Edgar Filing: Tallgrass Energy Partners, LP

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

TEP 2015.6.30 10Q

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 June 30, 2015



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

Commission file number 001-35917

Tallgrass Energy Partners, LP

(Exact name of registrant as specified in its charter)



Delaware				46-1972941
(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 ý No ¨

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 July 30, 2015, the Registrant had 60,576,357 Common Units and 834,391 General Partner Units outstanding.

TALLGRASS ENERGY PARTNERS, LP

TABLE OF CONTENTS



PART 1—FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
CONDENSED CONSOLIDATED BALANCE SHEETS	1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME	2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	3
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL	4
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3. Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. Controls and Procedures	38
PART II - OTHER INFORMATION	38
Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3. Defaults Upon Senior Securities	39
Item 4. Mine Safety Disclosures	39
Item 5. Other Information	39
Item 6. Exhibits	40
SIGNATURES	41

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.

EPA: The United States Environmental Protection Agency.

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 if the contracted capacity is 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 if the contracted storage capacity is 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 (or walk-up 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 PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)



	June 30, 2015			December 31, 2014
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1,778		$	867
Accounts receivable, net	51,521			39,768
Receivable from related party	—			73,393
Gas imbalances	1,017			2,442
Inventories	15,162			13,045
Prepayments and other current assets	3,768			2,766
Total Current Assets	73,246			132,281
Property, plant and equipment, net	1,943,016			1,853,081
Goodwill	343,288			343,288
Intangible asset, net	100,506			104,538
Deferred financing costs, net	4,735			5,528
Deferred charges and other assets	16,651			18,481
Total Assets	$	2,481,442		$	2,457,197
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities:
Accounts payable (including $15,945 and $45,534, respectively, related to variable interest entities)	$	28,583		$	62,329
Accounts payable to related parties	3,772			3,915
Gas imbalances	2,812			3,611
Derivative liabilities at fair value	41			—
Accrued taxes	12,206			3,989
Accrued liabilities	6,710			9,384
Deferred revenue	9,882			5,468
Other current liabilities	4,247			7,872
Total Current Liabilities	68,253			96,568
Long-term debt	706,000			559,000
Other long-term liabilities and deferred credits	6,342			6,478
Total Long-term Liabilities	712,342			565,478
Commitments and Contingencies
Equity:
Common unitholders (60,576,357 and 32,834,105 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively)	1,629,223			800,333
Subordinated unitholder (0 and 16,200,000 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively)	—			274,133
General partner (834,391 units issued and outstanding at June 30, 2015 and December 31, 2014)	(353,579		)	(35,743		)
Total Partners’ Equity	1,275,644			1,038,723
Noncontrolling interests	$	425,203		$	756,428
Total Equity	$	1,700,847		$	1,795,151
Total Liabilities and Equity	$	2,481,442		$	2,457,197

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands, except per unit amounts)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	20,011		$	39,042		$	41,880		$	92,757
Natural gas transportation services	29,041			30,569			61,189			64,673
Crude oil transportation services	74,022			—			124,403			—
Processing and other revenues	9,896			7,709			20,173			14,669
Total Revenues	132,970			77,320			247,645			172,099
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	17,180			37,214			36,773			85,420
Cost of transportation services (exclusive of depreciation and amortization shown below)	13,492			5,288			24,207			10,405
Operations and maintenance	12,408			10,055			21,983			18,068
Depreciation and amortization	20,355			9,525			40,960			17,834
General and administrative	13,451			7,124			26,140			13,773
Taxes, other than income taxes	(271		)	1,639			11,026			3,595
Loss on sale of assets	—			—			4,483			—
Total Operating Costs and Expenses	76,615			70,845			165,572			149,095
Operating Income	56,355			6,475			82,073			23,004
Other (Expense) Income:
Interest expense, net	(3,893		)	(2,137		)	(7,333		)	(3,433		)
Gain on remeasurement of unconsolidated investment	—			9,388			—			9,388
Equity in earnings of unconsolidated investment	—			273			—			717
Other income, net	769			729			1,481			1,669
Total Other (Expense) Income	(3,124		)	8,253			(5,852		)	8,341
Net income	53,231			14,728			76,221			31,345
Net (income) loss attributable to noncontrolling interests	(8,332		)	558			997			1,065
Net income attributable to partners	$	44,899		$	15,286		$	77,218		$	32,410
Allocation of income to the limited partners:
Net income attributable to partners	$	44,899		$	15,286		$	77,218		$	32,410
Predecessor operations interest in net loss (income)	—			1,581			—			(2,643		)
General partner interest in net income	(11,030		)	(1,096		)	(18,468		)	(1,477		)
Common and subordinated unitholders' interest in net income	33,869			15,771			58,750			28,290
Basic net income per common and subordinated unit	$	0.56		$	0.39		$	1.04		$	0.70
Diluted net income per common and subordinated unit	$	0.55		$	0.38		$	1.02		$	0.68
Basic average number of common and subordinated units outstanding	60,362			40,885			56,566			40,694
Diluted average number of common and subordinated units outstanding	61,225			41,905			57,404			41,624

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Six Months Ended June 30,
	2015			2014
	(in thousands)
Cash Flows from Operating Activities:
Net income	$	76,221		$	31,345
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	42,867			18,470
Gain on remeasurement of unconsolidated investment	—			(9,388		)
Noncash compensation expense	3,254			2,249
Loss on sale of assets	4,483			—
Changes in components of working capital:
Accounts receivable and other	(10,215		)	4,142
Gas imbalances	189			831
Inventories	(6,068		)	(867		)
Accounts payable and accrued liabilities	2,183			(17,077		)
Deferred revenue	4,198			1,673
Other operating, net	(4,894		)	(253		)
Net Cash Provided by Operating Activities	112,218			31,125
Cash Flows from Investing Activities:
Capital expenditures	(49,544		)	(479,309		)
Acquisition of additional 33.3% membership interest in Pony Express	(700,000		)	—
Acquisition of Trailblazer	—			(150,000		)
Acquisition of additional equity interests in Water Solutions	—			(7,600		)
Other investing, net	(4,648		)	(1,638		)
Net Cash Used in Investing Activities	(754,192		)	(638,547		)
Cash Flows from Financing Activities:
Proceeds from public offering, net of offering costs	551,673			—
Borrowings under revolving credit facility, net	147,000			146,000
Contributions from Predecessor Member, net	—			460,400
Distributions to unitholders	(67,080		)	(26,770		)
Contribution from TD	—			27,488
Contributions from noncontrolling interests	16,294			—
Other financing, net	(5,002		)	330
Net Cash Provided by Financing Activities	642,885			607,448
Net Change in Cash and Cash Equivalents	911			26
Cash and Cash Equivalents, beginning of period	867			—
Cash and Cash Equivalents, end of period	$	1,778		$	26

