Crude Oil Transportation & Logistics segment reflecting the commencement of commercial operations at Pony Express. The increased costs in the Crude Oil Transportation & Logistics segment were partially offset by decreased costs of $18.3 million and $5.6 million in the Processing & Logistics and Gas Transportation & Logistics segments, respectively.

Interest expense, net. Interest expense of $3.4 million for the three months ended March 31, 2015 was primarily composed of interest and fees associated with TEP’s revolving credit facility, partially offset by interest income of $0.4 million on the cash balance swept to TD under the Pony Express cash management agreement. Interest expense of $1.3 million for the three months ended March 31, 2014 was primarily composed of interest and fees associated with TEP’s revolving credit facility. The increase in interest and fees associated with TEP's revolving credit facility is primarily due to higher average borrowings under the revolving credit facility during the three months ended March 31, 2015 over the three months ended March 31, 2014.

Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.4 million for the three months ended March 31, 2014 was related to our investment in GWSI prior to TEP's consolidation of the Water Solutions business on May 13, 2014.

Other income, net. Other income, net typically includes rental income, income earned from certain customers related to the capital costs we incurred to connect these customers to our system, the allowance for funds used during construction at our regulated entities, and other noncash gains and losses. Other income for the three months ended March 31, 2015 was $0.7 million compared to $0.9 million for the three months ended March 31, 2014.

The following provides a summary of our Natural Gas Transportation & Logistics segment results of operations for the periods indicated:



Segment Financial Data - Natural Gas Transportation & Logistics⁽¹⁾	Three Months Ended March 31,
	2015		2014
	(in thousands)
Revenues:
Natural gas sales	$	105	$	4,116
Natural gas transportation services	33,494		35,359
Processing and other revenues	11		156
Total revenues	33,610		39,631
Operating costs and expenses:
Cost of sales	74		3,827
Cost of transportation services	3,316		5,117
Operations and maintenance	5,740		6,049
Depreciation and amortization	6,071		5,605
General and administrative	4,261		4,192
Taxes, other than income taxes	1,595		1,875
Total operating costs and expenses	21,057		26,665
Operating income	$	12,553	$	12,966


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the combined financial data, see Note 13 – Reporting Segments to the accompanying condensed combined financial statements.

Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

Revenues. Natural Gas Transportation & Logistics segment revenues were $33.6 million for the three months ended March 31, 2015, compared to $39.6 million for the three months ended March 31, 2014, which represents a $6.0 million, or 15%, decrease in segment revenues primarily driven by a $4.0 million decrease in natural gas sales as a result of lower volumes sold and a 58% decrease in natural gas prices.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $21.1 million for the three months ended March 31, 2015 compared to $26.7 million for the three months ended March 31, 2014, which represents a decrease of $5.6 million, or 21%.

Cost of sales decreased $3.8 million, or 98%, in the three months ended March 31, 2015 when compared to the same period in the prior year, due to lower natural gas sales volumes at TIGT and 50% lower natural gas prices.

Cost of transportation services decreased $1.8 million, or 35%, in the three months ended March 31, 2015 when compared to the same period in the prior year, primarily due to decreased fuel reimbursements of $2.1 million, driven by lower transportation volumes, and decreased fuel recoveries of $1.8 million.

Operations and maintenance costs decreased $0.3 million, or 5%, in the three months ended March 31, 2015 when compared to the same period in the prior year.

Depreciation and amortization increased $0.5 million, or 8%, in the three months ended March 31, 2015 when compared to the same period in the prior year.

General and administrative costs increased $0.1 million, or 2%, in the three months ended March 31, 2015 when compared to the same period in the prior year.

Taxes, other than income taxes, decreased $0.3 million, or 15%, in the three months ended March 31, 2015 when compared to the same period in the prior year, primarily due to lower property taxes as a result of successful appeals with state taxing authorities on the assessed value of property.

The following provides a summary of our Crude Oil Transportation & Logistics segment results of operations for the periods indicated:



Segment Financial Data - Crude Oil Transportation & Logistics ⁽¹⁾	Three Months Ended March 31,
	2015		2014
	(in thousands)
Revenues:
Crude Oil transportation services	$	50,381	$	—
Total revenues	50,381		—
Operating costs and expenses:
Cost of transportation services	8,709		—
Operations and maintenance	1,415		—
Depreciation and amortization	11,233		757
General and administrative	5,155		—
Taxes, other than income taxes	9,596		—
Total operating costs and expenses	36,108		757
Operating income (loss)	$	14,273	$	(757	)


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the combined financial data, see Note 13 – Reporting Segments to the accompanying condensed combined financial statements.

Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

Revenues. Crude Oil Transportation & Logistics segment revenues of $50.4 million for the three months ended March 31, 2015 represents transportation revenue on Pony Express, which was placed in service in October 2014. There were no revenues for the three months ended March 31, 2014 as Pony Express had not yet commenced commercial operations.

Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were $36.1 million for the three months ended March 31, 2015 compared to $0.8 million for the three months ended March 31, 2014. Operating costs and expenses for the three months ended March 31, 2015 include costs associated with the start of commercial operations in October 2014 as well as the amortization of the Pony Express oil conversion use rights. For the three months ended March 31, 2014, operating costs and expenses consisted of the amortization of the Pony Express oil conversion use rights.

The following provides a summary of our Processing & Logistics segment results of operations for the periods indicated:



Segment Financial Data - Processing & Logistics ⁽¹⁾	Three Months Ended March 31,
	2015		2014
	(in thousands)
Revenues:
Natural gas liquids sales	$	21,025	$	48,907
Natural gas sales	739		692
Processing and other revenues	10,266		6,804
Total revenues	32,030		56,403
Operating costs and expenses:
Cost of sales	19,519		44,379
Cost of transportation services	36		—
Operations and maintenance	2,420		1,964
Depreciation and amortization	3,301		1,947
General and administrative	1,111		891
Taxes, other than income taxes	106		81
Loss on sale of assets	4,483		—
Total operating costs and expenses	30,976		49,262
Operating income	$	1,054	$	7,141


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the combined financial data, see Note 13 – Reporting Segments to the accompanying condensed combined financial statements.

Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

Revenues. Processing & Logistics segment revenues were $32.0 million for the three months ended March 31, 2015, compared to $56.4 million for the three months ended March 31, 2014, which represents a $24.4 million, or 43%, decrease in segment revenues. The decrease in segment revenues was primarily due to a $27.9 million decrease in natural gas liquids sales at TMID, partially offset by a $3.0 million increase in processing and other revenues at Water Solutions. The decrease in natural gas liquids sales at TMID was driven by reduced volumes processed and a 67% decrease in NGL prices. The Water Solutions business was consolidated in May 2014 and recognized processing and other revenues of $3.0 million during the three months ended March 31, 2015. Prior to its consolidation in May 2014, TEP's investment in Water Solutions was accounted for under the equity method of accounting and as a result TEP recognized no revenues from Water Solutions during the three months ended March 31, 2014.

Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $31.0 million for the three months ended March 31, 2015 compared to $49.3 million for the three months ended March 31, 2014, which represents a decrease of $18.3 million, or 37%.

Cost of sales decreased $24.9 million, or 56%, in the three months ended March 31, 2015 when compared to the same period in the prior year, primarily driven by decreased volumes processed and lower NGL prices as discussed above.

Cost of transportation services of $36,000 in the three months ended March 31, 2015 represent the costs of water transportation at the Water Solutions business, which was consolidated in May 2014.

Operations and maintenance costs increased $0.5 million, or 23%, in the three months ended March 31, 2015 when compared to the same period in the prior year, primarily driven by operations and maintenance costs at Water Solutions of $0.4 million during the three months ended March 31, 2015. Prior to its consolidation in May 2014, TEP's investment in Water Solutions was accounted for under the equity method of accounting and as a result TEP recognized no operations and maintenance costs during the three months ended March 31, 2014.

Depreciation and amortization increased $1.4 million, or 70%, in the three months ended March 31, 2015 when compared to the same period in the prior year, primarily driven by depreciation and amortization at Water Solutions of $1.3 million during the three months ended March 31, 2015. Prior to its consolidation in May 2014, TEP's investment in Water Solutions was accounted for under the equity method of accounting and as a result TEP recognized no depreciation and amortization during the three months ended March 31, 2014.

General and administrative costs increased $0.2 million, or 25%, in the three months ended March 31, 2015 when compared to the same period in the prior year, primarily driven by the consolidation of Water Solutions in May 2014.

Taxes, other than income taxes, were comparable during the three months ended March 31, 2015 and the three months ended March 31, 2014.

Loss on sale of assets during the three months ended March 31, 2015 represents a noncash loss recognized on the sale of compressor assets at TMID during the three months ended March 31, 2015.

Liquidity and Capital Resources Overview

Subsequent to the completion of the Offering on May 12, 2015, we expect our primary sources of liquidity on a consolidated basis to include cash generated from our operations, borrowing capacity available under TEP's revolving credit facility, and future issuances of equity and/or debt securities.

We believe that cash on hand, cash generated from operations, and availability under TEP’s revolving 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 a combination of borrowings under TEP's revolving credit facility and issuance of debt and/or equity securities.

Our total liquidity as of March 31, 2015 and December 31, 2014 was as follows:



	March 31, 2015			December 31, 2014
	(in thousands)
Cash on hand	$	876		$	867
Total capacity under the TEP revolving credit facility	850,000			850,000
Less: Outstanding borrowings under the TEP revolving credit facility	(698,000		)	(559,000		)
Less: Letters of credit issued under the TEP revolving credit facility	—			—
Available capacity under the TEP revolving credit facility	152,000			291,000
Total liquidity	$	152,876		$	291,867

TEP Revolving Credit Facility

The unused portion of TEP's revolving credit facility is subject to a commitment fee, which ranges from 0.300% to 0.500%, based on TEP’s total leverage ratio. As of March 31, 2015, the weighted average interest rate on outstanding borrowings was 2.20%.

TEP Public Offering

Working Capital

Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements have been, and we expect will continue to be, primarily driven by changes in accounts receivable and accounts payable. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, and receivables from related parties, as well as the level of spending for capital expenditures and changes in the market prices of energy commodities that we buy and sell in the normal course of business.

As of March 31, 2015, we had a working capital deficit of $40.8 million compared to a working capital surplus of $35.7 million at December 31, 2014, which represents a decrease in working capital of $76.5 million. The overall decrease in working capital was primarily attributable to a decrease of $73.4 million in receivables from related parties due to the utilization of the Pony Express cash balance swept to TD under the cash management agreement.

A material adverse change in operations, available financing under our revolving credit facility, or available financing from the equity or debt capital markets could impact our ability to fund our requirements for liquidity and capital resources in the future.

Cash Flows

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



	Three Months Ended March 31,
	2015			2014
	(in thousands)
Net cash provided by (used in):
Operating activities	$	48,639		$	27,603
Investing activities	$	(713,611	)	$	(211,021	)
Financing activities	$	664,981		$	183,418

Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

Operating Activities. Cash flows provided by operating activities were $48.6 million and $27.6 million for the three months ended March 31, 2015 and 2014, respectively. The increase in net cash flows provided by operating activities of $21.0 million was primarily driven by increased operating results during the period, largely driven by the start of commercial operations at Pony Express in October 2014, as well as higher cash inflows as a result of changes in working capital balances, primarily driven by an increase in accounts payable and accrued liabilities due to property tax accruals in the Crude Oil Transportation & Logistics segment during the three months ended March 31, 2015.

Investing Activities. Cash flows used in investing activities were $713.6 million and $211.0 million for the three months ended March 31, 2015 and 2014, respectively. During the three months ended March 31, 2015, net cash used in investing activities were driven by the $700 million cash outflow for the acquisition of an additional 33.3% membership interest in Pony Express and capital expenditures of $13.3 million, primarily due to construction of the Pony Express System, including the lateral in Northeast Colorado. In the three months ended March 31, 2014, net cash used in investing activities was driven by $209.1 million in capital expenditures, consisting primarily of spending on the conversion and construction of the Pony Express System.

Financing Activities. Cash flows provided by financing activities were $665.0 million and $183.4 million for the three months ended March 31, 2015 and 2014, respectively. Financing cash inflows for the three months ended March 31, 2015 were primarily driven by $551.9 million and $139.0 million, respectively, from the issuance of 11.2 million TEP common units in a public offering during the three months ended March 31, 2015 and net borrowings under the TEP revolving credit facility, the proceeds of which were used to fund the acquisition of an additional 33.3% membership interest in Pony Express as discussed above. These financing cash inflows were partially offset by distributions to TEP unitholders of $14.8 million and distributions to TEGP Predecessor Members of $13.5 million. Cash flows provided by financing activities for the three months ended March 31, 2014 consisted primarily of net contributions from TEGP Predecessor Members of $188.7 million. These financing cash inflows were partially offset by distributions to TEP unitholders of $6.5 million.

Distributions

TEGP's partnership agreement requires it to distribute available cash to Class A shareholders beginning with the quarter ending June 30, 2015. We expect that the amount of any distribution declared and paid for the second quarter of 2015 will be on a prorated basis for the period from the closing of the Offering on May 12, 2015 through June 30, 2015. Any distributions received by Tallgrass Equity from TEP and TEP GP related to periods prior to the closing of the Offering will be paid to TD and the Exchange Right Holders, as applicable.

Capital Requirements

The midstream energy business can be capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following:


•	maintenance capital expenditures, which 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. These expenditures typically include certain system integrity, compliance and safety improvements; and


•	expansion capital expenditures, which are cash expenditures to increase our operating income or operating capacity over the long term. Expansion capital expenditures include acquisitions or capital improvements (such as additions to or improvements on the capital assets owned, or acquisition or construction of new capital assets).

We expect to incur approximately $199 million for capital expenditures in 2015, of which approximately $149 million is expected for the construction of the lateral to the Pony Express System located in Northeast Colorado and remaining costs associated with completion of the construction of the Pony Express System, approximately $37 million is expected for other expansion projects, and approximately $13 million is expected for maintenance capital expenditures.

The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:



	Three Months Ended March 31,
	2015		2014
	(in thousands)
Maintenance capital expenditures	$	1,511	$	941
Expansion capital expenditures	80,996		261,711
Total capital expenditures incurred	$	82,507	$	262,652

Capital expenditures incurred represent capital expenditures paid and accrued during the period, inclusive of Pony Express capital expenditures paid by TD on behalf of Pony Express and settled via the cash management agreement. The increase in maintenance capital expenditures to $1.5 million for the three months ended March 31, 2015 from $0.9 million for the three months ended March 31, 2014 is primarily driven by increased maintenance capital expenditures in the Gas Transportation & Storage segment. 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 year to year and from quarter to quarter. The decrease in expansion capital expenditures to $81.0 million for the three months ended March 31, 2015 from $261.7 million for the three months ended March 31, 2014 is primarily driven by the significant spending on the Pony Express System prior to commencement of commercial operations in October 2014. Expansion capital expenditures of $81.0 million for the three months ended March 31, 2015 consisted primarily of spending on the Pony Express System lateral in Northeast Colorado.

In addition, we invested cash in unconsolidated affiliates of $1.8 million during the three months ended March 31, 2014 to fund our share of capital expansion projects. There were no investments in unconsolidated affiliates during the three months ended March 31, 2015.

We intend to make cash distributions to our Class A shareholders. Due to our cash distribution policy, we expect that we will distribute to our Class A shareholders most of the cash generated by our operations. We expect TEP to fund future capital expenditures with funds generated from its operations, borrowings under its Credit Agreement, the issuance of additional partnership units and/or the issuance of long-term debt. If these sources are not sufficient, TEP may reduce its discretionary spending.

Contractual Obligations

There have been no material changes in our contractual obligations as reported in the Prospectus.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The critical accounting policies and estimates used in the preparation of our condensed combined financial statements are set forth in our Prospectus and have not changed.