Schedule of Noncash Investing and Financing Activities:
Property, plant and equipment acquired via the cash management agreement with TD	$	103,239		$	—
Contributions from noncontrolling interests settled via the cash management agreement with TD	$	21,525		$	—
Distribution to noncontrolling interests settled via the cash management agreement with TD	$	22,266		$	—
Increase in accrual for payment of property, plant and equipment	$	—		$	10,148

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(UNAUDITED)



	Predecessor Equity			Limited Partners						General Partner			Total Partners’ Equity			Noncontrolling Interests			Total Equity
	Predecessor Equity			Common			Subordinated			General Partner			Total Partners’ Equity			Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2015	$	—		$	800,333		$	274,133		$	(35,743	)	$	1,038,723		$	756,428		$	1,795,151
Net income (loss)	—			53,570			5,180			18,468			77,218			(997		)	76,221
Issuance of units to public, net of offering costs	—			551,673			—			—			551,673			—			551,673
Distributions to unitholders	—			(47,247		)	(7,857		)	(11,976		)	(67,080		)	—			(67,080		)
Noncash compensation expense	—			6,000			—			—			6,000			—			6,000
LTIP units tendered by employees to satisfy tax withholding obligations	—			(6,562		)	—			—			(6,562		)	—			(6,562		)
Contributions from noncontrolling interest	—			—			—			—			—			68,651			68,651
Distributions to noncontrolling interest	—			—			—			—			—			(22,607		)	(22,607		)
Acquisition of additional 33.3% membership interest in Pony Express	—			—			—			(324,328		)	(324,328		)	(375,672		)	(700,000		)
Acquisition of noncontrolling interests	—			—			—			—			—			(600		)	(600		)
Conversion of subordinated units	—			271,456			(271,456		)	—			—			—			—
Balance at June 30, 2015	$	—		$	1,629,223		$	—		$	(353,579	)	$	1,275,644		$	425,203		$	1,700,847

	Predecessor Equity			Limited Partners						General Partner			Total Partners’ Equity			Noncontrolling Interests			Total Equity
	Predecessor Equity			Common			Subordinated			General Partner			Total Partners’ Equity			Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2014	$	247,221		$	455,197		$	274,666		$	14,078		$	991,162		$	317,939		$	1,309,101
Net income (loss)	2,643			17,034			11,256			1,477			32,410			(1,065		)	31,345
Noncash compensation expense	—			4,650			—			—			4,650			—			4,650
Distributions to unitholders	—			(15,677		)	(10,368		)	(725		)	(26,770		)	—			(26,770		)
Contribution from TD	—			—			—			27,488			27,488			—			27,488
Contributions from Predecessor Member, net	151,537			—			—			—			151,537			308,863			460,400
Issuance of general partner units	—			—			—			263			263			—			263
Acquisition of Trailblazer	(91,090		)	14,023			—			(72,933		)	(150,000		)	—			(150,000		)
Acquisition of Water Solutions	—			—			—			—			—			1,400			1,400
Balance at June 30, 2014	$	310,311		$	475,227		$	275,554		$	(30,352	)	$	1,030,740		$	627,137		$	1,657,877

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

TALLGRASS ENERGY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Description of Business

Tallgrass Energy Partners, LP ("TEP" or the "Partnership") 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," "us," "our" and similar terms refer to TEP together with its consolidated subsidiaries. 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, Colorado, and the surrounding regions through our membership interest in Tallgrass Pony Express Pipeline, LLC ("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.

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.

The table below summarizes our equity ownership as of June 30, 2015:



Unit Holder	Limited Partner Common Units	General Partner Units	Percentage of Outstanding Limited Partner Common Units		Percentage of Outstanding Common and General Partner Units
Public Unitholders	34,220,877	—	56.49	%	55.72	%
Tallgrass Equity, LLC	20,000,000	—	33.02	%	32.57	%
Tallgrass Development, LP	6,355,480	—	10.49	%	10.35	%
Tallgrass MLP GP, LLC ⁽¹⁾	—	834,391	—		1.36	%
Total	60,576,357	834,391	100.00	%	100.00	%


⁽¹⁾	Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights ("IDRs").

The term "Trailblazer Predecessor" refers to Trailblazer Pipeline Company LLC ("Trailblazer") for the period from November 13, 2012 to its acquisition by TEP on April 1, 2014, and the term "Pony Express Predecessor" refers to Pony Express for the period from November 13, 2012 to September 1, 2014, the date on which TEP acquired a controlling 33.3% membership interest. Trailblazer Predecessor and Pony Express Predecessor are collectively referred to as the Predecessor Entities, as further discussed in Note 2 – Summary of Significant Accounting Policies. Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entities. Predecessor Equity as presented in the condensed consolidated financial statements represents the capital account activity of Trailblazer Predecessor prior to April 1, 2014 and of Pony Express Predecessor prior to September 1, 2014. For additional information regarding these acquisitions, see Note 4 – Acquisitions.

2. Summary of Significant Accounting Policies

Basis of Presentation

These unaudited condensed consolidated financial statements and related notes for the three and six months ended June 30, 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 year-end balance sheet data was derived from audited financial statements but does not include disclosures required by GAAP for annual periods. The unaudited condensed consolidated financial statements for the three and six months ended June 30, 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. Certain prior period amounts have been reclassified to conform to the current presentation.

Our financial results for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2015. The accompanying unaudited condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K/A for the year ended December 31, 2014 (“2014 Form 10-K/A”) filed with the United States Securities and Exchange Commission (the “SEC”) on June 4, 2015.

The condensed consolidated financial statements of TEP include historical cost basis accounts of the assets of Trailblazer for the periods prior to April 1, 2014, the date TEP acquired Trailblazer from Tallgrass Development, LP ("TD"), and Pony Express for the periods prior to September 1, 2014, the date TEP acquired a controlling 33.3% membership interest in Pony Express, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis.

As further discussed in Note 4 – Acquisitions, TEP closed the acquisition of Trailblazer on April 1, 2014 and the acquisition of a 33.3% membership interest in Pony Express effective September 1, 2014. As the acquisitions of Trailblazer and the initial 33.3% membership interest in Pony Express are considered transactions between entities under common control, and a change in reporting entity, the financial information presented for prior periods has been recast to include Trailblazer and the initial 33.3% membership interest in Pony Express for all periods presented. 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 March 1, 2015 have not been recast to reflect the additional 33.3% membership interest.

The condensed consolidated financial statements include the accounts of TEP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Net equity contributions of the Predecessor Entities included in the condensed consolidated 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 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.

Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP 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 TEP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in 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. We have presented separately in our condensed consolidated balance sheets, to the extent material, the assets of our consolidated VIE that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of our consolidated VIE for which creditors do not have recourse to our general credit. Pony Express is considered to be a VIE under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we are the primary beneficiary as we have the power to direct matters that most significantly impact the activities of Pony Express and have the right to receive benefits of Pony Express that could potentially be significant to Pony Express. We have consolidated Pony Express accordingly. For additional information see Note 3 – Variable Interest Entities.

Use of Estimates

Certain amounts included in or affecting these condensed consolidated 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. During the second quarter of 2015, we recorded a reduction in our property tax accrual for the first quarter of 2015 of $5.7 million as a result of revised property tax estimates due to successful appeals with state taxing authorities on the assessed value of property, which resulted in a net credit of $0.3 million in taxes, other than income taxes for the three months ended June 30, 2015.

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, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. 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.

ASU No. 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory"

In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory. ASU 2015-11 establishes a "lower of cost and net realizable value" model for the measurement of most inventory balances. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.

The amendments in ASU 2015-11 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We are currently evaluating the impact of ASU 2015-11.

3. Variable Interest Entities

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 consolidate Pony Express accordingly.

We have not provided any additional financial support to Pony Express other than our initial capital contribution of $570 million and have 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.

The carrying amounts and classifications of the Pony Express assets and liabilities included in our condensed consolidated balance sheets at June 30, 2015 and December 31, 2014 are as follows:



	June 30, 2015		December 31, 2014
	(in thousands)
Current assets	$	39,090	$	93,019
Noncurrent assets	1,381,735		1,300,816
Total assets	$	1,420,825	$	1,393,835
Current liabilities	$	34,970	$	52,547
Total liabilities	$	34,970	$	52,547

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 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 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 as discussed further in Note 10 – Partnership Equity and Distributions.

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 the Second Amended Pony Express LLC Agreement, 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 Pony Express LLC Agreement, 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 June 30, 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.

Historical Financial Information

The results of our acquisitions of Trailblazer and a 66.7% membership interest in Pony Express are included in the condensed consolidated balance sheet as of June 30, 2015. The results of our acquisitions of Trailblazer and the initial 33.3% membership interest in Pony Express are included in the condensed consolidated balance sheet as of December 31, 2014. The results of our acquisitions of Trailblazer and the initial 33.3% membership interest in Pony Express are included in the condensed consolidated statements of income for the three and six months ended June 30, 2015 and 2014. The results of our acquisition of an additional 33.3% membership interest in Pony Express are included in the condensed consolidated statements of income prospectively beginning March 1, 2015.

The following tables present the previously reported condensed consolidated statements of income for the three and six months ended June 30, 2014 adjusted for the acquisition of the initial 33.3% membership interest in Pony Express:



	Three Months Ended June 30, 2014
	TEP			Consolidate Tallgrass Pony Express Pipeline, LLC			Eliminations			TEP (As currently reported)
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	39,042		$	—		$	—		$	39,042
Transportation services	30,569			—			—			30,569
Processing and other revenues	7,709			—			—			7,709
Total Revenues	77,320			—			—			77,320
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	37,214			—			—			37,214
Cost of transportation services (exclusive of depreciation and amortization shown below)	3,958			—			1,330			5,288
Operations and maintenance	10,055			—			—			10,055
Depreciation and amortization	8,768			757			—			9,525
General and administrative	7,124			—			—			7,124
Taxes, other than income taxes	1,639			—			—			1,639
Total Operating Costs and Expenses	68,758			757			1,330			70,845
Operating Income (Loss)	8,562			(757		)	(1,330		)	6,475
Other (Expense) Income:
Interest (expense) income, net	(2,140		)	3			—			(2,137		)
Gain on remeasurement of unconsolidated investment	9,388			—			—			9,388
Equity in earnings of unconsolidated investment	273			—			—			273
Other income, net	729			—			—			729
Total Other Income	8,250			3			—			8,253
Net Income (Loss)	16,812			(754		)	(1,330		)	14,728
Net loss attributable to noncontrolling interests	55			503			—			558
Net income (loss) attributable to partners	$	16,867		$	(251	)	$	(1,330	)	$	15,286



	Six Months Ended June 30, 2014
	TEP			Consolidate Tallgrass Pony Express Pipeline, LLC			Eliminations			TEP (As currently reported)
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	92,757		$	—		$	—		$	92,757
Transportation services	64,673			—			—			64,673
Processing and other revenues	14,669			—			—			14,669
Total Revenues	172,099			—			—			172,099
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	85,420			—			—			85,420
Cost of transportation services (exclusive of depreciation and amortization shown below)	7,820			—			2,585			10,405
Operations and maintenance	18,068			—			—			18,068
Depreciation and amortization	16,320			1,514			—			17,834
General and administrative	13,773			—			—			13,773
Taxes, other than income taxes	3,595			—			—			3,595
Total Operating Costs and Expenses	144,996			1,514			2,585			149,095
Operating Income (Loss)	27,103			(1,514		)	(2,585		)	23,004
Other (Expense) Income:
Interest (expense) income, net	(3,433		)	—			—			(3,433		)
Gain on remeasurement of unconsolidated investment	9,388			—			—			9,388
Equity in earnings of unconsolidated investment	717			—			—			717
Other income, net	1,669			—			—			1,669
Total Other Income	8,341			—			—			8,341
Net Income (Loss)	35,444			(1,514		)	(2,585		)	31,345
Net loss attributable to noncontrolling interests	55			1,010			—			1,065
Net income (loss) attributable to partners	$	35,499		$	(504	)	$	(2,585	)	$	32,410

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 Grasslands Water Services I, LLC ("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 December 31, 2014, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. During the three months ended June 30, 2015, the preliminary purchase price allocation with respect to Water Solutions was finalized with no material adjustments.

On May 20, 2015, TEP acquired an additional 12% equity interest in Water Solutions from NR2, LLC for cash consideration of $600,000, which was accounted for as an acquisition of noncontrolling interest. As of June 30, 2015, TEP's aggregate membership interest in Water Solutions was 92%.

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 "Omnibus Agreement"). The 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.

TEP’s general and administrative costs under the Omnibus Agreement were $5.5 million and $10.9 million for the three and six months ended June 30, 2015, respectively, excluding costs attributable to Pony Express. Pony Express had general and administrative costs of $5.2 million and $10.3 million for the three and six months ended June 30, 2015, respectively. TEP also pays a quarterly reimbursement to TD for costs associated with being a public company. The quarterly public company reimbursement was $635,000 for the second quarter of 2015. These amounts will be periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEP.

Due to the cash management agreement discussed in Note 2 – Summary of Significant Accounting Policies, intercompany balances at the Predecessor Entities 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 consolidated balance sheets. We recognized interest income from TD of $0.4 million during the three and six months ended June 30, 2015 on the receivable balance under the Pony Express cash management agreement.