Item 3. 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 March 31, 2015 approximately 87% of our reserved processing capacity was subject to fee-based processing contracts, with the remaining 13% subject to percent of proceeds or keep whole processing contracts. We do not currently hedge the commodity exposure in our processing contracts and we do not expect to in the foreseeable future. Our Processing & Logistics segment comprised approximately 4% and 43% of our Operating Income for the three months ended March 31, 2015 and 2014, respectively.

We have a limited amount of direct commodity price exposure related to crude oil collected as part of our contractual pipeline loss allowance at Pony Express. We do not currently hedge this commodity exposure.

We also have a limited amount of direct commodity price exposure related to natural gas collected 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 a substantial majority of the gas we expect to collect during the current year for the purpose of hedging our commodity price exposures. We expect to continue these hedging activities for the foreseeable future. As of March 31, 2015, we had natural gas swaps outstanding with a notional volume of approximately 0.9 Bcf short, representing a portion of the natural gas that is expected to be sold by our Natural Gas Transportation and Logistics segment through the end of 2015. The fair value of these swaps was an asset of approximately $0.1 million at March 31, 2015.

We measure the risk of price changes in 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. We enter into derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, both 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. A hypothetical 10% increase in the natural gas price forward curve would result in a decrease of approximately $0.2 million in the net fair value of our derivative instruments for the quarter ended March 31, 2015 as a result of our hedging program. For the purpose of determining the change in fair value associated with the hypothetical natural gas price increase scenario, we have assumed a parallel shift in the forward curve through the end of 2015.

The Commodity Futures Trading Commission ("CFTC") has promulgated regulations to implement Dodd-Frank’s changes to the Commodity Exchange Act, including the definition of commodity-based swaps subject to those regulations. The CFTC regulations are intended to implement new reporting and record keeping requirements related to those swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate that most, if not all, of our swap transactions should qualify for an exemption to the clearing and exchange-execution requirements, we will still be subject to record keeping and reporting requirements. Other changes to the Commodity Exchange Act made as a result of the Dodd-Frank Act and the CFTC’s implementing regulations could significantly increase the cost of entering into new swaps.

Interest Rate Risk

As described in "Liquidity and Capital Resources Overview" above, TEP currently has an $850 million revolving credit facility. Borrowings under the revolving 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 was initially 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin was initially 2.00%. After June 25, 2014, the applicable margin ranges from 0.75% to 2.75%, based upon our total leverage ratio and whether we have elected the base rate or the reserve adjusted Eurodollar rate. We do not currently hedge the interest rate risk on our borrowings under the credit facility. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the debt by $0.1 million based on the debt obligations as of March 31, 2015.

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 a credit approval process which includes credit analysis, the establishment of credit limits and ongoing monitoring procedures. We may request letters of credit, cash collateral, prepayments, guarantees or bonds 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, firm, fee-based contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with approximately 70% of our revenues derived from customers who have investment grade credit ratings or are part of corporate families with investment grade credit ratings as of March 31, 2015.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a- 15(e) or Rule 15d- 15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Assessment of Internal Control over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act. Our first Annual Report on Form 10-K will not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to newly public companies. Our management will be required to provide an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2016.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Note 12 – Legal and Environmental Matters to the condensed combined financial statements included in Part I—Item 1.—Financial Statements of this Quarterly Report, which is incorporated here by reference.

Item 1A. Risk Factors

You should consider carefully the following risk factors, together with all of the other information included in this Quarterly Report, in your evaluation of an investment in our Class A shares. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations. In that case, we might not be able to pay or sustain our estimated annualized initial quarterly distribution on our Class A shares, the trading price of our Class A shares could decline and you could lose all or part of your investment. References to “us,” “we,” and “our” in this Item 1A refer to Tallgrass Energy GP, LP in its individual capacity.

Risks Inherent in an Investment in Us

Our only cash-generating assets are our interests in Tallgrass Equity and therefore our cash flow is entirely dependent upon the ability of TEP to make cash distributions to Tallgrass Equity, and the ability of Tallgrass Equity to make cash distributions to us.

We currently anticipate that the only source of our earnings and cash flow will be cash distributions from Tallgrass Equity, which will consist exclusively of cash distributions from TEP. The amount of cash that TEP will be able to distribute to its partners, including Tallgrass Equity, each quarter principally depends upon the amount of cash it generates from its business. For a description of certain factors that can cause fluctuations in the amount of cash that TEP generates from its business, please read the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” TEP may not have sufficient available cash each quarter to continue paying distributions at its current level or at all. If TEP reduces its per unit distribution, either because of reduced operating cash flow, higher expenses, capital requirements or otherwise, we will have less cash available for distribution to you and would likely be required to reduce our per share distribution to you. You should also be aware that the amount of cash TEP has available for distribution depends primarily upon

TEP’s distributable cash flow, including cash flow from the release of financial reserves as well as borrowings, not profitability, which will be affected by non-cash items. As a result, TEP may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.

Furthermore, Tallgrass Equity’s ability to distribute cash to us and our ability to distribute cash received from Tallgrass Equity to our Class A shareholders is limited by a number of factors, including:


•	Tallgrass Equity’s payment of costs and expenses associated with our, our general partner's, Holdings', and Tallgrass Equity’s respective operations, including expenses we incur as a result of being a public company, which costs and expenses are not subject to a limit pursuant to the Omnibus Agreement, dated May 12, 2015 (the “TEGP Omnibus Agreement”);


•	our payment of any income taxes;


•	interest expense and principal payments on any indebtedness incurred by TEP, Tallgrass Equity, TEP GP or us;


•	restrictions on distributions contained in Tallgrass Equity’s and TEP’s respective revolving credit facilities and any future debt agreements entered into by Tallgrass Equity, TEP, TEP GP or us;


•	reserves created by our general partner as necessary to permit Tallgrass Equity to make required capital contributions to TEP GP for it to maintain or attain up to a 2.0% general partner interest in TEP; and

•

reserves our general partner or TEP GP establish for the proper conduct of our, Tallgrass Equity’s or TEP’s business, including reserves to comply with applicable law or any agreement binding on us, our subsidiaries, Tallgrass Equity, Tallgrass Equity’s subsidiaries, TEP and TEP’s subsidiaries, which reserves are not subject to a limit pursuant to our partnership agreement, TEP’s partnership agreement or Tallgrass Equity’s limited liability company agreement.

A material increase in amounts paid or reserved with respect to any of these factors could restrict our ability to pay quarterly distributions to our Class A shareholders.

We may limit or modify the incentive distributions that Tallgrass Equity is entitled to receive through its ownership of TEP’s incentive distribution rights without the consent of our shareholders, which may reduce cash distributions to you.

We own a 30.35% membership interest in Tallgrass Equity, which, through its ownership of all the membership interests in TEP GP, is entitled to receive increasing percentages (up to a maximum of 48%, to the extent not modified) of any cash distributed by TEP in excess of $0.3048 per TEP common unit in any quarter. The majority of the cash flow we receive from Tallgrass Equity is expected to be derived from its ownership of these IDRs.

TEP, like other publicly traded partnerships, generally targets acquisitions or expansion capital projects that, after giving effect to related costs and expenses, would be expected to be accretive, meaning it would increase cash distributions per unit in future periods. Because Tallgrass Equity, through its ownership of TEP GP, currently participates in the IDRs at all levels, including the highest sharing level of 48%, it is harder for an acquisition or capital project to show accretion for the common unitholders of TEP than if the IDRs received less incremental cash flow. As a result, our general partner may cause TEP’s general partner to modify or reduce the IDRs to facilitate a particular acquisition or expansion capital project. Any such reduction or modification of IDRs will reduce the amount of cash that would have otherwise been distributed by Tallgrass Equity to us, which will in turn reduce the cash distributions we would otherwise be able to pay to you. Our shareholders are not able to vote on or otherwise prohibit TEP’s general partner from modifying the TEP IDRs, and our general partner may cause TEP’s general partner to reduce or modify the IDRs without considering the interests of the holders of our Class A shares. In addition, there can be no guarantee that the expected benefits of any IDR reduction or modification will be realized.

A reduction in TEP’s distributions will disproportionately affect the amount of cash distributions to which Tallgrass Equity is currently entitled.

Tallgrass Equity’s indirect ownership of TEP’s IDRs entitle it to receive increasing percentages, ranging from 13% up to 48%, to the extent not reduced or modified, of all cash distributed by TEP in excess of $0.3048 per TEP common unit per quarter. A decrease in the amount of distributions paid by TEP to less than $0.4313 per TEP common unit per quarter would reduce Tallgrass Equity’s percentage of incremental cash distributions in excess of $0.3048 per TEP common unit per quarter from 48% to as low as 13%. A decrease in the amount of distributions paid by TEP to less than $0.3048 per TEP common unit per quarter would result in Tallgrass Equity not receiving any incremental cash distributions with respect to the IDRs for such quarter. As a result, any such reduction in quarterly cash distributions from TEP would have the effect of disproportionately reducing the amount of distributions that Tallgrass Equity receives from TEP in respect of the IDRs as compared to cash distributions TEP makes with respect to its common units and general partner interest.

Our distributions to our Class A shareholders are not cumulative.

Our distributions to our Class A shareholders are not cumulative. Consequently, if distributions on our Class A shares are not paid with respect to any fiscal quarter then our Class A shareholders will not be entitled to receive that quarter’s payments in the future.

The amount of cash that we and TEP distribute each quarter may limit our ability to grow.

Because we distribute all of our available cash, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. In fact, because our cash flow is generated solely from distributions we receive from Tallgrass Equity, which are derived from Tallgrass Equity’s direct and indirect partnership interests in TEP, our growth is expected to initially be completely dependent upon TEP. The amount of distributions received by Tallgrass Equity is based on TEP’s per unit distribution paid on each TEP unit, the number of TEP units outstanding, and the number of TEP units owned by Tallgrass Equity. If we issue additional Class A shares, Tallgrass Equity incurs additional debt, we incur debt or we or Tallgrass Equity are required to pay taxes, the payment of distributions on those additional Class A shares or interest on that debt or payment of such taxes could increase the risk that we will be unable to maintain or increase our cash distribution levels.

Our rate of growth will be reduced to the extent we purchase additional equity interests from TEP, which will reduce the percentage of our cash flow that we receive from the IDRs.

Our business strategy includes, where appropriate, supporting the growth of TEP through the use of our capital resources, including by purchasing TEP common units or lending funds to TEP to finance acquisitions or internal growth projects. To the extent we purchase common units or securities not entitled to a current distribution from TEP, the rate of our distribution growth will be reduced, at least in the short term, because a smaller percentage of our cash distributions would come from our ownership of the IDRs, which increase at a faster rate than TEP’s common units and any similar equity interests TEP may issue in the future.

Restrictions in Tallgrass Equity’s and TEP’s respective revolving credit facilities could limit Tallgrass Equity’s ability to make distributions to us, thereby limiting our ability to make distributions to our Class A shareholders. Any credit facility we enter into in the future could pose similar restrictions that would further limit our ability to make distributions.

Tallgrass Equity’s and TEP’s respective revolving credit facilities contain various operating and financial restrictions and covenants. Tallgrass Equity’s and TEP’s respective ability to comply with these restrictions and covenants may be affected by events beyond their control, including prevailing economic, financial and industry conditions. If Tallgrass Equity or TEP is unable to comply with these restrictions and covenants, any indebtedness under these revolving credit facilities may become immediately due and payable and Tallgrass Equity’s and TEP’s respective lenders’ commitment to make further loans under these revolving credit facilities may terminate. Tallgrass Equity or TEP might not have, or be able to obtain, sufficient funds to make these accelerated payments.

Tallgrass Equity’s payment of principal and interest on indebtedness reduces its cash distributions to us, thereby reducing our cash available for distribution on our Class A shares. Tallgrass Equity’s revolving credit facility limits our ability to pay distributions to our Class A shareholders during an event of default or if an event of default would result from the distribution.

We may enter into a credit facility in the future that would impose similar restrictions to those discussed above. In addition, our payment of principal and interest on any indebtedness would reduce our cash available for distribution to our Class A shares.

For more information regarding Tallgrass Equity’s revolving credit facility, please read the section entitled “Notes to Condensed Combined Financial Statements-Subsequent Events-Tallgrass Equity Revolving Credit Facility.” For more information regarding TEP’s revolving credit facility, please see the section “-Risks Related to TEP’s Business-Restrictions in TEP’s revolving credit facility could adversely affect its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.”

Tallgrass Equity’s ownership in TEP’s IDRs, TEP’s common units and TEP’s general partner interest, are pledged under Tallgrass Equity’s revolving credit facility.

Tallgrass Equity’s direct ownership of the Acquired TEP Units and its indirect ownership of TEP’s IDRs and general partner interest are pledged as security under Tallgrass Equity’s revolving credit facility. Tallgrass Equity’s revolving credit facility contains customary and other events of default. Upon an event of default, the lenders under Tallgrass Equity’s revolving credit facility could foreclose on the IDRs in TEP, the Acquired TEP Units, and the general partner interest in TEP, which are the only assets from which our cash flows are derived. Additionally, this foreclosure would result in a change in control of TEP GP, which would constitute an immediate event of default under TEP’s credit facility. This would have a material adverse effect on our business, financial condition and results of operations.

Our shareholders do not vote in the election of our general partner’s directors. The Exchange Right Holders own a sufficient number of shares to allow them to prevent the removal of our general partner.

Our shareholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. The board of directors of our general partner, including our independent directors, is designated and elected by Holdings or its designees. Our shareholders do not have the ability to elect our general partner or the members of the board of directors of our general partner.

In addition, if our Class A shareholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. Our general partner may not be removed except by vote of the holders of at least 80% of our outstanding shares, voting together as a single class. The Exchange Right Holders own 69.95% of our outstanding shares. This ownership level enables the Exchange Right Holders to prevent our general partner’s removal.

As a result of these provisions, the price at which our shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.

If TEP’s unitholders remove TEP GP, TEP GP may be required to sell or exchange its IDRs and general partner interest and TEP GP would lose the ability to manage and control TEP.

TEP’s partnership agreement gives unitholders of TEP the right to remove TEP GP upon the affirmative vote of holders of 66 2/3% of TEP’s outstanding units. If TEP GP withdraws as general partner in compliance with TEP’s partnership agreement or is removed as general partner of TEP where cause (as defined in TEP’s partnership agreement) does not exist and a successor general partner is elected in accordance with TEP’s partnership agreement, TEP GP could elect to receive cash in exchange for its IDRs and general partner interest. If TEP GP withdraws in circumstances other than those described in the preceding sentence and a successor general partner is elected in accordance with TEP’s partnership agreement, the successor general partner will have the option to purchase the IDRs and general partner interest for their fair market value. If TEP GP or the successor general partner do not exercise their options, TEP GP’s interests would be converted into common units based on an independent valuation. In each case, TEP GP would also lose its ability to manage TEP.

In addition, if TEP GP is removed as general partner of TEP, we would face an increased risk of being deemed an investment company. Please read the section entitled “-If in the future we cease to manage and control TEP, we may be deemed to be an investment company under the Investment Company Act of 1940.”

Our general partner may cause us to issue additional Class A shares or other equity securities, including equity securities that are senior to our Class A shares, without your approval, which may adversely affect you.

Our general partner may cause us to issue an unlimited number of additional Class A shares, or other equity securities of equal rank with the Class A shares, without shareholder approval. In addition, we may issue an unlimited number of shares that are senior to our Class A shares in right of distribution, liquidation and voting. Except for Class A shares issued in connection with the exercise by any Exchange Right Holder of its right to exchange a Class B share for a Class A share (the "Exchange Right"), each of which will result in the cancellation of an equivalent number of Class B shares and therefore have no effect on the total number of outstanding shares, the issuance of additional Class A shares, or other equity securities of equal or senior rank, may have the following effects:


•	each shareholder’s proportionate ownership interest in us may decrease;


•	the amount of cash available for distribution on each Class A share may decrease;


•	the relative voting strength of each previously outstanding Class A share may be diminished;


•	the ratio of taxable income to distributions may increase; and


•	the market price of the Class A shares may decline.