Totals of transactions with affiliated companies are as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)
Cost of transportation services	$	6,233	$	—	$	10,591	$	—
Charges to TEP: ⁽¹⁾
Property, plant and equipment, net	$	1,594	$	3,186	$	2,901	$	6,586
Operation and maintenance	$	5,825	$	4,608	$	11,248	$	8,956
General and administrative	$	9,315	$	4,676	$	18,571	$	9,603


⁽¹⁾	Charges to TEP, inclusive of 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 consolidated balance sheets are as follows:



	June 30, 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	$	3,688	$	3,894
Rockies Express Pipeline LLC	84		21
Total accounts payable to related parties	$	3,772	$	3,915

Balances of gas imbalances with affiliated shippers are as follows:



	June 30, 2015		December 31, 2014
	(in thousands)
Affiliate gas balance receivables	$	11	$	275
Affiliate gas balance payables	$	405	$	455

6. Inventory

The components of inventory at June 30, 2015 and December 31, 2014 consisted of the following:



	June 30, 2015		December 31, 2014
	(in thousands)
Crude oil	$	2,855	$	581
Materials and supplies	5,415		3,049
Natural gas liquids	386		519
Gas in underground storage	6,506		8,896
Total inventory	$	15,162	$	13,045

7. Property, Plant and Equipment

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



	June 30, 2015			December 31, 2014
	(in thousands)
Crude oil pipelines	$	1,154,685		$	939,536
Natural gas pipelines	553,595			548,482
Processing and treating assets	237,045			241,671
General and other	63,530			42,719
Construction work in progress	28,615			139,873
Accumulated depreciation and amortization	(94,454		)	(59,200		)
Total property, plant and equipment, net	$	1,943,016		$	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 consolidated balance sheets:



	Balance Sheet Location	June 30, 2015		December 31, 2014
		(in thousands)
Energy commodity derivative contracts	Current liabilities	$	41	$	—

As of June 30, 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 and six months ended June 30, 2015 and 2014:



		Amount of Gain (Loss) Recognized in Income on Derivatives
	Location of gain (loss) recognized in income on derivatives	Three Months Ended June 30,						Six Months Ended June 30,
	Location of gain (loss) recognized in income on derivatives	2015			2014			2015			2014
		(in thousands)
Derivatives not designated as hedging contracts:
Energy commodity derivative contracts	Sales of natural gas, NGLs, and crude oil	$	(131	)	$	(106	)	$	(41	)	$	(458	)

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 exchanges. 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. As of June 30, 2015, the fair value of TEP’s derivative contracts was a liability, resulting in no credit exposure from TEP’s counterparties as of that date.

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 June 30, 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 June 30, 2015 based on the fair value hierarchy established by the Codification:



			Liability fair value measurements using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
TEP as of June 30, 2015
Energy commodity derivative contracts	$	41	$	—	$	41	$	—

9. Long-term Debt

The following table sets forth the outstanding borrowings, letters of credit issued, and available borrowing capacity under our revolving credit facility as of June 30, 2015 and December 31, 2014:



	June 30, 2015			December 31, 2014
	(in thousands)
Total capacity under the revolving credit facility	$	850,000		$	850,000
Less: Outstanding borrowings under the revolving credit facility	(706,000		)	(559,000		)
Available capacity under the revolving credit facility	$	144,000		$	291,000

The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict our ability (as well as the ability of our restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions of 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 our 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, we are 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 June 30, 2015, we are in compliance with the covenants required under the 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 our total leverage ratio. As of June 30, 2015, the weighted average interest rate on outstanding borrowings was 1.94%.

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 consolidated balance sheets as of June 30, 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)
June 30, 2015	$	—	$	706,000	$	—	$	706,000	$	706,000
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 June 30, 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 June 30, 2015.

10. Partnership Equity and Distributions

February Public Offering

On February 27, 2015, we 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 $492.4 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.

Distributions to Holders of Common Units, Subordinated Units, General Partner Units and Incentive Distribution Rights

Our partnership agreement requires us to distribute our available cash, as defined below, to unitholders of record on the applicable record date within 45 days after the end of each quarter, beginning with the quarter ended June 30, 2013. Our partnership agreement provides that available cash, each quarter, is first distributed to the common unitholders and the general partner on a pro rata basis until each common unitholder has received $0.2875 per unit, which amount is defined in our partnership agreement as the minimum quarterly distribution ("MQD").

The following table shows the distributions for the periods indicated:



		Distributions
		Limited Partners Common and Subordinated Units		General Partner						Distributions per Limited Partner Unit
Three Months Ended	Date Paid	Limited Partners Common and Subordinated Units		Incentive Distribution Rights		General Partner Units		Total		Distributions per Limited Partner Unit
		(in thousands, except per unit amounts)
June 30, 2015	August 14, 2015 ⁽¹⁾	$	35,135	$	10,418	$	627	$	46,180	$	0.5800
March 31, 2015	May 14, 2015	31,322		6,934		530		38,786		0.5200
December 31, 2014	February 13, 2015	23,782		4,039		473		28,294		0.4850
September 30, 2014	November 14, 2014	20,092		1,208		363		21,663		0.4100
June 30, 2014	August 14, 2014	18,596		758		330		19,684		0.3800
March 31, 2014	May 14, 2014	13,288		126		274		13,688		0.3250


⁽¹⁾	The distribution declared on July 15, 2015 for the second quarter of 2015 will be paid on August 14, 2015 subsequent to the date of this Quarterly Report on 60,576,357 common units of record at the close of business on July 31, 2015.

Subordinated Units

Under the terms of TEP's partnership agreement and upon the payment of the quarterly cash distribution to unitholders on February 13, 2015, the subordination period ended. As a result, the 16,200,000 subordinated units held by TD converted into common units on a one for one basis on February 17, 2015.

General Partner Units

As of June 30, 2015, the general partner owns an approximate 1.4% general partner interest in TEP, represented by 834,391 general partner units. Under TEP’s partnership agreement, the general partner may at any time (but is under no obligation to) contribute additional capital to TEP in order to maintain or attain a 2% general partner interest.

Incentive Distribution Rights

The general partner also owns all of the IDRs. IDRs represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the MQD and each target distribution level has been achieved. The general partner may transfer these rights separately from its general partner interest, subject to restrictions in TEP’s partnership agreement.

The following discussion related to incentive distributions assumes that TEP’s general partner holds a 2% general partner interest and continues to own all of the IDRs.

If for any quarter:


•	TEP has distributed available cash from operating surplus to all of the common unitholders (and during the subordination period, to the subordinated unitholders) in an amount equal to the MQD for each outstanding unit for such quarter; and


•	TEP has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in the payment of the MQD to common unitholders;

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


•	first, 98% to all unitholders, pro rata, and 2% to TEP’s general partner, until each unitholder receives a total of $0.3048 per unit for that quarter (the "first target distribution");


•	second, 85% to all unitholders, pro rata, and 15% to TEP’s general partner, until each unitholder receives a total of $0.3536 per unit for that quarter (the "second target distribution");


•	third, 75% to all unitholders, pro rata, and 25% to TEP’s general partner, until each unitholder receives a total of $0.4313 per unit for that quarter (the "third target distribution"); and


•	thereafter, 50% to all unitholders, pro rata, and 50% to TEP’s general partner.

Definition of Available Cash

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


•	less, the amount of cash reserves established by TEP’s general partner to:


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


▪	comply with applicable law or regulation, or any of TEP’s debt instruments or other agreements; or

▪

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


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

Other Contributions and Distributions

During the six months ended June 30, 2015, TEP was deemed to have made a noncash capital distribution of $324.3 million to the general partner, which represents the excess purchase price over the carrying value of the additional 33.3% membership interest in Pony Express acquired effective March 1, 2015. See Note 4 - Acquisitions for additional information regarding the transaction. TEP also recognized contributions from noncontrolling interests of $68.7 million, which consisted primarily of contributions from TD to Pony Express to fund construction of the lateral in Northeast Colorado, and distributions to noncontrolling interests of $22.6 million.

During the six months ended June 30, 2014, the Trailblazer Predecessor and Pony Express Predecessor recognized net contributions from TD of $460.4 million. TEP also recognized a $27.5 million contribution from TD representing the difference between the carrying amount of the Replacement Gas Facilities, as discussed in Note 13 – Regulatory Matters, and the proceeds received from TD.

11. Net Income per Limited Partner Unit

The Partnership’s net income is allocated to the general partner and the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income, less general partner incentive distributions, by the weighted average number of outstanding limited partner units during the period.

We compute earnings per unit using the two-class method for Master Limited Partnerships as prescribed in the FASB guidance. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement and as further prescribed in the FASB guidance under the two-class method.

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights (which are currently held by our general partner), even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.

Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.

All net income or loss from Trailblazer prior to its acquisition on April 1, 2014 and Pony Express prior to its acquisition effective September 1, 2014 is allocated to predecessor operations in the table below. Historical earnings of transferred businesses for periods prior to the date of those common control drop-down transactions are solely those of the general partner and, therefore we have appropriately excluded any allocation to the limited partner units when determining net income available to common and subordinated unitholders. We present the financial results of any transferred business prior to the drop down transaction date in the line item "Predecessor operations interest in net (income) loss" in the table below.

The following table illustrates the Partnership’s calculation of net income per common and subordinated unit for the three and six months ended June 30, 2015 and 2014:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands, except per unit amounts)
Net income	$	53,231		$	14,728		$	76,221		$	31,345
Net (income) loss attributable to noncontrolling interests	(8,332		)	558			997			1,065
Net income attributable to partners	44,899			15,286			77,218			32,410
Predecessor operations interest in net loss (income)	—			1,581			—			(2,643		)
General partner interest in net income	(11,030		)	(1,096		)	(18,468		)	(1,477		)
Common and subordinated unitholders' interest in net income	$	33,869		$	15,771		$	58,750		$	28,290
Basic net income per common and subordinated unit	$	0.56		$	0.39		$	1.04		$	0.70
Diluted net income per common and subordinated unit	$	0.55		$	0.38		$	1.02		$	0.68
Basic average number of common and subordinated units outstanding	60,362			40,885			56,566			40,694
Equity Participation Unit equivalent units	863			1,020			838			930
Diluted average number of common and subordinated units outstanding	61,225			41,905			57,404			41,624

12. Equity-Based Compensation

For additional information regarding our Long-term Incentive Plan ("LTIP"), see Note 15 – Equity-Based Compensation to our Consolidated Financial Statements included in Part II of the 2014 Form 10-K/A.

The following table summarizes the changes in the equity participation units ("EPUs") outstanding for the six months ended June 30, 2015:



	Six Months Ended June 30, 2015
	Equity Participation Units		Weighted Average Grant Date Fair Value
Beginning of period	1,525,750		$	18.75
Granted	109,333		41.75
Vested ⁽¹⁾	(477,387	)	(19.30		)
Forfeited	(35,496	)	(17.06		)
End of period	1,122,200		$	20.90


⁽¹⁾	During the six months ended June 30, 2015, approximately 342,252 common units (net of tax withholding of approximately 135,135 common units) were issued in connection with the settlement of vested awards.

13. Regulatory Matters

There are currently no proceedings challenging the rates of Pony Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT"), or Trailblazer. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable regulations, to challenge the rates that we charge at our regulated entities. 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 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 the 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

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.

On May 18, 2015, Pony Express filed with the FERC to implement tariff contract rates for Pony Express’ newly constructed lateral in Northeast Colorado effective June 1, 2015.

On May 29, 2015, tariff filings were made with the FERC in Docket No. IS15-492-000 to increase the Pony Express local contract rates for service from the Guernsey origin, and for local non-contract rates from all origins, by amounts reflecting the FERC annual index adjustment of approximately 4.6% effective July 1, 2015. A tariff filing was also made in Docket No. IS15-493-000 on that date to increase joint tariff contract rates for service on Pony Express, Belle Fourche Pipeline Company, and Bridger Pipeline, LLC by approximately 4.6% effective July 1, 2015.

14. 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 reserves for legal claims of approximately $0.6 million as of June 30, 2015 and December 31, 2014.

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.

Environmental, Health and Safety

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 reserves of $5.1 million and $5.3 million at June 30, 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 and the possible inclusion of TIGT as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant site.

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.

TIGT

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 do not believe the cost of anticipated remediation activities will be material.

Trailblazer

Pipeline Integrity Management Program

Trailblazer recently completed smart tool surveys and preliminary analysis on segments of its natural gas pipeline to evaluate the growth rate of corrosion downstream of compressor stations. Trailblazer currently believes that approximately 25 - 35 miles of pipe will likely need to be repaired or replaced in order for the pipeline to operate at its maximum allowable operating pressure of 1,000 pounds per square inch, or psig. Such repair or replacement may occur over a period of years, depending upon final assessment of corrosion growth rates and the remediation and repair plan adopted by Trailblazer. Until then, Trailblazer is operating at a reduced pressure, public notice of which was first provided in June 2014. The current pressure reduction is not expected to prevent Trailblazer from fulfilling its firm service obligations at existing subscription levels and to date it has not had a material adverse financial impact on TEP.

During 2015, Trailblazer is scheduled to complete approximately 25 excavation digs at an aggregate cost of approximately $850,000 (all of which is included in Trailblazer’s 2015 budget) to confirm the corrosion growth rates suggested by the smart tool surveys and preliminary analysis. Segments of the Trailblazer Pipeline that require full replacement are currently expected to cost in the range of approximately $2.2 million to $2.7 million per mile. Repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. Trailblazer is currently devising a remediation and repair plan, which involves, among other things, finalizing cost recovery options, establishing project scope and timing and setting an overall project budget. Trailblazer is currently exploring all possible cost recovery options. It may not ultimately be able to recover any or all of such out of pocket costs unless and until Trailblazer recovers them through a general rate increase or other FERC-approved recovery mechanism, or through negotiated rate agreements with its customers.