You may not have limited liability if a court finds that shareholder action constitutes control of our business.

Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our shareholders (who hold limited partner interests despite the fact that we use the term “shareholder” in this Quarterly Report) as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the “control” of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.

Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a shareholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

If in the future we cease to manage and control TEP we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to indirectly manage and control TEP and are deemed to be an investment company under the Investment Company Act of 1940, we would have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict the ability of TEP GP, Tallgrass Equity, TEP and us to borrow funds or engage in other transactions involving leverage, require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of our Class A shares.

Our partnership agreement restricts the rights of shareholders owning 20% or more of our shares.

Our shareholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any shares held by a person or group that owns 20% or more of any class of shares then outstanding, other than our general partner, the Exchange Right Holders or their respective affiliates and persons who acquired such shares with the prior approval of our general partner’s board of directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our shareholders to call meetings or to acquire information about our operations, as well as other provisions limiting our shareholders’ ability to influence the manner or direction of our management. As a result, the price at which our Class A shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.

If TEP GP, which is owned by Tallgrass Equity, is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of TEP, its value, and, therefore, the value of our Class A shares, could decline.

TEP GP and its affiliates may make expenditures on behalf of TEP for which TEP GP will seek reimbursement from TEP. Under Delaware partnership law, TEP GP has unlimited liability for the obligations of TEP, such as its debts and environmental liabilities, except for those contractual obligations of TEP that are expressly made without recourse to the general partner. To the extent TEP GP incurs obligations on behalf of TEP, it is entitled to be reimbursed or indemnified by TEP. If TEP is unable or unwilling to reimburse or indemnify TEP GP, TEP GP may not be able to satisfy those liabilities or obligations, which would reduce TEP GP’s cash distributions to Tallgrass Equity and ultimately to us for the benefit of our Class A shareholders.

Our Class A shares and TEP’s common units may not trade in relation or proportion to one another.

Our Class A shares and TEP’s common units may not trade in simple relation or proportion to one another. Instead, while the trading prices of our Class A shares and TEP’s common units are likely to follow generally similar broad trends, the trading prices may diverge because, among other things:


•	TEP’s cash distributions to its common unitholders have a priority over distributions on its IDRs;


•	we participate in the distributions on the IDRs and general partner interest in TEP while TEP’s common unitholders do not;


•	we expect to pay federal income taxes in the future; and


•	we may pursue business opportunities separate and apart from TEP or any of its affiliates.

An increase in interest rates may cause the market price of our shares to decline.

Like all equity investments, an investment in our Class A shares is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partner interests. Reduced demand for our Class A shares resulting from investors seeking other more favorable investment opportunities may cause the trading price of our Class A shares to decline.

Future sales of our Class A shares in the public market, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, could reduce our Class A share price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

Subject to certain limitations and exceptions, the Exchange Right Holders may cause the exchange of their Tallgrass Equity units (together with a corresponding number of Class B shares) for Class A shares (on a one-for-one basis, subject to customary conversion rate adjustments for equity splits and reclassification and other similar transactions) and then sell those Class A shares. We may also issue additional Class A shares or convertible securities in subsequent public or private offerings.

We cannot predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that future issuances and sales of our Class A shares, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, will have on the market price of our Class A shares. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.

The underwriters of the Offering may waive or release parties to the lock-up agreements entered into in connection with the Offering, which could adversely affect the price of our Class A shares.

Certain of our affiliates, the Exchange Right Holders and the directors and officers of our general partner have entered into lock-up agreements with respect to any sale of their Class A shares, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the effective date of the registration statement filed with respect to the Offering. Citigroup Global Markets Inc. and Goldman, Sachs & Co., at any time and without notice, may release all or any portion of the Class A shares, subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then the applicable Class A shares will be available for sale into the public markets, which could cause the market price of our Class A shares to decline and impair our ability to raise capital.

Holdings has sole authority to elect the board of directors of our general partner.

Holdings has the ability to elect all of the members of our board of directors. In addition, Holdings is able to determine the outcome of all matters requiring shareholder approval, including certain mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our shareholders of an opportunity to receive a premium for their Class A shares as part of a sale of our company. The Exchange Right Holders currently own 100% of the voting interests in Holdings and entities and/or investment funds affiliated with (i) The Energy & Minerals Group, (ii) Kelso & Company and (iii) members of our and TEP’s management each have the right to designate two members of the board of managers of Holdings for so long as they maintain certain ownership percentages in Holdings. Holdings currently has a six person board of managers. Holdings continues to be able to strongly influence all matters requiring shareholder approval, regardless of whether or not shareholders believe that the transaction is in their own best interests.

A valuation allowance on our deferred tax asset could reduce our earnings.

A significant deferred tax asset was recorded as a result of certain reorganization transactions completed in connection with the Offering. GAAP requires that a valuation allowance must be established for deferred tax assets when it is more likely than not that they will not be realized. If we were to determine that a valuation allowance was appropriate for our deferred tax asset, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ equity and increase in balance sheet leverage as measured by debt to total capitalization.

The NYSE does not require a limited partnership like us or TEP to comply with certain of its corporate governance requirements.

Because we and TEP are limited partnerships, the New York Stock Exchange (the “NYSE”) does not require our general partner or TEP’s general partner to have a majority of independent directors on their respective board of directors. The NYSE also does not require our general partner or TEP’s general partner to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our shareholders and TEP’s unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. In addition, as limited partnerships, we and TEP are not required to seek shareholder or unitholder approval, as appropriate, for issuances of Class A shares or TEP common units, respectively, including issuances in excess of 20% of outstanding equity securities, or for issuances of equity to certain affiliates.

We may incur liability as a result of our ownership of TEP’s general partner.

Under Delaware law, a general partner of a limited partnership is generally liable for the debts and liabilities of the partnership for which it serves as general partner, subject to the terms of any indemnification agreements contained in the partnership agreement and except to the extent the partnership’s contracts are non-recourse to the general partner. As a result of our structure, we indirectly own and control the general partner of TEP. To the extent the indemnification provisions in TEP’s partnership agreement or non-recourse provisions in our contracts are not sufficient to protect TEP GP from such liability, we may in the future incur liabilities as a result of our indirect ownership of TEP’s general partner. Please read the section entitled “-Risks Related to Conflicts of Interest.”

For as long as we are an emerging growth company, we are not required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to accounting standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we are not required to, among other things, (1) 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(b) of the Sarbanes Oxley Act of 2002, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) 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, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise, (4) provide certain disclosure regarding executive compensation required of larger public companies or (5) hold unitholder advisory votes on executive compensation.

If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

We are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we are required to disclose material changes made to our internal controls and procedures on a quarterly basis, we are not required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we need to implement additional internal controls, reporting systems and procedures and may need to hire additional accounting, finance and legal staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2015, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2020 if we continue to maintain our emerging growth company status for a full five years. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A shares.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results will be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A shares.

Risks Related to Conflicts of Interest

Our existing organizational structure and the relationships among us, TEP, our respective general partners, Holdings, the owners of Holdings, including the Exchange Right Holders, and their affiliated entities present the potential for conflicts of interest. Moreover, additional conflicts of interest may arise in the future among us and the entities affiliated with any general partner or similar interests we acquire or among TEP and such entities.

Conflicts of interest may arise as a result of our organizational structure and the relationships among us, TEP, our respective general partners, TEGP, the owners of Holdings, including the Exchange Right Holders, and their affiliated entities.

Our partnership agreement defines the duties of our general partner (and, by extension, its officers and directors). Our general partner’s board of directors or its conflicts committee has authority on our behalf to resolve any conflict involving us and they have broad latitude to consider the interests of all parties to the conflict.

Conflicts of interest may arise between us and our shareholders, on the one hand, and our general partner and its direct and indirect owners, including Holdings and the Exchange Right Holders, and affiliated entities, on the other hand, or between us and our shareholders, on the one hand, and TEP and its unitholders, on the other hand. The resolution of these conflicts may not always be in our best interest or that of our shareholders.

The Exchange Right Holders own 100% of the voting interests in Holdings and hold a majority of the combined voting power of our Class A and Class B shares.

The Exchange Right Holders own 100% of the voting interests in Holdings and hold approximately 69.65% of the combined voting power of our Class A and Class B shares . Although each of the Exchange Right Holders are entitled to act separately in their own respective interests with respect to their ownership interest in Holdings and us, the Exchange Right Holders collectively have the ability to elect all of the members of Holdings’ board of managers, each of whom serves as a member of the board of directors of our general partner. So long as any of the Exchange Right Holders continue to own a significant amount of the voting interests in Holdings, they will continue to be able to strongly influence our management and affairs.

Holdings may have interests that conflict with holders of our Class A shares.

Holdings owns our general partner and may have conflicting interests with holders of Class A shares.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Holdings, on the other hand, concerning, among other things, a decision whether to modify or limit the IDRs in the future or potential competitive business activities or business opportunities. These conflicts of interest may not be resolved in our favor.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our Class A shares 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 replaces 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 shareholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the shareholders 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 shareholders. Examples of decisions that our general partner may make in its individual capacity include:


•	how to allocate business opportunities among us and its affiliates;


•	whether to exercise its limited call right;


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


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


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

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

By purchasing shares, you agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Our general partner’s affiliates and Holdings may compete with us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. The restrictions contained in our general partner’s limited liability company agreement are subject to a number of exceptions. For example, affiliates of our general partner, including Holdings, the Exchange Right Holders, and their respective affiliates, are not prohibited from engaging in other businesses or activities that might be in direct competition with us.

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

If at any time more than 80% of our outstanding shares (including Class A shares issuable upon the exchange of Class B shares) are owned by our general partner, Holdings or their respective affiliates, our general partner has the right (which it may assign to any of its affiliates, Holdings or us), but not the obligation, to acquire all, but not less than all, of the remaining Class A shares held by public shareholders at a price equal to the greater of (x) the highest cash price paid by our general partner, Holdings, or their respective affiliates for any shares purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those shares and (y) 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, you may be required to sell your Class A shares at an undesirable time or price and may not receive any return of or on your investment. You may also incur a tax liability upon a sale of your Class A shares.

Risks Related to TEP’s Business

TEP may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to its general partner and its affiliates, to enable it to pay the quarterly distribution at the current distribution level, or at all, to holders of its common units.

TEP may not have sufficient available cash from operating surplus each quarter to enable it to pay the quarterly distribution at the current distribution level, at the minimum quarterly distribution level, or at all. The amount of cash TEP can distribute on its units principally depends upon the amount of cash TEP generates from its operations, which will fluctuate from quarter to quarter based on, among other things:


•	the level of firm transportation and storage capacity sold, the volume of natural gas and crude oil TEP transports and the volume of natural gas TEP stores, processes and treats;


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


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


•	regulatory action affecting the supply of, or demand for, natural gas and crude oil, the rates TEP can charge on its assets, how TEP contracts for services, its existing contracts, its operating costs or its operating flexibility;


•	changes in the fees TEP charges for its services;


•	the effect of seasonal variations in temperature on the amount of natural gas and crude oil that TEP transports and the amount of natural gas that TEP stores, processes and treats;


•	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 its geographic markets;


•	the creditworthiness of its customers;


•	the level of its 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 or acts of terrorism;


•	outages in its pipeline systems or at its processing facilities;


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


•	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 TEP will have available for distribution depends on other factors, including:


•	the level and timing of capital expenditures TEP makes;


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


•	the cost of pursuing and completing acquisitions, if any;


•	its debt service requirements and other liabilities;


•	fluctuations in its working capital needs;


•	its ability to borrow funds and access capital markets;


•	restrictions contained in its debt agreements;


•	the amount of cash reserves established by its general partner; and


•	other business risks affecting its cash levels.

If TEP is not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, its financial condition, results of operation, cash flows and ability to make cash distributions to its unitholders will be adversely affected. With respect to its natural gas transportation and logistics segment, TEP has 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, its ability to make cash distributions to its unitholders may be materially impacted.

TEP transports, stores and processes a substantial majority of the natural gas and crude oil on its systems under long-term contracts with terms of various durations. For the year ended December 31, 2014, approximately 93% of its natural gas transportation and storage revenues were generated under firm transportation and storage contracts. As of December 31, 2014, the weighted average remaining life of its long-term (defined as more than one-year in duration) natural gas transportation contracts and natural gas storage contracts was approximately three years and seven years, respectively, the weighted average remaining life of its oil transportation contracts was approximately five years, and the weighted average remaining life of its natural gas processing contracts was approximately three years. As these contracts expire, TEP may be unable to obtain new contracts on terms similar to those of its existing contracts, or at all. If TEP is unable to promptly resell capacity from expiring contracts on equivalent terms, its revenues may decrease and its ability to make cash distributions to its unitholders may be materially impaired.

For example, over the past several years, a number of TEP’s natural gas transportation and storage customers have opted not to renew their contracts for service on the TIGT System. TEP believes 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 TEP’s areas of operations, as opposed to TEP’s 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, TIGT’s average firm contracted capacity decreased from 842 MMcf/d for the year ended December 31, 2010 to 639 MMcf/d for the year ended December 31, 2014 and transportation services revenue decreased from $143.4 million to $102.0 million over the same period, primarily due to the loss of revenue from the non-renewal of transportation contracts.

TEP also may be unable to maintain the long-term nature and economic structure of its 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 its potential customers may be generally unwilling to enter into long-term contracts. To the extent TEP is unable to renew or replace its existing contracts on terms that are favorable to it or successfully manage the long-term nature and economic structure of its contract profile over time, its revenues and cash flows could decline and its ability to make distributions to its 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, TEP may be subject to a loss of revenue if TEP is unable to promptly resell the capacity to another customer on substantially equivalent terms.

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


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


•	the macroeconomic factors affecting crude oil and natural gas gathering economics for its current and potential customers;


•	the balance of supply and demand for natural gas and crude oil, on a short-term, seasonal and long-term basis, in the markets it serves;


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


•	the effects of federal, state or local laws or regulations on the contracting practices of its customers.

As a result of the acquisition of an interest in Pony Express, TEP is engaged in crude oil transportation, which is a new line of business for TEP. TEP cannot provide assurance that its expansion into this line of business will succeed.

In September 2014, TEP acquired a 33.3% membership interest in Pony Express, which owns the Pony Express System, an approximately 698 mile crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma, with delivery points at Ponca City Refinery and Deeprock Development in Cushing. In March 2015, TEP acquired an additional 33.3% membership interest in Pony Express, resulting in TEP owning a 66.7% membership interest in Pony Express. In addition, upon completion of ongoing construction, the Pony Express System will also include an approximately 66-mile lateral in northeast Colorado that will commence in Weld County, Colorado and interconnect with the Pony Express System just east of Sterling, Colorado. The construction of the lateral in Northeast Colorado and its expected in-service date may be delayed, which could negatively impact its future financial performance and results of operations. Additionally, TEP shares joint tariffs with third-party pipelines delivering oil from the Bakken into Guernsey, Wyoming, and those pipelines are currently experiencing delays in their construction and expansion efforts, the continuance of which would further delay its ability to utilize the Pony Express System at full capacity, which in turn could negatively impact its financial performance and results of operations.

The ownership and operation of a crude oil pipeline is a new line of business for TEP, as its operations were previously focused on the transportation, storage and processing of natural gas. Operating a crude oil pipeline system requires different operating strategies and different managerial expertise than its current operations, and a crude oil pipeline system is subject to additional or different regulations. Failure to timely and successfully develop this new line of business in conjunction with its existing operations may have a material adverse effect on its business, financial condition and results of operations.