In connection with TEP’s acquisition of the Trailblazer Pipeline, TD 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 TD is currently capped at $20 million and is subject to TEP’s first paying an annual $1.5 million deductible.

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.

15. 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 consider Adjusted EBITDA our primary segment performance measure as we believe it is the most meaningful measure to assess our financial condition and results of operations as a public entity. We define Adjusted EBITDA, a non-GAAP measure, as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments.

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



	Three Months Ended June 30, 2015							Three Months Ended June 30, 2014
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)							(in thousands)
Natural Gas Transportation & Logistics	$	30,969	$	(1,344	)	$	29,625	$	33,940	$	(1,330	)	$	32,610
Crude Oil Transportation & Logistics	75,219		—			75,219		—		—			—
Processing & Logistics	28,126		—			28,126		44,710		—			44,710
Corporate and Other	—		—			—		—		—			—
Total Revenue	$	134,314	$	(1,344	)	$	132,970	$	78,650	$	(1,330	)	$	77,320



	Six Months Ended June 30, 2015							Six Months Ended June 30, 2014
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
			(in thousands)							(in thousands)
Natural Gas Transportation & Logistics	$	64,579	$	(2,690	)	$	61,889	$	73,571	$	(2,585	)	$	70,986
Crude Oil Transportation & Logistics	125,600		—			125,600		—		—			—
Processing & Logistics	60,156		—			60,156		101,113		—			101,113
Corporate and Other	—		—			—		—		—			—
Total Revenue	$	250,335	$	(2,690	)	$	247,645	$	174,684	$	(2,585	)	$	172,099



	Three Months Ended June 30, 2015									Three Months Ended June 30, 2014
Adjusted EBITDA:	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA
	(in thousands)									(in thousands)
Natural Gas Transportation & Logistics	$	16,591		$	(1,344	)	$	15,247		$	15,066		$	(1,330	)	$	13,736
Crude Oil Transportation & Logistics	46,320			1,344			47,664			—			—			—
Processing & Logistics	7,077			—			7,077			5,511			—			5,511
Corporate and Other	(1,036		)	—			(1,036		)	(625		)	—			(625		)
Reconciliation to Net Income:
Interest expense, net							3,893									2,139
Depreciation and amortization expense, net of noncontrolling interest							18,302									8,874
Non-cash loss (gain) related to derivative instruments							131									(96		)
Non-cash compensation expense							1,727									1,308
Distributions from unconsolidated investment							—									772
Equity in earnings of unconsolidated investment							—									(273		)
Gain on remeasurement of unconsolidated investment							—									(9,388		)
Net income attributable to partners							$	44,899								$	15,286



	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
Adjusted EBITDA:	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA
	(in thousands)									(in thousands)
Natural Gas Transportation & Logistics	$	35,837		$	(2,690	)	$	33,147		$	34,928		$	(2,585	)	$	32,343
Crude Oil Transportation & Logistics	71,826			2,690			74,516			—			—			—
Processing & Logistics	15,795			—			15,795			15,107			—			15,107
Corporate and Other	(1,671		)	—			(1,671		)	(1,250		)	—			(1,250		)
Reconciliation to Net Income:
Interest expense, net							7,333									3,433
Depreciation and amortization expense, net of noncontrolling interest							38,835									16,678
Non-cash loss from asset sales							4,483									—
Non-cash loss related to derivative instruments							41									255
Non-cash compensation expense							3,254									2,249
Distributions from unconsolidated investment							—									1,280
Equity in earnings of unconsolidated investment							—									(717		)
Non-cash loss allocated to noncontrolling interest							(9,377		)							—
Gain on remeasurement of unconsolidated investment							—									(9,388		)
Net income attributable to partners							$	77,218								$	32,410



	Six Months Ended June 30,
Capital Expenditures:	2015		2014
	(in thousands)
Natural Gas Transportation & Logistics	$	7,061	$	13,956
Crude Oil Transportation & Logistics	32,501		459,457
Processing & Logistics	9,982		5,896
Corporate and Other	—		—
Total capital expenditures	$	49,544	$	479,309



Assets:	June 30, 2015		December 31, 2014
	(in thousands)
Natural Gas Transportation & Logistics	$	716,147	$	716,106
Crude Oil Transportation & Logistics	1,423,163		1,394,793
Processing & Logistics	336,818		340,620
Corporate and Other	5,314		5,678
Total assets	$	2,481,442	$	2,457,197

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

As used in this Quarterly Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEP" and similar terms refer to Tallgrass Energy Partners, LP, together with its consolidated subsidiaries. The term our "general partner" refers to Tallgrass MLP GP, LLC. References to "TD" refer to Tallgrass Development, LP. Historical periods have been recast to reflect the operations of Trailblazer Pipeline Company LLC ("Trailblazer"), which was acquired on April 1, 2014, and Tallgrass Pony Express Pipeline, LLC ("Pony Express"), of which TEP acquired a controlling 33.3% membership interest effective September 1, 2014. TEP's subsequent acquisition of an additional 33.3% membership interest in Pony Express

on March 1, 2015 represents an acquisition of noncontrolling interests. As a result, financial information for periods prior to that transaction have not been recast to reflect the additional 33.3% membership interest. 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 was owned by TD from November 13, 2012 to March 31, 2014, and Pony Express was wholly-owned by TD from November 13, 2012 to August 31, 2014.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report. Additionally, the following discussion and analysis should be read in conjunction with the audited 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 TEP's "Business" in our Annual Report on Form 10-K/A for the year ended December 31, 2014 (our "2014 Form 10-K/A") filed with the United States Securities and Exchange Commission on June 4, 2015.

A reference to a "Note" herein refers to the accompanying Notes to Consolidated 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

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, Colorado, and the surrounding regions 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.

Recent Developments

Distribution Declared

On July 15, 2015, the Board of Directors of our general partner declared a cash distribution for the quarter ended June 30, 2015 of $0.58 per common unit. The distribution will be paid on August 14, 2015, to unitholders of record on July 31, 2015.

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 into 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, contract profile and volumes, operating costs and expenses, Adjusted EBITDA and distributable cash flow. Adjusted EBITDA and distributable cash flow are non-GAAP measures and are defined below.

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, cost of 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.

Adjusted EBITDA and Distributable Cash Flow

Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:


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


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


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


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

We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, nor should Adjusted EBITDA and distributable cash flow be considered alternatives to available cash, operating surplus, distributions of available cash from operating surplus or other definitions in our partnership agreement. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Non-GAAP Financial Measures

We define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments. We also use distributable cash flow, which we define as Adjusted EBITDA, plus preferred distributions received from Pony Express in excess of its distributable cash flow attributable to our net interest and adjusted for deficiency payments received from or utilized by Pony Express shippers, less cash interest expense, maintenance capital expenditures, and distributions to noncontrolling interests in excess of earnings allocated to noncontrolling interests, to analyze our performance. Maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements.