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

TEP’s ability to renew or replace its existing contracts at rates sufficient to maintain current revenues and current cash flows could be adversely affected by the activities of its competitors. Some of TEP’s competitors have greater financial, managerial and other resources than TEP does and control substantially more transportation, storage and processing capacity and/or crude oil transportation capacity than TEP does. In addition, some of TEP’s competitors have assets in closer proximity to natural gas and/or crude oil 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 TEP’s natural gas pipeline systems and transport gas to customers in the Rocky Mountain and Midwest regions of the United States. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil benchmarks (West Texas Intermediate Crude and Brent Crude). In addition, numerous other crude oil pipeline projects have been announced recently that would compete directly with TEP’s Pony Express crude oil pipeline system. TEP’s competitors may expand or construct new transportation, storage or processing systems that would create additional competition for the services TEP provides to its customers, or its 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 TEP’s areas of operation is particularly acute due to the nature of the processing industry and the attractive drilling profile of geographic areas served by its Midstream Facilities. Furthermore, Tallgrass Development and its affiliates are not limited in their ability to compete with TEP.

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

Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users, including electricity, coal and other liquid fuels. Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a reduction in demand for its services.

All of these competitive pressures could make it more difficult for TEP to renew its existing long-term, firm transportation, storage and processing contracts when they expire or to attract new customers as TEP seeks to expand its business, which could have a material adverse effect on its business, financial condition, results of operations and prospects. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas and crude oil in the markets TEP serves, 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 or crude oil.

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

TEP’s ability to grow depends, in part, on its ability to make acquisitions that increase its cash generated from operations on a per unit basis. The acquisition component of its strategy is based, in large part, on its expectation of ongoing divestitures of midstream energy assets by industry participants, including Tallgrass Development. Other than Tallgrass Development’s obligation to offer TEP certain assets (if Tallgrass Development decides to sell such assets) pursuant to the right of first offer under TEP's Omnibus Agreement, TEP has no contractual arrangement with Tallgrass Development that would require it to provide TEP with an opportunity to acquire midstream assets that it may sell. Accordingly, while TEP believes Tallgrass Development will be incentivized pursuant to its economic relationship with TEP to offer TEP opportunities to purchase midstream assets, there can be no assurance that any such offer will be made, and there can be no assurance TEP will reach agreement on the terms with respect to any acquisition opportunities offered to TEP by Tallgrass Development. Furthermore, many factors could impair its access to future midstream assets, including a change in control of Tallgrass Development or a transfer of the IDRs by its general partner to a third party. A material decrease in divestitures of midstream energy assets from Tallgrass Development or otherwise would limit its opportunities for future acquisitions and could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.

TEP’s future growth and ability to increase distributions will be limited if TEP is unable to make accretive acquisitions from Tallgrass Development or third parties because, among other reasons, (i) Tallgrass Development elects not to sell or contribute additional assets to TEP or to offer acquisition opportunities to TEP, (ii) TEP is unable to identify attractive third-party acquisition opportunities, (iii) TEP is unable to negotiate acceptable purchase contracts with Tallgrass Development or third parties, (iv) TEP is unable to obtain financing for these acquisitions on economically acceptable terms, (v) TEP is outbid by competitors or (vi) TEP is unable to obtain necessary governmental or third-party consents. Furthermore, even if TEP does make acquisitions that TEP believes 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 TEP acquires;


•	the assumption of unknown liabilities for which TEP is not indemnified or for which its 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 TEP’s distributable cash flow per unit, it could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.

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

In order to expand its asset base through acquisitions or capital projects, TEP may need to make expansion capital expenditures. If TEP does not make sufficient or effective expansion capital expenditures, TEP will be unable to expand its business operations and may be unable to maintain or raise the level of its quarterly cash distributions. TEP could be required to use cash from its operations or incur borrowings or sell additional common units or other limited partner interests in order to fund its expansion capital expenditures. Using cash from operations will reduce cash available for distribution to its common unitholders. TEP’s ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by its financial condition at the time of any such financing or offering as well as the covenants in its debt agreements,

general economic conditions and contingencies and uncertainties that are beyond its control. Even if TEP is successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit its ability to pay distributions to its common unitholders. In addition, incurring additional debt may significantly increase its 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 its ability to pay distributions at the then-current distribution rate.

TEP does not currently have any commitment with its general partner or other affiliates, including Tallgrass Development, to provide any direct or indirect financial assistance to TEP.

TEP is exposed to direct commodity price risk with respect to some of its processing revenues, and its exposure to direct commodity price risk may increase in the future.

TEP’s Processing & Logistics segment operates under three types of contracts, two of which directly expose its cash flows to increases and decreases in the price of natural gas and NGLs: percent of proceeds and keep whole processing contracts. As of December 31, 2014, approximately 13% of the reserved capacity in its Processing & Logistics segment was contracted under percent of proceeds or keep whole processing contracts. TEP does not currently hedge the commodity exposure inherent in these types of processing contracts due to the minimal impact to TEP’s overall financial condition and results of operations, and as a result, its revenues and results of operations are impacted by fluctuations in the prices of natural gas and NGLs.

Percent of proceeds processing contracts generally provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under keep whole processing contracts, TEP’s revenues and cash flows generally increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect its profitability. When natural gas prices are low relative to NGL prices, it is more profitable for TEP to process natural gas under keep whole arrangements. When natural gas prices are high relative to NGL prices, it is less profitable for TEP and its customers to process natural gas both because of the higher value of natural gas and 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, TEP may experience periods in which higher natural gas prices relative to NGL prices reduce its processing margins or reduce the volume of natural gas processed at some of its plants. In addition, NGL prices have historically been related to the market price of oil and as a result any significant changes in oil prices could also indirectly impact its operations. Indirectly, reduced commodity prices impact TEP through reduced exploration and production activity, which results in fewer opportunities for new business to offset potential volume declines. NGL and natural gas prices are impacted by changes in the supply and demand for NGLs and natural gas. In the latter half of 2014 and the beginning of 2015, natural gas prices have declined substantially and such declines may result in lower realizations on our percent of proceeds and keep whole processing contracts.

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

TEP’s natural gas transportation, storage and processing facilities and its oil transportation facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as Phillips 66, Deeprock Development, LLC and others. For example, a substantial majority of the NGLs TEP processes are transported on the Powder River pipeline owned by Phillips 66, and therefore, any downtime on this pipeline as a result of maintenance or force majeure would adversely affect TEP. For example, its Pony Express System connects to upstream joint tariff pipelines, including the Belle Fourche Pipeline owned by the True Companies (which also own and operate the Bridger Pipeline) and Hiland Double H Pipeline, which are responsible for delivering a substantial portion of the crude oil for transportation on the Pony Express System. Plus, nearly all of the crude oil TEP transports on the Pony Express System is stored in crude oil tanks located on or pumped over to downstream pipelines that interconnect through the Deeprock Development terminal facility in Cushing, Oklahoma. The continuing operation of such third- party pipelines, processing plants, crude oil terminal facilities and other midstream facilities is not within its control. These pipelines, plants and other midstream facilities may become unavailable to TEP for any number of reasons, including 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. For example, the operations of the Bridger Pipeline’s Poplar System are down indefinitely due to an apparent pipeline release on or about January 21, 2015. Bridger has declared a Force Majeure as a result of this event and has indicated that it does not have the capacity to make up volumes on other lines that directly or indirectly deliver crude oil into designated origin points on the Pony Express System or the Belle Fourche Pipeline. The largest committed shipper on the Pony Express System has also declared a force majeure as a result of this incident. TEP is currently evaluating the impact this will have on the operations of its Pony Express System, but it could result in decreased transportation throughput, increased costs and reduced revenues.

In addition, if the costs to TEP to access and transport on these third-party pipelines significantly increase, its 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 to store or transport crude oil, or if the volumes TEP transports or process do not meet the quality requirements of such pipelines or facilities, its revenues and its ability to make quarterly cash distributions to its unitholders could be adversely affected. For example, in May 2014 Phillips 66 notified TEP of an allegation that Tallgrass Midstream, LLC (“Tallgrass Midstream”) had been delivering NGLs to the Powder River NGL pipeline with methanol levels in excess of applicable tolerances. The Douglas plant was shut in completely for five days, and operated at approximately 50% of its processing capacity for another 10 days, as a result. Although Tallgrass Midstream was reimbursed by its upstream suppliers for substantially all of the off-spec fees imposed by Phillips 66 during 2014, Phillips 66 could also attempt to seek payment for any other costs (including those associated with overtime, testing, and shipping), penalties or damages allegedly incurred by them in connection with their processing, use or sale of the NGLs. If TEP is required to make additional substantial payments to Phillips 66 for costs, penalties or other damages and are unable to recover such amounts from upstream suppliers, its revenues and ability to make distributions to unitholders could be adversely affected.

The revenue in TEP’s Processing and Logistics segment largely depends on the amount of natural gas that its customers actually deliver to its natural gas processing plants.

As of December 31, 2014, approximately 87% of its reserved capacity at its Casper and Douglas natural gas processing plants was subject to fee-based processing contracts (the remaining 13% was subject to percent of proceeds or keep whole processing contracts). On these fee-based contracts, TEP’s revenue is largely tied to the amount of natural gas that its customers actually deliver its Casper and Douglas plants for processing. Unlike many pipeline transportation customers, TEP’s natural gas processing customers are not generally subject to “take or pay” obligations. Thus, if its natural gas processing customers do not produce natural gas and deliver that natural gas to its processing plants to be processed, revenue for its Processing and Logistics Segment will decline. If natural gas, crude oil or NGL prices decline, as has been the case over the latter half of 2014 and the first part of 2015, TEP’s customers may make less money from the production of natural gas, crude oil or NGLs than it costs them to produce it. If that happens, its customers may not continue to produce natural gas and its revenue will decline. In addition, the fees its customers pay to reserve capacity at its processing plants may not deter those customers from processing their natural gas volumes at other facilities, with whom they may have had prior arrangements or otherwise.

Any significant decrease in available supplies of natural gas or crude oil in TEP’s areas of operation, or redirection of existing natural gas or crude oil supplies to other markets, could adversely affect its business and operating results. If recent lower commodity prices for oil and gas are prolonged beyond our contract lives, we may experience lower throughput volumes and reduced cash flows.

TEP’s business is dependent on the continued availability of natural gas and crude oil production and reserves. Production from existing wells and natural gas and crude oil supply basins with access to its transportation, storage and processing facilities will naturally decline over time. The amount of natural gas and crude oil 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 and crude oil transported and natural gas stored and processed on its systems and cash flows associated therewith, its customers must continually obtain adequate supplies of natural gas and crude oil.

However, the development of additional natural gas and crude oil 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 and crude oil to be produced and delivered to its transportation, storage and processing facilities. In addition, low prices for natural gas and crude oil, 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 and crude oil supplies. A period of sustained price reductions in crude oil or refined products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. For example, in response to recent declines in crude oil prices, a number of producers in TEP’s areas of operation have announced significant reductions in their capital budget and drilling plans for 2015. In addition, production may fluctuate for other reasons, including, for example, in the case of crude oil, the decisions made by the members of the Organization of the Petroleum Exporting Countries (“OPEC”), regarding production controls. Furthermore, competition for natural gas and crude oil supplies to serve other markets could reduce the amount of natural gas and crude oil supply available for its customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas and crude oil transported on TEP’s systems and cash flows associated with its operations, its customers must compete with others to obtain adequate supplies of natural gas and crude oil.

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

TEP’s natural gas and crude oil 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 its business, financial condition, and results of operations.

TEP provides open-access interstate transportation service on its natural gas transportation systems pursuant to tariffs approved by the FERC. TEP’s natural gas transportation and storage operations are regulated by the FERC, under the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”), and the Energy Policy Act of 2005 (the “EPAct”). The TIGT System and the Trailblazer Pipeline each operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms and terms and conditions of service to its customers. The rates and terms of service on the Pony Express System are subject to regulation by the FERC under the Interstate Commerce Act (the “ICA”) and the Energy Policy Act of 1992. TEP provides interstate transportation service on the Pony Express System pursuant to tariffs on file with the FERC.

Generally, the FERC’s authority over natural gas facilities extends to:


•	rates, operating terms and conditions of service;


•	the form of tariffs governing service;


•	the types of services TEP may offer to its customers;


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


•	the acquisition, extension, disposition or abandonment of facilities;


•	creditworthiness and credit support requirements;


•	the maintenance of accounts and records;


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


•	depreciation and amortization policies; and


•	the initiation and discontinuation of services.

The FERC’s authority over crude oil pipelines is less broad, extending to:


•	rates, operating terms and conditions of service;


•	the form of tariffs governing service;


•	the maintenance of accounts and records;


•	relationships among affiliated transporters and shippers; and


•	depreciation and amortization policies.

Interstate natural gas pipelines subject to the jurisdiction of the FERC may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust, unreasonable, unduly discriminatory, or preferential. The maximum recourse rate that TEP may charge for its natural gas 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 its FERC-approved tariff.

Pursuant to the NGA, existing interstate natural gas 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. TEP currently holds authority from the FERC to charge and collect (i) “recourse rates” (i.e., the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its tariff); (ii) “discount rates” (i.e., rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline’s tariff); and (iii) “negotiated rates” (i.e., rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within or outside of the cost-based maximum and minimum rate levels set forth in the tariff, and which are individually filed

with the FERC for review and acceptance). When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) at which such capacity is sold are subject to regulatory approval and oversight. Regulators and customers on its natural gas pipeline systems have the right to protest or otherwise challenge the rates that TEP charges under a process prescribed by applicable regulations. The FERC may also initiate reviews of its rates. Customers on TEP’s natural gas pipeline systems may also dispute terms and conditions contained in its agreements, as well as the interpretation and application of its tariffs, among other things.

Rates for crude oil transportation service must be filed as a tariff with the FERC and are subject to applicable FERC regulation. The filed tariff rates include contract rates entered into with shippers willing to make long term commitments to the pipeline to support new pipeline capacity and “walk-up” rates available to uncommitted non-contract shippers. Crude oil pipelines typically must reserve at least ten percent of their capacity for walk-up shippers. Crude oil pipeline tariff rates may be adjusted, positively or negatively, on an annual basis through a FERC indexing procedure. A crude oil pipeline may also file new tariff rates at any time, subject to shipper contract restrictions and FERC regulatory procedures. The filing of any indexed rate increase or other rate increase may be protested and subjected to cost-of-service review by the FERC to determine whether the proposed new rate is just and reasonable.

Under the ICA, which applies to FERC-regulated liquids pipelines such as the Pony Express System, parties having standing may challenge new or existing rates and terms and conditions of service at any time. The FERC is authorized to suspend, subject to refund, the effectiveness of a protested rate for up to seven months while it determines if the protested rate is just and reasonable. TEP’s rates may be reduced and TEP may be required to issue refunds as a result of settlement or by an order of the FERC following a hearing finding that a protested rate is unjust and unreasonable. If the complaint is not resolved by settlement, the FERC may conduct a hearing and order the crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. TEP cannot guarantee that any new or existing rate on the Pony Express System would not be rejected or modified by the FERC, or subjected to refunds or reparations. While the FERC regulates rates and terms and conditions of service for transportation of crude oil in interstate commerce by pipeline, state agencies may also regulate facilities (including construction, acquisition, disposition, financing, and abandonment), rates, and terms and conditions of service for crude oil pipeline transportation in intrastate commerce. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on its business, financial condition and results of operations.

The Trailblazer Pipeline, one of TEP’s interstate natural gas pipelines, uses two types of fuel to power its compressors: (1) natural gas and (2) electric power. For the natural gas compression, customers are charged a gas retainage percentage as an in-kind reimbursement for fuel. For the electric compression, customers are charged a commodity rate for the electricity used at the pipeline’s stations. The volume of gas and cost of electric power are tracked and adjusted in annual periodic rate adjustment filings made pursuant to the tariff. Lost and unaccounted for gas is also tracked and adjusted in annual periodic rate adjustment filings. These costs were subject to the NGA Section 4 rate case initiated by the Trailblazer Pipeline and resolved by settlement as approved by the FERC in May 2014. On TIGT, TEP’s 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 its transportation and storage facilities. These Fuel Retention Factors were the subject of a Section 5 proceeding initiated by the FERC that TEP resolved with customers by a settlement approved by the FERC in September 2011.

The FERC’s jurisdiction over natural gas facilities 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. With some exceptions applicable to smaller projects, auxiliary facilities, and certain facility replacements, prior to commencing construction and/or operation of new or existing interstate natural gas transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction from, or file to amend its existing certificate with, 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 delay or refusal by an agency to issue authorizations or permits as requested for one or more of these projects may mean that they will be constructed in a manner or with capital requirements that TEP did not anticipate or that TEP will not be able to pursue these projects. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from these projects. The FERC does not regulate the construction, expansion, or abandonment of crude oil pipelines nor the initiation or discontinuation of services on those pipelines, provided that the action taken is not discriminatory or preferential among similarly situated shippers.

The FERC has the authority to conduct audits of regulated entities to assess compliance with FERC regulations and policies. The FERC also conducts audits to verify that the websites of interstate natural gas pipelines accurately provide information on the operations and availability of services on the pipeline. FERC regulations also require entities providing natural gas and crude oil transportation services to comply with uniform terms and conditions for service, as set forth in publicly available tariffs or, as it concerns natural gas facilities, agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are generally required to conform, in all material

respects, with the standard form of service agreements set forth in the natural gas pipeline’s FERC-approved tariff. The pipeline and a customer may choose to enter into a non-conforming service agreement so long as this agreement is 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, the FERC could reject the agreement or require TEP to modify the agreement, or alternatively require TEP to modify its tariff so that the non-conforming provisions are generally available to all customers. Agreements entered into with crude oil shippers are generally not available for public review, but the rates and terms and service provided to similarly situated shippers may not be unduly discriminatory or preferential.

The FERC has promulgated rules and policies covering many aspects of TEP’s natural gas pipeline business, including regulations that require TEP to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential, provide internet access to current information about its available pipeline capacity and other relevant transmission 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 prevent interstate natural gas pipelines from sharing customer information with marketing affiliates, and restrict how interstate natural gas pipelines share transportation with marketing affiliates. FERC regulations require that certain transmission function personnel of interstate natural gas pipelines function independently of personnel engaged in natural gas marketing functions. Crude oil pipelines subject to the ICA must comply with FERC regulations that require the pipeline to act as a common carrier and not engage in undue discrimination or preferential treatment with respect to shippers.

FERC policies also govern how interstate natural gas pipelines respond to interconnection requests from third party facilities, including other pipelines. Generally, an interstate natural gas pipeline must grant an interconnection request upon the satisfaction of several conditions. As a consequence, an interstate natural gas pipeline faces the risk that an interconnecting third party pipeline may pose a risk of additional competition to serve a particular market. Failure to comply with applicable provisions of the NGA, NGPA, EPAct 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, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of up to $1.0 million per day, per violation. Violations of the ICA, the Energy Policy Act of 1992, or regulations and orders promulgated by the FERC are also subject to administrative and criminal penalties and remedies, including forfeiture and individual liability.

In addition, new laws or regulations or different interpretations of existing laws or regulations applicable to TEP’s pipeline systems or midstream facilities could have a material adverse effect on its business, financial condition, results of operations and prospects. For example, 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. TEP may face challenges to its rates or terms of service in the future. Any successful challenge could materially adversely affect its future earnings and cash flows.

The rates of TEP’s regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.

TEP’s shippers or other interested stakeholders, such as state regulatory agencies, may challenge the rates or the terms and conditions of service applicable to its natural gas or crude oil pipeline tariffs, unless they have entered into agreements not to challenge such tariffs. The FERC has authority to investigate TEP’s rates and terms and conditions of service pursuant to NGA Section 5 for natural gas pipelines and the ICA for common carrier oil pipelines. TEP’s crude oil firm contract shippers have generally agreed not to complain or protest rates unless they are in conflict with their contracts. With regard to TEP’s natural gas pipelines, Trailblazer initiated on its own initiative, under NGA Section 4, a rate proceeding with the FERC on July 1, 2013 to implement a general rate increase to its recourse rates, initiate a rolled-in rate structure for expansion facilities certificated in 2001, and adopt miscellaneous other updates to its General Terms and Conditions in its tariff. On February 24, 2014, Trailblazer submitted to the FERC an uncontested offer of settlement and stipulation to resolve the proceeding by, among other things: (a) setting new maximum recourse rates based upon a “black box” cost of service of $21.1 million, (b) revising the charges and methods for recovery of fuel (natural gas and electric power used in providing service) costs, (c) providing for revenue sharing of certain interruptible and short-term firm service revenues with eligible maximum recourse rate firm service shippers, (d) establishing a rate moratorium until January 1, 2016, and (e) requiring a general rate case to be filed no later than January 1, 2019. The FERC accepted the settlement agreement by letter order on May 29, 2014. Per the terms of the settlement, Trailblazer is required to file a new general rate case by January 1, 2019, and no customer or participant who joined the settlement (defined in the settlement as a “Settling Party”) may file to change the settlement rates before January 1, 2016. TIGT is not subject to any current moratorium on complaints or protests regarding its rates or terms and conditions of service. The rates on TEP’s TIGT natural gas pipeline system were subject to a NGA Section 5 proceeding initiated by the FERC relating to TIGT’s Fuel Retention Factors, which generally are recovered by retaining a fixed percentage of natural gas throughput on TIGT’s natural gas transportation and storage facilities. TIGT 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. 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 natural gas pipeline system.

On TEP’s crude oil pipeline system, shippers may challenge new or existing rates at any time. As a result of settlement or by order of the FERC following hearing, its rates may be reduced. If a shipper files a complaint, and if the complaint is not resolved with that shipper, to the extent the FERC determines after hearing that TEP has collected payment on rates not previously found to be just and reasonable, TEP may be required to pay reparations to that shipper for up to two years prior to the date on which a complaint was filed. Regardless of the prospective just and reasonable rate, reparations may not be required below the last rates determined by the FERC to be just and reasonable. In other words, crude oil pipelines are not required to make reparations that refund revenues collected pursuant to rates previously determined to be just and reasonable.

Successful challenges to rates charged on TEP’s natural gas and crude oil pipeline systems, or to the terms and conditions of service on those systems, could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.

TEP is exposed to the creditworthiness and performance of its customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect its financial condition, cash flows, and operating results.

Although TEP attempts to assess the creditworthiness of its customers, suppliers and contract counterparties, there can be no assurance that its 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 its business, results of operations, financial condition and ability to make cash distributions to its unitholders. In addition, TEP’s long-term firm transportation and storage contracts obligate its customers to pay demand charges regardless of whether they transport or store natural gas or crude oil on its facilities, except for certain circumstances when TEP is unable to schedule the customer’s nomination for service. As a result, during the term of TEP’s long-term firm transportation and storage contracts and absent an event of force majeure, its revenues will generally depend on its customers’ financial condition and their ability to pay rather than upon the amount of natural gas or crude oil transported. Further, its contract counterparties may not perform or adhere to its existing or future contractual arrangements. Any material nonpayment or nonperformance by its contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could have an adverse impact on its business, results of operations, financial condition and ability to make cash distributions to its unitholders.

The procedures and policies TEP uses to manage its 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 its procedures and policies prove to be inadequate, its financial and operational results may be negatively impacted. Some of TEP’s counterparties may be highly leveraged or have limited financial resources and are subject to their own operating and regulatory risks. Even if its credit review and analysis mechanisms work properly, TEP may experience financial losses in its dealings with such parties. As seen with the recent decline in crude oil prices, prices for crude oil and natural gas are subject to large fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of other factors that are beyond its control. Such volatility in commodity prices might have an impact on many of its counterparties and their ability to borrow and obtain additional capital on attractive terms, which, in turn, could have a negative impact on their ability to meet their obligations to TEP and may also increase the magnitude of these obligations.

Any material nonpayment or nonperformance by its counterparties could require TEP 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.

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

One of the ways TEP may grow its business is by constructing additions or modifications to its existing facilities. TEP also may construct new facilities, either near its existing operations or in new areas. For example, in 2013 TEP completed an expansion of its Casper and Douglas plants to increase processing capacity and upgrade compression. Pony Express substantially completed its approximately 698-mile crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma during 2014 and is currently constructing an approximately 66-mile lateral in Northeast Colorado. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of which are beyond its control. These projects also involve numerous economic uncertainties, including the impact of inflation on project costs and the availability of required resources.

TEP may be unable to complete announced construction projects, including the potential expansion of the Pony Express System announced in its public filings, on schedule, at the budgeted cost, or at all, which could have a material adverse effect

on its business and results of operations. Moreover, TEP may not receive any material increase in operating cash flow from a project for some time. For instance, if TEP expands a pipeline or processing facility, the construction expenditures may occur over an extended period of time, yet TEP will not receive any material increases in cash flow until the project is completed and fully operational. In addition, its cash flow from a project may be delayed or may not meet its expectations. TEP’s 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.

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

TEP’s success depends on the supply and demand for natural gas and crude oil.

The success of its business is in many ways impacted by the supply and demand for natural gas and crude oil. For example, TEP’s business can be negatively impacted by sustained downturns in supply and demand for natural gas and crude oil in the markets that TEP serves, including reductions in its 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 domestic natural gas and crude oil supplies has been the significant growth in unconventional sources such as shale plays and the continued progression of hydraulic fracturing technology. The supply and demand for natural gas and crude oil, and therefore the future rate of growth of its business, depends on these and many other factors outside of its control, including, but not limited to:


•	adverse changes in general global economic conditions;


•	adverse changes in domestic regulations;


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


•	the price and availability of other forms of energy;


•	prices for natural gas, crude oil and NGLs;


•	decisions of the members of the OPEC regarding price and production controls;


•	increased costs to explore for, develop, produce, gather, process and transport natural gas or to transport crude oil;


•	weather conditions, seasonal trends and hurricane disruptions;


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


•	perceptions of customers on the availability and price volatility of its services and natural gas and crude oil prices, particularly customers’ perceptions on the volatility of natural gas and crude oil prices over the long term;


•	capacity and transportation service into, or out of, its markets; and


•	petrochemical demand for NGLs.

TEP is subject to numerous hazards and operational risks.

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


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


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


•	uncontrolled releases of crude oil, natural gas and other hydrocarbons;


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


•	outages at its processing facilities;


•	ruptures, fires, leaks and explosions; and


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

For example, failures occurred on two separate pipeline segments of the TIGT System during 2013; one in Kimball County, Nebraska on May 4, 2013 and one in Goshen County, Wyoming on June 13, 2013. The failures both resulted in the release of natural gas. Both lines were promptly brought back into service and neither failure caused any known injuries, fatalities, fires or evacuations. The costs to repair or replace the damaged section in Kimball County, Nebraska were not material. In February 2014, TEP communicated to PHMSA that TEP’s investigation of the pipeline involved in the Kimball County failure is complete. TEP has since placed this line into oil service and restored pressure to full maximum allowable operating pressure. TEP is currently working with PHMSA to develop a plan to close the Corrective Action Order received from PHMSA regarding the Goshen County failure and is evaluating the cost of anticipated remediation activities.

TEP has also had four minor incidents on the Pony Express System that TEP reported to PHMSA during final commissioning and since the line has been placed into commercial service. On August 31, 2014 a leak occurred at the Sterling Pump Station in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on Tallgrass property. On October 7, 2014 an overpressure event occurred upstream of the Lincoln Pump Station, which resulted in an overflow of the sump at the Lincoln Pump Station. On October 28, 2014, an overpressure situation occurred at the Cushing Terminal in Payne County, Oklahoma. On November 17, 2014, a leak occurred at the Sterling Pig Adapter in Logan County, Colorado due to a one inch valve that was inadvertently left in a partial open state. This incident resulted in a spill of approximately 119 bbls of crude oil. The Pony Express System is a newly commissioned crude oil pipeline and these integrity issues may continue for the foreseeable future.

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 TEP’s pipeline systems 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 TEP takes, events such as those described above could cause considerable harm to people or property, could result in loss of service available to customers, and could have a material adverse effect on its financial condition and results of operations and ability to make distributions to unitholders. In addition, maintenance, repair and remediation activities could result in service interruptions on segments of its systems or alter the operational profile of its systems. Potential impacts arising from these service interruptions or operational profile changes on segments of TEP’s systems could include, among others, limitations on its 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.

TEP could be required by regulatory authorities to test or undertake modifications to its systems, operations or both that could result in a material adverse impact on its business, financial condition and results of operations. For example, TEP received a Corrective Action Order from PHMSA on June 19, 2013 directing TEP to take certain investigative, testing and corrective measures with regard to the segment of the TIGT pipeline that failed on June 13, 2013. Such actions, including those required by PHMSA, could materially and adversely impact its ability to meet contractual obligations and retain customers, with a resulting material adverse impact on its business and results of operations, and could also limit or prevent its ability to make quarterly cash distributions to its unitholders. Some or all of its costs arising from these operational risks may not be recoverable under insurance, contractual indemnification or increases in rates charged to its customers.

TEP’s insurance coverage may not be adequate.

TEP is not insured or fully insured against all risks that could affect its business, including losses from environmental accidents. For example, TEP does not maintain business interruption insurance in the type and amount to cover all possible losses. In addition, TEP does not carry insurance for certain environmental exposures, including but not limited to potential environmental fines and penalties, certain business interruptions, 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 one or more of its insured assets, any insurance proceeds that TEP may receive in respect thereof may be insufficient to effect a restoration of such asset to the condition that existed prior to such loss. In addition, TEP is either not insured or not fully insured with respect to the legal proceedings described in Note 12 - Legal and Environmental Matters to the condensed combined financial statements included herein and may, depending upon the circumstances, need to pay self-insured retention amounts prior to having losses covered by the insurance providers. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on its business, financial condition, results of operations and cash flows.

Furthermore, TEP may not be able to maintain or obtain insurance of the type and amount it desires at reasonable rates, and it may elect to self-insure all or a portion of TEP’s risks of loss. 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. Any insurance coverage TEP does obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses.

TEP’s pipeline integrity program may impose significant costs and liabilities on TEP, while increased regulatory requirements relating to the integrity of its pipeline systems may require TEP to make additional capital and operating expenditures to comply with such requirements.

TEP is subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal requirements set by PHMSA for owners and operators of natural gas and crude oil pipelines 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 (“HCAs”).

Its 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 its pipeline systems and determine the pressures at which its pipeline systems can operate. The Pipeline Safety Act of 2011 enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002, or the Pipeline Safety Act of 2002, in a number of significant ways, including:


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


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


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


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

PHMSA published an advanced notice of proposed rule making 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 $0.1 million to $0.2 million per violation per day of violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing PHMSA’s enforcement process.

The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of the costs to comply with the rules are associated with pipeline integrity testing and the repairs found to be necessary. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs can have a significant impact on the costs to perform integrity testing and repairs. TEP is currently performing inspections on certain segments of the Trailblazer Pipeline that collectively total approximately 70-miles as part of TEP’s integrity management program to identify potential areas for replacement and repair. In connection with TEP’s acquisition of the Trailblazer Pipeline, Tallgrass Development agreed to contractually indemnify TEP for any out of pocket costs TEP incurs between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline’s disbonded Hi-Melt CTE coating. The contractual indemnity provided to TEP by Tallgrass Development is capped at $20 million and is subject to TEP’s first paying an annual $1.5 million deductible. TEP may not be able to recover any or all of such out of pocket costs that are not covered by this contractual indemnity from its customers unless and until TEP receives FERC approval to recover such costs through a general rate increase or other FERC-approved recovery mechanism. TEP plans to continue its pipeline integrity testing programs to assess and maintain the integrity of its existing and future pipelines as required by the United States Department of Transportation rules. The results of these tests could cause TEP to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines, which expenditures could be material.