TEP receives a minimum quarterly preference payment from Pony Express of $36.65 million through the quarter ending December 31, 2015 (prorated to approximately $23.5 million for the quarter ended March 31, 2015). To the extent that Pony Express does not have sufficient distributable cash flow to cover this preference payment, TD, as the noncontrolling interest owner, is required to contribute cash to Pony Express to fund the excess preference payment. The cash received by Pony Express from TD to fund the minimum quarterly preference payment in excess of distributable cash flow from Pony Express is considered distributable cash flow at TEP. Pony Express collects deficiency payments for barrels committed by the customer to be transported in a month but not physically received for transport or delivered to the customers' agreed upon destination point. These deficiency payments are recorded as a deferred liability until the barrels are physically transported and delivered by TEP. As discussed further in Note 2 – Summary of Significant Accounting Policies, earnings at Pony Express are allocated between TEP and noncontrolling interests in accordance with a substantive profit sharing arrangement rather than pro rata by ownership. Distributions made by Pony Express to its noncontrolling interests reduce the distributable cash flow available to TEP.

Distributable cash flow and Adjusted EBITDA are not presentations made in accordance with GAAP. The following table presents a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities and a reconciliation of distributable cash flow to net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
Net income attributable to partners	$	44,899		$	15,286		$	77,218		$	32,410
Add:
Interest expense, net of noncontrolling interest	3,893			2,139			7,333			3,433
Depreciation and amortization expense, net of noncontrolling interest	18,302			8,874			38,835			16,678
Non-cash loss from asset sales	—			—			4,483			—
Non-cash loss (gain) related to derivative instruments	131			(96		)	41			255
Non-cash compensation expense	1,727			1,308			3,254			2,249
Distributions from unconsolidated investment	—			772			—			1,280
Less:
Gain on remeasurement of unconsolidated investment	—			(9,388		)	—			(9,388		)
Non-cash loss allocated to noncontrolling interest	—			—			(9,377		)	—
Equity in earnings of unconsolidated investment	—			(273		)	—			(717		)
Adjusted EBITDA	$	68,952		$	18,622		$	121,787		$	46,200
Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	63,579		$	3,522		$	112,218		$	31,125
Add:
Interest expense, net of noncontrolling interest	3,893			2,139			7,333			3,433
Other, including changes in operating working capital	1,480			12,961			2,236			11,642
Adjusted EBITDA	$	68,952		$	18,622		$	121,787		$	46,200
Less:
Maintenance capital expenditures	(3,067		)	(2,531		)	(4,578		)	(3,472		)
Cash interest expense	(3,482		)	(1,909		)	(6,513		)	(3,082		)
Pony Express deficiency payments received, net	3,416			—			3,708			—
Distributions to noncontrolling interest in excess of earnings	(8,894		)	—			(10,997		)	—
Cash flow attributable to predecessor operations	—			1,330			—			(4,052		)
Distributable Cash Flow	$	56,925		$	15,512		$	103,407		$	35,594

The following table presents a reconciliation of Adjusted EBITDA by segment to segment operating income, the most directly comparable GAAP financial measure, for each of the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)
Reconciliation of Adjusted EBITDA to Operating Income in the Natural Gas Transportation & Logistics Segment ⁽¹⁾
Operating income	$	9,937		$	8,318		$	22,490		$	21,284
Add:
Depreciation and amortization expense	5,754			6,115			11,825			11,720
Non-cash loss (gain) related to derivative instruments	131			(96		)	41			255
Other income, net	769			729			1,481			1,669
Segment Adjusted EBITDA	$	16,591		$	15,066		$	35,837		$	34,928
Reconciliation of Adjusted EBITDA to Operating Income in the Crude Oil Transportation & Logistics Segment ⁽¹⁾
Operating income (loss)	$	45,515		$	(757	)	$	59,788		$	(1,514	)
Add:
Depreciation and amortization expense, net of noncontrolling interest	9,196			252			20,429			504
Adjusted EBITDA attributable to noncontrolling interests	(8,391		)	505			(8,391		)	1,010
Segment Adjusted EBITDA	$	46,320		$	—		$	71,826		$	—
Reconciliation of Adjusted EBITDA to Operating Income in the Processing & Logistics Segment ⁽¹⁾
Operating income	$	3,666		$	2,177		$	4,720		$	9,318
Add:
Depreciation and amortization expense, net of noncontrolling interest	3,352			2,507			6,581			4,454
Non-cash loss from asset sales	—			—			4,483			—
Distributions from unconsolidated investment	—			772			—			1,280
Adjusted EBITDA attributable to noncontrolling interests	59			55			11			55
Segment Adjusted EBITDA	$	7,077		$	5,511		$	15,795		$	15,107
Total Segment Adjusted EBITDA	$	69,988		$	20,577		$	123,458		$	50,035
Corporate general and administrative costs	(1,036		)	(625		)	(1,671		)	(1,250		)
Elimination of intersegment activity	—			(1,330		)	—			(2,585		)
Total Adjusted EBITDA	$	68,952		$	18,622		$	121,787		$	46,200


⁽¹⁾	Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for the Natural Gas Transportation & Logistics, Crude Oil Transportation & Logistics, and Processing & Logistics segments. For reconciliations to the consolidated financial data, see Note 15 – Reporting Segments to the accompanying consolidated financial statements.

Results of Operations

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands, except operating data)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	20,011		$	39,042		$	41,880		$	92,757
Natural gas transportation services	29,041			30,569			61,189			64,673
Crude oil transportation services	74,022			—			124,403			—
Processing and other revenues	9,896			7,709			20,173			14,669
Total Revenues	132,970			77,320			247,645			172,099
Operating Costs and Expenses:
Cost of sales	17,180			37,214			36,773			85,420
Cost of transportation services	13,492			5,288			24,207			10,405
Operations and maintenance	12,408			10,055			21,983			18,068
Depreciation and amortization	20,355			9,525			40,960			17,834
General and administrative	13,451			7,124			26,140			13,773
Taxes, other than income taxes	(271		)	1,639			11,026			3,595
Loss on sale of assets	—			—			4,483			—
Total Operating Costs and Expenses	76,615			70,845			165,572			149,095
Operating Income	56,355			6,475			82,073			23,004
Other (Expense) Income:
Interest expense, net	(3,893		)	(2,137		)	(7,333		)	(3,433		)
Gain on remeasurement of unconsolidated investment	—			9,388			—			9,388
Equity in earnings of unconsolidated investment	—			273			—			717
Other income, net	769			729			1,481			1,669
Total Other (Expense) Income	(3,124		)	8,253			(5,852		)	8,341
Net income	53,231			14,728			76,221			31,345
Net (income) loss attributable to noncontrolling interests	(8,332		)	558			997			1,065
Net income attributable to partners	$	44,899		$	15,286		$	77,218		$	32,410
Other Financial Data:⁽¹⁾
Adjusted EBITDA	$	68,952		$	18,622		$	121,787		$	46,200
Operating Data:
Gas transportation firm contracted capacity (MMcf/d)	1,520			1,494			1,564			1,549
Crude oil transportation average throughput (Bbls/d)	237,184			N/A			201,495			N/A
Natural gas processing inlet volumes (MMcf/d)	130			136			138			144


⁽¹⁾	For more information regarding Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable GAAP measure, please see "Non-GAAP Financial Measures" above.