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 (including hydrotesting) or modifying or replacing facilities to meet the demands of verifiable pressures, could significantly increase TEP’s costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for Maximum Allowable Operating Pressure (“MAOP”). TEP is currently undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could require TEP to operate at reduced pressures, which would reduce available capacity on its natural gas pipeline systems. These specific requirements do not currently apply to crude oil pipelines, but forthcoming

regulations implementing the Pipeline Safety Act of 2012 likely will expand the scope of regulation applicable to crude oil pipelines. 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 TEP currently anticipates. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on its business, financial position, results of operations and prospects. In addition, TEP may be subject to enforcement actions and penalties for failure to comply with pipeline regulations.

On August 29, 2012, PHMSA notified TIGT 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. TIGT 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 and a Final Order was received on October 30, 2013 that required TEP to modify its operating procedures to further address abnormal operating conditions. Failures occurred on two separate pipeline segments of the TIGT System during 2013; one in Kimball County, Nebraska on May 4, 2013 and one in Goshen County, Wyoming on June 13, 2013. The failures both resulted in the release of natural gas. Both lines were promptly brought back into service and neither failure caused any known injuries, fatalities, fires or evacuations. The costs to repair or replace the damaged section in Kimball County, Nebraska were not material. In February 2014, TEP communicated to PHMSA that TEP’s investigation of the pipeline involved in the Kimball County failure is complete. TEP has since placed this line into oil service and restored pressure to full maximum allowable operating pressure. TEP is currently working with PHMSA to develop a plan to close the Corrective Action Order received from PHMSA regarding the Goshen County failure and is evaluating the cost of anticipated remediation activities.

TEP has also had four minor incidents on the Pony Express System that TEP reported to PHMSA during final commissioning and since the line has been placed into commercial service. On August 31, 2014 a leak occurred at the Sterling Pump Station in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on Tallgrass property. On October 7, 2014 an overpressure event occurred upstream of the Lincoln Pump Station, which resulted in an overflow of the sump at the Lincoln Pump Station. On October 28, 2014, an overpressure situation occurred at the Cushing Terminal in Payne County, Oklahoma. On November 17, 2014, a leak occurred at the Sterling Pig Adapter in Logan County, Colorado due to a one-inch valve that was left in a partial open state. This incident resulted in a spill of approximately 119 bbls of crude oil. The Pony Express System is a newly commissioned crude oil pipeline and these integrity issues may continue for the foreseeable future. There can be no assurance as to the amount or timing of future expenditures required to remediate or resolve these issues, and actual future expenditures may be different from the amounts TEP currently anticipates. These integrity issues could have a material adverse effect on its business, financial position, results of operations and prospects.

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

Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and products produced from crude oil, are examples of GHGs. The United States Environmental Protection Agency (the “EPA”), has determined that the emission of GHGs present an endangerment to public health and the environment because emissions of such gases contribute to the warming of the Earth’s atmosphere and other climatic changes. Various laws and regulations exist, or are under development that seek to regulate the emission of such GHGs, including 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.

Based on these findings, the EPA began adopting and implementing regulations to restrict the emission of GHGs under existing provisions of the federal Clean Air Act (the “CAA”), starting in 2011. The EPA has 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 (“PSD”) and Title V programs. The EPA has indicated in rule makings that it may reduce the current regulatory thresholds for GHGs, making additional sources subject to PSD permitting requirements. On June 23, 2014, the United States Supreme Court ruled that portions of EPA’s GHG regulatory program violated the CAA. Specifically, the Supreme Court determined that GHGs cannot independently trigger PSD permitting requirements. However, the Court held that certain PSD permitting requirements may apply to GHG emissions if emissions of another regulated pollutant, like sulfur dioxide or particulate matter, trigger PSD permitting. Additionally, the Supreme Court ruled that the Tailoring Rule thresholds violated the CAA, while suggesting that EPA could promulgate “de minimis” thresholds for GHGs. On April 10, 2015, the United States Court of Appeals for the District of Columbia Circuit issued an order that vacates EPA’s regulations to the extent that they allow GHGs to independently trigger PSD permitting requirements and that requires EPA to revise its regulations accordingly and to assess the need for other regulatory changes to implement the Supreme Court’s decision.

Some of TEP’s facilities emit GHGs in excess of the 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, and to emit a regulated non-GHG pollutant in excess of statutory thresholds as well, would require TEP to obtain a PSD permit containing enforceable limits on GHG emissions. TEP notes that, as described above, the Supreme Court’s recent decision on EPA’s GHG rules creates some uncertainty regarding applicable regulatory thresholds for GHG emissions for facilities that trigger permitting requirements based on emissions of non-GHG pollutants.

Additional direct regulation of GHG emissions in TEP’s industry may be implemented under other CAA programs, including the New Source Performance Standards (“ 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 TEP’s operations, the EPA may propose to regulate additional sources under the NSPS program. For example, the EPA has proposed a rule that it calls the “Clean Power Plan” to compel state governments to reduce GHG emissions from sources within their jurisdictions. 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. 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 requires reporting of GHG emissions by regulated facilities to the EPA on an annual basis. Some of TEP’s 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, TEP could be required to purchase and surrender emission allowances and its customers may find it less attractive to produce, own, ship or have natural gas or crude oil processed or refined.

Because TEP’s operations, including its compressor stations and processing facilities, emit various types of GHGs, primarily methane and carbon dioxide, new legislation or regulation could increase its costs related to operating and maintaining its facilities, and could delay future permitting. Depending on the particular new law, regulation or program adopted, TEP could be required to incur capital expenditures for installation of new emission controls on its compressor stations and processing facilities, acquire and surrender allowances for its GHG emissions, pay taxes related to its GHG emissions and administer and manage a GHG emissions program. TEP is not able at this time to estimate such increased costs; however, they could be significant. While TEP may be able to include some or all of such increased costs in the rates charged by its pipelines, such recovery of costs is uncertain in all cases and may depend on events beyond its control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations.

Similarly, while TEP may be able to recover some or all of such increased costs in the rates charged by its processing facilities, such recovery of costs is uncertain and may depend on the terms of its contracts with its customers. Any of the foregoing could have a material adverse effect on its 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 its 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 its services by making natural gas and crude oil products less desirable than competing sources of energy.

TEP’s operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose it to significant costs, liabilities and expenditures that could exceed its current expectations.

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


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


•	Clean Water Act (“CWA”) and analogous state laws, which regulate discharge of pollutants (Section 402) or fill material (Section 404) from TEP’s facilities to state and federal waters, including wetlands;


•	Comprehensive Environmental Response, Compensation, and Liability Act (“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 TEP or locations to which TEP has sent wastes for disposal;


•	Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from TEP’s facilities;


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


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

•

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


•	Endangered Species Act (“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;


•	Bald and Golden Eagle Protection Act (“BGEPA”) prohibits anyone, without a permit issued by the Secretary of the Interior, from “taking” bald or golden eagles, including their parts, nests, or eggs. The Act defines “take” as “pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, molest or disturb;”


•	The Oil Pollution Act (“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; and


•	National Historic Preservation Act (“NHPA”) and analogous state laws, which is intended to preserve and protect historical and archeological sites.

Various governmental authorities, including but not limited to the EPA, the U.S. Department of the Interior, the U.S. Department of Homeland Security, and analogous Federal, 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 TEP’s operations, and delays in granting permits.

There is inherent risk of the incurrence of environmental costs and liabilities in TEP’s business, some of which may be material, due to its handling of the products it transports, processes and stores, air emissions related to its 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 oil, natural gas and wastes on, under, or from TEP’s properties and facilities. TEP is currently conducting remediation at several sites to address contamination. For 2014, TEP spent approximately $270,000 and for 2015 has budgeted approximately $691,000 for these ongoing environmental remediation projects. Private parties, including but not limited to the owners of properties through which TEP’s pipelines pass and facilities where its 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 its operations. Some sites at which TEP operates 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 its compliance costs and the cost of any remediation that may become necessary. TEP’s insurance does not cover all environmental risks and costs and may not provide sufficient coverage if an environmental claim is made against TEP.

In June 2013, the EPA extended its National Enforcement Initiatives, enforcement priorities list, including an initiative related to Energy Extraction Activities, for 2014 through 2016. TEP 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 and crude oil that TEP transports and/or processes could decline and its results of operations could be materially adversely affected.

TEP’s 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, TEP might not be able to obtain or maintain from time to time all required environmental regulatory approvals for its 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 TEP fails to obtain and comply with them, the operation or construction of its facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to its business, financial condition, results of operations and cash flows.

TEP is also generally responsible for all liabilities associated with the environmental condition of its 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, TEP could acquire, or be required to provide indemnification against, environmental liabilities that could expose TEP to material losses, which may not be covered by insurance. In addition, the steps TEP could be required to take to bring certain facilities into compliance could be prohibitively expensive, and TEP might be required to shut down, divest or alter the operation of those facilities, which might cause TEP to incur losses. For example, in August 2011, the EPA and the Wyoming Department of Environmental Quality conducted an inspection of the Leak Detection and Repair Program (“LDAR”) at the Casper Plant in Wyoming. In September 2011, Tallgrass Midstream 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 CAA. Tallgrass Midstream received a letter from the U.S. EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the U.S. EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including attempted resolution of more recently identified LDAR issues. TEP is not currently able to estimate the costs that may be associated with a settlement or other resolution of this matter, which could be substantial.

TEP has agreed to a number of conditions in its 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 TEP currently operates, and would operate if its facilities are extended or expanded, or if TEP constructs new facilities, and TEP is unable to predict the effect that any such measures would have on its business, financial position, results of operations or prospects.

Further, such existing laws and regulations may be revised or new laws or regulations may be adopted or become applicable to TEP. 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 TEP. Also, EPA and the U.S. Army Corps of Engineers recently issued a final rule to clarify the term “waters of the United States” as regards federal jurisdiction under the CWA. Many interested parties believe that the rule will expand federal jurisdiction under the CWA. 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 TEP currently anticipates. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from its customers, could have a material adverse effect on its business, financial position, results of operations and prospects.

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

A portion of TEP’s customers’ oil and 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 production. Hydraulic fracturing is currently exempt from federal regulation pursuant to the federal Safe Drinking Water Act (“SDWA”) (except when the fracturing fluids or propping agents contain diesel fuels, and EPA released guidance on the permitting of wells that use diesel fuels during hydraulic fracturing activities in February 2014), 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 was expected to be available for public comment and peer review in 2014, although it has not yet been released. Reports prepared by the U.S. Department of Energy’s Shale Gas Subcommittee could also lead to further restrictions on hydraulic fracturing. In addition, EPA has announced its intention to propose regulations under the CWA regarding wastewater discharges from hydraulic fracturing and other gas production and, on May 9, 2014, EPA issued an Advance Notice of Proposed Rulemaking under Section 8 of the Toxic Substances Control Act (the “TSCA”) to seek public comment on hydraulic fracturing chemical information that could be reported and disclosed under TSCA. Most recently, the federal Bureau of Land Management (the “BLM”) issued a final rule on March 20, 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands including, among other things, submission of various detailed notices, plans and other information relating to the fracturing activities that are subject to BLM pre-approval, implementation of measures designed to protect usable water from fracturing activities; and public disclosure of chemicals used in hydraulic fracturing fluids through the FracFocus website. The BLM rule has an expected effective date of June 2015 but is currently subject to one or more legal challenges that seek to block implementation of the rule.

Apart from federal legislation and EPA regulations, other federal agencies and states have proposed or adopted legislation or regulations restricting hydraulic fracturing. On May 24, 2013, the U.S. Department of Interior published a proposed rule in the Federal Register that includes disclosure requirements and other mandates for hydraulic fracturing on federal lands. Some states have already imposed disclosure requirements associated with hydraulic fracturing, including states in which TEP operates.

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. For example, Wyoming, Kansas, Colorado, North Dakota, Montana, and Oklahoma have imposed regulations regarding disclosure of information regarding chemicals in well stimulation operations. The Governor of Colorado recently announced that he would form a task force to consider additional regulation of oil and gas activities, including hydraulic fracturing. Although TEP does not have operations in the State of New York, the Governor of New York announced in December 2014 that hydraulic fracturing would be banned in that state. Many local governments have restricted or banned hydraulic fracturing within their jurisdictions, including some in states in which TEP operates.

State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. However, some state regulatory agencies have modified their regulations to account for induced seismicity. For example, the Texas Railroad Commission (the “TRC”) rules allow the TRC to modify, suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity.

TEP 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 crude oil and natural gas that TEP transports may decline and its results of operations could be materially and adversely affected. Further, additional state legislation or regulation may impact any potential expansion plans by delaying implementation or requiring additional approvals or modifications to expansion plans.

In addition, the EPA approved final rules that establish new air emission controls for oil and natural gas production, pipelines and processing operations that 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 January 1, 2015. As of 2015, 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 (“VOCs”) 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 TEP’s and TEP’s 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 rule and has since reconsidered certain aspects of the rule. The case is currently in abeyance and EPA may reconsider other 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 issued rules cannot be predicted. Additionally, EPA has signaled its intent to regulate emissions of methane and volatile organic compounds from the oil and gas sector as a measure to implement President Obama’s Climate Action Plan. EPA has released a series of white papers addressing methane reductions from the oil and gas sector. On January 14, 2015, the Obama Administration announced that EPA will propose a rule in the summer of 2015 to set standards for methane and VOC emissions from new and modified sources in the oil and gas sector, including transmission. A final rule is expected in 2016. The Obama Administration’s announcement also stated that other federal agencies, including PHMSA and the Department of Energy, will impose new or more stringent regulations on the oil and gas sector that will have the effect of reducing methane emissions. 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 TEP is 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 TEP. Compliance with such rules may also make it more difficult for TEP’s customers to operate, thereby reducing the volume of natural gas or crude oil transported through its pipelines or the volumes of natural gas it processes, which may adversely affect its business. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for TEP and its customers, which could have a material adverse effect on its business.

Potential increased costs as a result of EPA regulation of internal combustion engines could be significant.

Internal combustion engines used in TEP’s 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. TEP anticipates modest future cost increases for compliance with these rules, as activities such as routine major engine overhauls or facility permitting changes could subject existing engines to rule requirements which were not previously applicable.

TEP is exposed to costs associated with lost and unaccounted for volumes.

A certain amount of natural gas and crude oil may be lost or unaccounted for in normal operations in connection with their transportation across a pipeline system. Under its tariffs and contractual arrangements with its customers TEP is entitled to retain a specified volume of natural gas and crude oil in order to compensate TEP for such lost and unaccounted for volumes, as well as the natural gas used to run its natural gas compressor stations, which TEP refers to collectively as fuel usage. TEP’s pipeline tariffs, other than the Trailblazer Pipeline’s, do not contain fuel usage true-up mechanisms. The use of fuel (natural gas, electric and lost and unaccounted for gas) trackers on the Trailblazer Pipeline, while minimizing risk over time, nevertheless leaves the Trailblazer Pipeline exposed to the possibility of under- or over-collections on an annual basis. The level of lost and unaccounted for volumes, and natural gas fuel usage, on TEP’s pipeline systems may exceed the natural gas and crude oil volumes retained from its customers as compensation for its lost and unaccounted for volumes, and fuel usage, pursuant to its tariffs and contractual agreements, and it may be necessary to purchase natural gas or crude oil in the market to make up for the difference, which exposes TEP to commodity price risk. Future exposure to the volatility of natural gas and crude oil prices as a result of lost and unaccounted for volume imbalances could have a material adverse effect on its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.

TEP has certain long term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if its costs increase, and TEP has certain crude oil transportation contracts that contain favored nation provisions that could require rate decreases if other similarly situated shippers are paying lower rates. As a result, its costs could exceed its revenues.

Approximately one-third of TEP’s contracted natural gas transportation firm capacity is provided under long-term, fixed price “negotiated rate” contracts that are not subject to adjustment, even if its cost to perform such services exceeds the revenues received from such contracts, and, as a result, its costs could exceed its revenues received under such contracts. It is possible that costs to perform services under TEP’s “negotiated rate” contracts will exceed the negotiated rates. If this occurs, it could decrease the cash flow realized by TEP’s assets and, therefore, the cash it has available for distributions to its 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 natural gas pipeline and the shipper for the contract term and does not necessarily 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. 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, may be recoverable from other shippers in certain limited circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case.

Approximately 90% of TEP’s crude oil pipeline capacity is provided to committed shippers under long-term “Throughput and Deficiency Agreements” (“TDAs”). Rates under the TDAs are typically subject to increase only through the FERC annual index process. TEP generally cannot file for rate increases outside of the annual FERC adjustment process with respect to committed shippers who have signed TDAs. Some of the TDAs also contain favored nations provisions which could result in lower rates being charged to certain committed shippers to ensure that the rates such shippers are paying are no greater than ninety to one hundred percent of the rates being charged to other similarly situated shippers for similar service at similar volumes and terms.

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

Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for TEP’s 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 its services and the rates it is 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 TEP’s storage services and the prices that it 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 its business, financial condition, results of operations and ability to make distributions.

Certain portions of TEP’s 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 its facilities that could have a material adverse effect on its business and results of operations.

Significant portions of TEP’s transportation, storage and processing systems have been in service for several decades. The age and condition of its facilities could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce its revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of its facilities could adversely affect its business and results of operations and its ability to make cash distributions to its unitholders.

Restrictions in TEP’s revolving credit facility could adversely affect its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.

TEP’s revolving credit facility limits its ability to, among other things:


•	incur or guarantee additional debt;


•	redeem or repurchase units or make distributions under certain circumstances;


•	make certain investments and acquisitions;


•	incur certain liens or permit them to exist;


•	enter into certain types of transactions with affiliates;


•	merge or consolidate with another company; and


•	transfer, sell or otherwise dispose of assets.

TEP’s revolving credit facility also contains covenants requiring it to maintain certain financial ratios. Its ability to meet those financial ratios and tests can be affected by events beyond its control, and TEP cannot assure us that it will meet those ratios and tests.

The provisions of TEP’s revolving credit facility may affect its ability to obtain future financing and pursue attractive business opportunities and its flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of its revolving credit facility, including a failure to meet the required financial ratios and tests, could result in a default or an event of default that could enable its lenders to restrict or prohibit its ability to make quarterly distributions and declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of its debt is accelerated, its assets may be insufficient to repay such debt in full, and its unitholders could experience a partial or total loss of their investment.

All of the membership interests in TEP GP that are owned by Tallgrass Equity are pledged as security under Tallgrass Equity’s credit facility. Upon an event of default under that credit facility, a change in control of TEP could result.

Tallgrass Equity pledged all of the equity interests it holds in TEP GP as collateral under its new revolving credit facility, which contains customary and other events of default. Upon an event of default, the lenders under Tallgrass Equity’s credit facility could foreclose on its collateral, which could result in a change in control of TEP GP and a change in indirect ownership of the general partner interests and incentive distribution rights in TEP held by TEP GP. Such change in control would constitute an immediate event of default under TEP’s credit facility, which would permit the lenders under TEP’s credit facility to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable.

TEP’s future debt levels may limit its flexibility to obtain financing and to pursue other business opportunities.

TEP’s level of debt could have important consequences to TEP, including the following:


•	its 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;


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


•	it may be more vulnerable to competitive pressures or a downturn in its business or the economy generally; and


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

Its ability to service its debt depends upon, among other things, its future financial and operating performance, which is affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond its control. If its operating results are not sufficient to service its current or future indebtedness, TEP will be forced to take actions such as reducing distributions, reducing or delaying its business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. TEP 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 TEP’s storage capacity, its unit price, its ability to issue equity or incur debt for acquisitions or other purposes and its ability to make cash distributions at its intended levels.

There is a financing cost for TEP’s customers to store natural gas in its storage facilities. That financing cost is impacted by the cost of capital or interest rate incurred by the customer in addition to the commodity cost of the natural gas in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas for future sale. As a result, a significant increase in interest rates could adversely affect the demand for its 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 its financing costs to increase accordingly. As with other yield-oriented securities, its unit price is impacted by the level of its 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 TEP’s units, and a rising interest rate environment could have an adverse impact on its unit price, its ability to issue equity or incur debt for acquisitions or other purposes and its ability to make cash distributions at its intended levels.

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

TEP’s 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 its services and increased difficulty in collecting amounts owed to TEP by its customers which could reduce its access to credit markets, raise the cost of such access or require TEP to provide additional collateral to its counterparties. TEP’s ability to access available capacity under its revolving credit facility could be impaired if one or more of its lenders fails to honor its contractual obligation to lend to TEP. If financing is not available when needed, or is available only on unfavorable terms, TEP may be unable to implement its business plans or otherwise take advantage of business opportunities or respond to competitive pressures.

The amount of cash TEP has available for distribution to unitholders depends primarily on its cash flow rather than on its profitability, which may prevent it from making distributions, even during periods in which TEP records net income.

The amount of cash TEP has available for distribution depends primarily upon its cash flow and not solely on profitability, which is affected by non-cash items. As a result, TEP may make cash distributions during periods when its records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.

The lack of diversification of TEP’s assets and geographic locations could adversely affect its ability to make distributions to its common unitholders.

TEP relies primarily on revenues generated from transportation, storage and processing systems that it owns, which are primarily located in the Rocky Mountain and Midwest regions of the United States. Due to its lack of diversification in assets and geographic location, an adverse development in these businesses or its areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for crude oil or natural gas, could have a significantly greater impact on its results of operations and cash available for distribution to its common unitholders than if TEP maintained more diverse assets and locations.

TEP does not own most of the land on which its natural gas and crude oil pipeline systems and Midstream Facilities are located, which could disrupt its operations and subject it to increased costs.

TEP does not own most of the land on which its pipeline systems and Midstream Facilities have been constructed, and TEP is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if TEP does not have valid rights-of-way, if such rights-of-way lapse or terminate or if its 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, TEP occasionally obtains the right to construct and operate pipelines on other owners’ land for a specific period of time. If TEP was to be unsuccessful in renegotiating rights-of-way, it might incur increased costs to maintain its pipeline systems, which could have a material adverse effect on its business, results of operations, financial condition and ability to make distributions to its unitholders. In addition, TEP is subject to the possibility of increased costs under its rental agreements with landowners, primarily through rental increases and renewals of expired agreements.

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

TEP’s interstate natural gas pipeline systems have federal eminent domain authority. Whether TEP has the power of eminent domain for the Pony Express crude oil pipeline varies from state to state, depending upon the laws of the particular state. Regardless, TEP 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 TEP, 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. TEP’s inability to exercise the power of eminent domain could negatively affect its business if TEP were to lose the right to use or occupy the property on which its crude oil or natural gas pipeline systems are located.

TEP’s operations are dependent on its rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.

Performance of its operations requires that TEP obtain and maintain numerous environmental and land use permits and other approvals authorizing its 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 its ability to initiate or continue operations at the affected location or facility. Expansion of its existing operations is also predicated on securing the necessary environmental or land use permits and other approvals, which TEP 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, TEP 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 TEP’s control. The denial of a permit or other approval essential to its operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impair or prevent its 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 TEP’s 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 TEP’s operations (including its ability to store, transport or process natural gas or crude oil or the pace of storing, transporting or processing natural gas or crude oil), its cost structure or its customers’ ability to use its services. Such current or future regulations could have a material adverse effect on its business and TEP may not be able to obtain or renew permits or other approvals in the future.

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

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

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

Upon the completion of its initial public offering, TEP became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. Effective internal controls are necessary for TEP to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. TEP’s efforts to develop and maintain its internal controls may not be successful, and TEP may be unable to maintain effective controls over its financial processes and reporting in the future or to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which TEP refers to as Section 404. For example, Section 404 requires TEP, among other things, to annually review and report on, and its independent registered public accounting firm to attest to, the effectiveness of its internal controls over financial reporting (except for the requirement for an auditor’s attestation report, as described below). Any failure to develop, implement or maintain effective internal controls or to improve TEP’s internal controls could harm its operating results or cause it to fail to meet its reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, TEP can provide no assurance as to its, or its independent registered public accounting firm’s, conclusions about the effectiveness of its internal controls, and TEP may incur significant costs in its efforts to comply with Section 404. Ineffective internal controls will subject TEP to regulatory scrutiny and a loss of confidence in TEP’s reported financial information, which could have an adverse effect on its business and would likely have a negative effect on the trading price of its common units.

For as long as TEP is an emerging growth company, TEP 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 JOBS Act. For as long as TEP remains an “emerging growth company” as defined in the JOBS Act, TEP intends to continue taking 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 its system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations

regarding executive compensation in its periodic reports. TEP will remain an emerging growth company for up to five full fiscal years, although TEP will lose that status sooner if it has more than $1.0 billion of revenues in a fiscal year, has more than $700 million in market value of its limited partner interests held by non-affiliates on the last business day of the most recently completed second fiscal quarter, or issues more than $1.0 billion of non-convertible debt over a three-year period.

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

TEP’s election to take advantage of the JOBS Act extended accounting transition period may make its financial statements more difficult to compare to other public companies.

Pursuant to the JOBS Act, as an “emerging growth company,” TEP 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 PCAOB or the SEC. TEP has 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, TEP can, for so long as TEP is an “emerging growth company,” adopt the standard for private companies. This may make comparison of its 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 TEP’s use of different accounting standards.

The outcome of future rate cases will determine the amount of income taxes that TEP 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 TEP’s revenues, earnings and cash flows.

TEP’s business could be negatively impacted by security threats, including cyber security threats, and related disruptions.

TEP relies on its information technology infrastructure to process, transmit and store electronic information, including information it uses to safely operate its assets. TEP may face cyber security and other security threats to its information technology infrastructure, which could include threats to its operational and safety systems that operate its pipelines, plants and assets. TEP could face unlawful attempts to gain access to its information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of its current information technology infrastructure and software assets and its ability to maintain and upgrade such assets could affect its ability to resist cyber security threats. TEP could also face attempts to gain access to information related to its 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.”

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

If TEP is unable to protect its information and telecommunication systems against disruptions or failures, its operations could be disrupted.

TEP relies extensively on computer systems to process transactions, maintain information and manage its business. Disruptions in the availability of its computer systems could impact its ability to service its customers and adversely affect its sales and results of operations. TEP is dependent on internal and third party information technology networks and systems, including the Internet and wireless communications, to process, transmit and store electronic information. Its computer systems are subject to damage or interruption due to system replacements, implementations and conversions, power outages, computer or telecommunication failures, computer viruses, security breaches, catastrophic events such as fires, tornadoes, snowstorms and floods and usage errors by its employees. If TEP’s computer systems are damaged or cease to function properly, it may have to make a significant investment to fix or replace them, and TEP may have interruptions in its ability to service its customers. Although TEP attempts to eliminate or reduce these risks by using redundant systems, this disruption caused by the unavailability of its computer systems could nevertheless significantly disrupt its operations or may result in financial damage or loss due to, among other things, lost or misappropriated information.

Tax Risks

As our only cash-generating assets consist of our partnership interest in Tallgrass Equity and its related direct and indirect interests in TEP, our tax risks are primarily derivative of the tax risks associated with an investment in TEP.

The tax treatment of TEP depends on its status as a partnership for U.S. federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat TEP as a corporation or TEP becomes subject to additional amounts of entity-level taxation for state or foreign tax purposes, it would reduce the amount of cash available for distribution to us and increase the portion of our distributions treated as taxable dividends.

We own a 30.35% membership interest in Tallgrass Equity, which directly owns the Acquired TEP Units and indirectly owns all of TEP’s IDRs and TEP’s general partner interest (which was approximately 1.37% as of March 31, 2015). Accordingly, the value of our indirect investment in TEP, as well as the anticipated after-tax economic benefit of an investment in our Class A shares, depends largely on TEP being treated as a partnership for federal income tax purposes, which requires that 90% or more of TEP’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”).

Despite the fact that TEP is a limited partnership under Delaware law and, unlike us, has not elected to be treated as a corporation for federal income tax purposes, it is possible, under certain circumstances, for TEP to be treated as a corporation for federal income tax purposes. A change in TEP’s business could cause it to be treated as a corporation for federal income tax purposes or otherwise subject it to federal income taxation as an entity. For example, TEP would be treated as a corporation if less than 90% of its gross income for any taxable year consists of “qualifying income” within the meaning of Section 7704 of the Code.

If TEP were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income taxes at varying rates. Distributions to TEP’s partners, including Tallgrass Equity, would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to TEP’s partners. Because a tax would be imposed upon TEP as a corporation, its cash available for distribution would be substantially reduced. Therefore, treatment of TEP as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to us, likely causing a substantial reduction in the value of our Class A shares.

Current law may change, causing TEP to be treated as a corporation for federal income tax purposes or otherwise subjecting TEP to entity-level taxation. In addition, 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 any entity-level taxes on TEP will reduce its cash available for distribution to its partners.

TEP’s partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects TEP to taxation as a corporation or otherwise subjects TEP to entity-level taxation for federal income tax purposes, TEP’s minimum quarterly distribution and target distribution amounts will be adjusted to reflect the impact of that law on TEP. If this were to happen, the amount of distributions Tallgrass Equity receives from TEP and our resulting cash flows could be reduced substantially, which would adversely affect our ability to pay distributions.

Moreover, if TEP were treated as a corporation we would not be entitled to the deductions associated with our initial acquisition of interests in Tallgrass Equity or subsequent exchanges of retained Tallgrass Equity interests and Class B shares for our Class A shares. As a result, if TEP were treated as a corporation, (i) our liability for taxes would likely be higher, further reducing our cash available for distribution and (ii) a greater portion of the cash we are able to distribute would be treated as a taxable dividend.

We may incur substantial corporate income tax liabilities on our allocable share of TEP income.

We anticipate that available deductions will offset our taxable income for, at a minimum, each of the periods ending December 31, 2015, 2016 and 2017. This expectation is subject to numerous assumptions, including TEP’s earnings from its operations, the amount of those earnings allocated to us, the amount of distributions paid to us by TEP, and that there will not be an issuance of significant additional units by TEP without a corresponding increase in the aggregate tax deductions generated by TEP. These assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, our expectation is based on current tax law and tax reporting positions that we and TEP will adopt and with which the IRS could disagree. We are classified as a corporation for U.S. federal income tax purposes and, in most states in which TEP does business, for state income tax purposes. To the extent that TEP allocates to us net taxable income in any year, current law provides that we will be subject to U.S. federal income tax at rates of up to 35% (and a 20% alternative minimum tax in certain cases), and to state income tax at rates that vary from state to state. The amount of cash available for distribution to you will be reduced by the amount of any such income taxes payable by us for which we establish reserves.

The tax treatment of publicly traded partnerships such as TEP could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including TEP, may be modified by legislative, judicial, or administrative changes, or interpretations of applicable law at any time. Any modifications to the U.S. federal income tax laws that may be applied retroactively or prospectively could make it more difficult or impossible to meet the expectation of future cash distributions or reduce the cash available for distributions to our shareholders. For example, from time to time, the President or members of 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, and the President proposed in his recently issued budget proposal to eliminate, the qualifying income exception upon which TEP relies for its treatment as a partnership for U.S. federal income tax purposes. TEP is unable to predict whether any of these changes or any other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of our indirect investment in TEP. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

The sale or exchange of 50% or more of TEP’s capital and profits interests during any twelve-month period will result in its termination as a partnership for federal income tax purposes.

TEP will be considered to have technically terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a twelve-month period. Tallgrass Development and its direct and indirect owners own a substantial interest in the capital and profits of TEP. Therefore, a transfer by them of all or a portion of their interests in TEP could result in a termination of TEP for U.S. 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. TEP’s termination would, among other things, result in a deferral of depreciation deductions allowable in computing TEP’s taxable income. A deferral of depreciation deductions could increase the amount of taxable income allocated to us from TEP which could increase our tax liabilities and thereby reduce the amount of cash available for distribution. TEP’s termination currently would not affect its classification as a partnership for federal income tax purposes, but could cause it to be subject to penalties if it were unable to determine that a termination occurred.

Taxable gain or loss on the sale of our Class A shares could be more or less than expected.

If a holder sells our Class A shares, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in those Class A shares. To the extent that the amount of our distributions exceeds our current and accumulated earnings and profits, the distributions will be treated as a tax free return of capital and will reduce a holder’s tax basis in the Class A shares. We do not expect to have any earnings and profits for, at a minimum, each of the periods ending December 31, 2015, 2016 and 2017. Because our distributions in excess of our earnings and profits decrease a holder’s tax basis in Class A shares, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A shares.

Our current tax treatment may change, which could affect the value of our Class A shares or reduce our cash available for distribution.

Our expectation that we will have available deductions that will offset a substantial portion of our taxable income and that our distributions will not constitute taxable dividends for, at a minimum, each of the periods ending December 31, 2015, 2016, and 2017, is based on current law, including with respect to the amortization of basis adjustments associated with our acquisition of interests in Tallgrass Equity. Similarly, our expectation that exchanges by the Exchange Right Holders of their retained interests in Tallgrass Equity and Class B shares in us for our Class A shares in the future will result in additional tax deductions is based on current law with respect to such exchanges. Changes in federal income tax law relating to such tax treatment could result in (i) our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution and (ii) a greater portion of our distributions being treated as taxable dividends. Moreover, we are subject to tax in numerous jurisdictions. Changes in current law in these jurisdictions, particularly relating to the treatment of deductions attributable to acquisitions of interests in Tallgrass Equity, could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution.

Any decrease in our Class A share price could adversely affect our amount of cash available for distribution.

Changes in certain market conditions may cause our Class A share price to decrease. If the Exchange Right Holders exchange their retained interests in Tallgrass Equity and Class B shares in us for our Class A shares at a point in time when our Class A share price is below the price at which Class A shares are being sold in this offering, the ratio of our income tax deductions to gross income would decline. This decline could result in our being subject to tax sooner than expected, our tax liability being greater than expected, or a greater portion of our distributions being treated as taxable dividends.

The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income with respect to our shares for U.S. federal income tax purposes, and failure to report your dividend income in a manner consistent with the IRS Form 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your U.S. federal income tax return. If you are a non-U.S. holder of our shares, your broker or other withholding agent may overwithhold taxes from dividends paid to you, in which case you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to claim a refund of the overwithheld taxes.

Distributions we pay with respect to our shares will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of your tax basis in your shares and then as capital gain realized on the sale or exchange of such shares. We may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes.

If you are a U.S. holder of our Class A shares, the IRS Form 1099-DIV may not be consistent with our determination of the amount that constitutes a “dividend” to you for U.S. federal income tax purposes or you may receive a corrected IRS Form 1099-DIV (and you may therefore need to file an amended federal, state or local income tax return). We will attempt to timely notify you of available information to assist you with your income tax reporting (such as posting the correct information on our website). However, the information that we provide to you may be inconsistent with the amounts reported to you by your broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your tax return.

If you are a non-U.S. holder of our Class A shares, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with your conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes, or your broker or withholding agent chooses to withhold taxes from distributions in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, your broker or other withholding agent may overwithhold taxes from distributions paid to you. In such a case, you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered Sales of Equity Securities

On February 19, 2015, in connection with our formation, we issued 100% of the limited partner interests in TEGP to Tallgrass Energy Holdings, LLC (formerly known as Tallgrass Development GP, LLC) in exchange for $1,000. This transaction was exempt from registration under Section 4(2) of the Securities Act. There were no other unregistered sales of securities during the three months ended March 31, 2015.

Use of Proceeds

On May 6, 2015, our Registration Statement on Form S-1 (File No. 333-202258), as amended, filed with the SEC in connection with the Offering was declared effective. The Offering closed on May 12, 2015, and we sold 47,725,000 Class A shares to the public, including a 6,225,000 Class A share overallotment exercised by the underwriters. The price to the public was $29.00 per Class A share and the proceeds (net of underwriting discounts and commissions) totaled approximately $1.3 billion. Expenses related to the Offering included approximately $65.7 million for the underwriters’ discount. Citigroup Global Markets Inc., Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Morgan Stanley & Co. LLC, RBC Capital Markets, LLC and Wells Fargo Securities, LLC acted as joint book-running managers of the Offering.

We contributed the net proceeds of the Offering (excluding proceeds from the underwriters exercise of their option to purchase additional Class A shares) to Tallgrass Equity in exchange for Tallgrass Equity’s issuance to us of 41,500,000 Tallgrass Equity units.

At the closing of the Offering, Tallgrass Equity entered into a new $150 million revolving credit facility and borrowed $150 million, the proceeds of which were used, together with the net proceeds from the Offering that Tallgrass Equity received from us, to purchase 20 million TEP common units from TD at $47.68 per TEP common unit. Tallgrass Equity distributed the remaining proceeds to the Exchange Right Holders.

We used the proceeds from the sale of the underwriters’ purchase the additional 6,225,000 Class A shares to purchase 6,225,000 Tallgrass Equity units from the Exchange Right Holders. 6,225,000 Class B shares were cancelled as a result of the exercise of the underwriter’s option to purchase the additional 6,225,000 Class A shares. After the application of the net proceeds from the Offering, we own a 30.35% membership interest in Tallgrass Equity.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits



Exhibit No.		Description

3.1		Certificate of Limited Partnership of Tallgrass Energy GP, LP, dated February 10, 2015 (incorporated by reference to Exhibit 3.1 to Tallgrass Energy GP, LP’s Registration Statement on Form S-1 filed February 24, 2015).

3.2		Amended and Restated Limited Partnership Agreement of Tallgrass Energy GP, LP, dated May 12, 2015 (incorporated by reference to Exhibit 3.1 to Tallgrass Energy GP, LP’s Current Report on Form 8-K filed May 12, 2015).

3.3		Certificate of Formation of TEGP Management, LLC, dated February 10, 2015 (incorporated by reference to Exhibit 3.3 to Tallgrass Energy GP, LP’s Registration Statement on Form S-1 filed February 24, 2015).

3.4		Amended and Restated Limited Liability Company Agreement of TEGP Management, LLC, dated May 12, 2015 (incorporated by reference to Exhibit 3.2 to Tallgrass Energy GP, LP’s Current Report on Form 8-K filed May 12, 2015).

3.5		Certificate of Formation of Tallgrass GP Holdings, LLC, dated March 28, 2013 (now known as Tallgrass Equity, LLC) (incorporated by reference to Exhibit 3.5 to Tallgrass Energy GP, LP’s Registration Statement on Form S-1 filed February 24, 2015).

3.6		Certificate of Amendment to Certificate of Formation of Tallgrass GP Holdings, LLC, dated February 20, 2015 (now known as Tallgrass Equity, LLC) (incorporated by reference to Exhibit 3.6 to Tallgrass Energy GP, LP’s Registration Statement on Form S-1 filed February 24, 2015).

3.7*		Second Amended and Restated Limited Liability Company Agreement of Tallgrass Equity, LLC, dated May 12, 2015.

3.8		Certificate of Limited Partnership of Tallgrass MLP, LP, dated as of February 6, 2013 (now known as Tallgrass Energy Partners, LP) (incorporated by reference to Exhibit 3.1 to Tallgrass Energy Partners, LP’s Registration Statement on Form S-1 filed March 28, 2013).

3.9		Certificate of Amendment to Certificate of Limited Partnership of Tallgrass MLP, LP, dated as of February 7, 2013 (now known as Tallgrass Energy Partners, LP) (incorporated by reference to Exhibit 3.2 to Tallgrass Energy Partners, LP’s Registration Statement on Form S-1 filed March 28, 2013).

3.10		Amended and Restated Agreement of Limited Partnership of Tallgrass Energy Partners, LP, dated as of May 17, 2013 (incorporated by reference to Exhibit 3.2 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed May 17, 2013).

3.11		Certificate of Formation of Tallgrass MLP GP, LLC, dated as of February 6, 2013 (incorporated by reference to Exhibit 3.4 to Tallgrass Energy Partners, LP’s Registration Statement on Form S-1 filed March 28, 2013).

3.12		Second Amended and Restated Limited Liability Company Agreement of Tallgrass MLP GP, LLC dated May 17, 2013 (incorporated by reference to Exhibit 3.4 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed May 17, 2013).

3.13		Amendment No. 1, dated February 19, 2015, to Second Amended and Restated Limited Liability Company Agreement of Tallgrass MLP GP, LLC, dated May 17, 2013 (incorporated by reference to Exhibit 3.8 to Tallgrass Energy Partners Annual Report on Form 10-K/A filed June 4, 2015).

4.1		Specimen certificate representing Class A Shares (incorporated by reference to Exhibit 4.1 to Tallgrass Energy GP, LP’s Registration Statement on Form S-1/A filed April 20, 2015).

4.2*		Registration Rights Agreement, dated May 12, 2015, by and among Tallgrass Energy GP, LP and each of the Initial Holders listed on an annex thereto.

10.1		Omnibus Agreement, dated May 12, 2015, by and among Tallgrass Energy Holdings, LLC, Tallgrass Energy GP, LP, TEGP Management, LLC and Tallgrass Equity, LLC (incorporated by reference to Exhibit 10.1 to Tallgrass Energy GP, LP’s Current Report on Form 8-K filed May 12, 2015).

10.2		Tallgrass Equity Credit Agreement, dated May 12, 2015, by and among Tallgrass Equity, LLC, Barclays Bank PLC, as administrative agent, and a syndicate of lenders named therein (incorporated by reference to Exhibit 10.2 to Tallgrass Energy GP, LP’s Current Report on Form 8-K filed May 12, 2015).



10.3		TEGP Management, LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to Tallgrass Energy GP, LP’s Current Report on Form 8-K filed May 12, 2015).

10.4		Distribution, Assignment and Assumption Agreement (interest in Tallgrass Energy GP, LP), dated May 11, 2015, by and among Tallgrass Holdings, LLC and the Assignees listed therein (incorporated by reference to Exhibit 10.3 to Tallgrass Energy GP, LP’s Current Report on Form 8-K filed May 12, 2015).

10.5		Tallgrass Equity Unit Issuance Agreement, dated May 12, 2015, by and among Tallgrass Equity, LLC and Tallgrass Energy GP, LP (incorporated by reference to Exhibit 10.4 to Tallgrass Energy GP, LP’s Current Report on Form 8-K filed May 12, 2015).

10.6		Conveyance Agreement (Common Units of Tallgrass Energy Partners, LP), dated May 12, 2015, by and among Tallgrass Operations, LLC and Tallgrass Equity, LLC (incorporated by reference to Exhibit 10.6 to Tallgrass Energy GP, LP’s Current Report on Form 8-K filed May 12, 2015).

10.7		Amended and Restated Employment Agreement between Tallgrass Management, LLC, Tallgrass Development GP, LLC, Tallgrass GP Holdings, LLC, Tallgrass MLP GP, LLC and David G. Dehaemers, Jr. (incorporated by reference to Exhibit 10.5 to Amendment No. 2 to Tallgrass Energy Partners, LP’s Registration Statement on Form S-1 filed April 18, 2013).

10.8		Purchase and Sale Agreement, dated August 1, 2012, between Kinder Morgan Interstate Gas Transmission LLC and Kinder Morgan Pony Express Pipeline LLC (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to Tallgrass Energy Partners, LP’s Registration Statement on Form S-1 filed April 8, 2013).

10.9		Contribution, Conveyance and Assumption Agreement, dated May 17, 2013, by and among Tallgrass Energy Partners, LP, Tallgrass MLP GP, LLC, Tallgrass Development, LP, Tallgrass Development GP, LLC, Tallgrass GP Holdings, LLC, Tallgrass Operations, LLC, Tallgrass Interstate Gas Transmission, LLC, Tallgrass Midstream, LLC and Tallgrass MLP Operations, LLC (incorporated by reference to Exhibit 10.1 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed May 17, 2013).

10.10		Omnibus Agreement, dated May 17, 2013, by and among Tallgrass Development, LP, Tallgrass Energy Partners, LP, Tallgrass MLP GP, LLC and Tallgrass Development GP, LLC (incorporated by reference to Exhibit 10.2 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed May 17, 2013).

10.11		Revolving Credit Agreement, dated May 17, 2013, by and among Tallgrass Energy Partners, LP, Barclays Bank PLC, as administrative agent, and a syndicate of lenders named therein (incorporated by reference to Exhibit 10.3 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed May 17, 2013).

10.12		Tallgrass MLP GP, LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed May 17, 2013).

10.13		Contribution and Sale Agreement, dated as of April 1, 2014, by and among Tallgrass Energy Partners, LP, Tallgrass Operations, LLC and Tallgrass Development, LP (incorporated by reference to Exhibit 10.1 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed April 2, 2014).

10.14		Amendment No. 1, dated as of June 25, 2014, to the Revolving Credit Agreement by and among Tallgrass Energy Partners, LP, Barclays Bank PLC, as administrative agent, and a syndicate of lenders named therein (incorporated by reference to Exhibit 10.1 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed June 30, 2014).

10.15		Contribution and Transfer Agreement, dated as of September 1, 2014, by and among Tallgrass Energy Partners, LP, Tallgrass Pony Express Pipeline, LLC, Tallgrass Operations, LLC and Tallgrass Development, LP (incorporated by reference to Exhibit 10.1 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed September 8, 2014).

10.16		Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Tallgrass Pony Express Pipeline, LLC, dated as of September 29, 2014, by and among Tallgrass Pony Express Pipeline, LLC, Tallgrass Operations, LLC, and Tallgrass PXP Holdings, LLC (incorporated by reference to Exhibit 10.3 to Tallgrass Energy Partners, LP’s Quarterly Report on Form 10-Q filed October 30, 2014).

10.17		Purchase and Sale Agreement, dated as of March 1, 2015, by and among Tallgrass Energy Partners, LP, Tallgrass Operations, LLC and Tallgrass Development, LP (incorporated by reference to Exhibit 10.1 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed March 2, 2015).



10.18		Third Amended and Restated Limited Liability Company Agreement of Tallgrass Pony Express Pipeline, LLC, dated as of March 1, 2015, by and among Tallgrass Pony Express Pipeline, LLC, Tallgrass Operations, LLC, and Tallgrass PXP Holdings, LLC (incorporated by reference to Exhibit 10.2 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed March 2, 2015).

31.1*		Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr.

31.2*		Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle.

32.1*		Section 1350 Certification of David G. Dehaemers, Jr.

32.2*		Section 1350 Certification of Gary J. Brauchle.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.


* -	filed herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		Tallgrass Energy GP, LP
		(registrant)
		By:	TEGP Management, LLC, its general partner

Date:	June 18, 2015	By:	/s/ Gary J. Brauchle
			Name:	Gary J. Brauchle
			Title:	Executive Vice President and Chief Financial Officer

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company