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

Revenues. Total revenues were $133.0 million for the three months ended June 30, 2015, compared to $77.3 million for the three months ended June 30, 2014, which represents an increase of $55.7 million, or 72%, in total revenues. The overall increase in revenue was largely driven by revenues of $75.2 million in the Crude Oil Transportation & Logistics segment for the three months ended June 30, 2015. There were no revenues in that segment for the three months ended June 30, 2014 as Pony Express had not yet commenced commercial operations. The Crude Oil Transportation & Logistics segment revenue was partially offset by decreased revenues of $16.6 million and $3.0 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively.

Operating costs and expenses. Operating costs and expenses were $76.6 million for the three months ended June 30, 2015 compared to $70.8 million for the three months ended June 30, 2014, which represents an increase of $5.8 million, or 8%. The increase in operating costs and expenses is primarily driven by increased operating costs and expenses of $28.9 million at Pony Express, reflecting the commencement of commercial operations at Pony Express, partially offset by decreased operating costs and expenses of $18.1 million and $4.6 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, primarily driven by decreased cost of sales related to lower natural gas and NGL prices.

Interest expense, net. Interest expense of $3.9 million and $2.1 million for the three months ended June 30, 2015 and 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 increased borrowings during the three months ended June 30, 2015 to fund a portion of the acquisition of an additional 33.3% membership interest in Pony Express.

Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.3 million for the three months ended June 30, 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 June 30, 2015 was $0.8 million compared to $0.7 million for the three months ended June 30, 2014.

Net (income) loss attributable to noncontrolling interests. Net income attributable to noncontrolling interests of $8.3 million for the three months ended June 30, 2015 primarily reflects income attributable to TD's 33.3% membership interest in Pony Express. The net loss attributable to noncontrolling interests of $0.6 million for the three months ended June 30, 2014 primarily reflects TD's 66.7% noncontrolling interest of the amortization of use rights at Pony Express prior to commencement of commercial operations.

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Revenues. Total revenues were $247.6 million for the six months ended June 30, 2015, compared to $172.1 million for the six months ended June 30, 2014, which represents an increase of $75.5 million, or 44%, in total revenues. The overall increase in revenue was largely driven by revenues of $125.6 million in the Crude Oil Transportation & Logistics segment for the six months ended June 30, 2015. There were no revenues in that segment for the six months ended June 30, 2014 as Pony Express had not yet commenced commercial operations. The Crude Oil Transportation & Logistics segment revenue was partially offset by decreased revenues of $41.0 million and $9.0 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively.

Operating costs and expenses. Operating costs and expenses were $165.6 million for the six months ended June 30, 2015 compared to $149.1 million for the six months ended June 30, 2014, which represents an increase of $16.5 million, or 11%. The overall increase in operating costs and expenses is primarily driven by increased operating costs and expenses of $64.3 million at Pony Express, reflecting the commencement of commercial operations at Pony Express, partially offset by decreased operating costs and expenses of $36.4 million and $10.2 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, primarily driven by decreased cost of sales related to lower natural gas and NGL prices and lower costs of gas transportation services.

Interest expense, net. Interest expense of $7.3 million for the six months ended June 30, 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 $3.4 million for the six months ended June 30, 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 increased borrowings during the six months ended June 30, 2015 to fund a portion of the acquisition of an additional 33.3% membership interest in Pony Express.

Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.7 million for the six months ended June 30, 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 six months ended June 30, 2015 was $1.5 million compared to $1.7 million for the six months ended June 30, 2014.

Net (income) loss attributable to noncontrolling interests. Net loss attributable to noncontrolling interests of $1.0 million for the six months ended June 30, 2015 primarily reflects the net loss allocated to TD's 66.7% noncontrolling interest in Pony Express for the period from January 1, 2015 to February 28, 2015 and TD's 33.3% noncontrolling interest for the period from March 1, 2015 to June 30, 2015. Net loss attributable to noncontrolling interest of $1.1 million for the six months ended June 30, 2014 primarily reflects TD's 66.7% noncontrolling interest of the amortization of use rights at Pony Express prior to commencement of commercial operations.

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 June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	574		$	2,022	$	679		$	6,138
Natural gas transportation services	30,385			31,899		63,879			67,258
Processing and other revenues	10			19		21			175
Total revenues	30,969			33,940		64,579			73,571
Operating costs and expenses:
Cost of sales	(203		)	1,846		(129		)	5,673
Cost of transportation services	2,794			5,265		6,110			10,382
Operations and maintenance	7,359			6,648		13,099			12,697
Depreciation and amortization	5,754			6,115		11,825			11,720
General and administrative	4,424			4,191		8,685			8,383
Taxes, other than income taxes	904			1,557		2,499			3,432
Total operating costs and expenses	21,032			25,622		42,089			52,287
Operating income	$	9,937		$	8,318	$	22,490		$	21,284


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 15 – Reporting Segments to the accompanying condensed consolidated financial statements.

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

Revenues. Natural Gas Transportation & Logistics segment revenues were $31.0 million for the three months ended June 30, 2015, compared to $33.9 million for the three months ended June 30, 2014, which represents a $3.0 million, or 9%, decrease in segment revenues primarily driven by a $1.5 million decrease in natural gas transportation services revenue driven by lower fuel reimbursements as a result of decreased prices and a $1.4 million decrease in revenue from the sales of natural gas, NGLs, and crude oil as a result of lower volumes sold and a 39% decrease in natural gas prices.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $21.0 million for the three months ended June 30, 2015 compared to $25.6 million for the three months ended June 30, 2014, which represents a decrease of $4.6 million, or 18%.

Cost of sales decreased $2.0 million, or 111%, in the three months ended June 30, 2015 when compared to the same period in the prior year primarily due to decreased volumes of natural gas sold and a 31% decrease in prices. Cost of sales during the three months ended June 30, 2015 were negative due to a reduction in our fuel tracker obligations at Trailblazer driven by the FERC approval of our annual fuel tracker filing and decreased prices during the period.

Cost of transportation services decreased $2.5 million, or 47%, in the three months ended June 30, 2015 when compared to the same period in the prior year, primarily due to lower fuel reimbursements and fuel recoveries as a result of decreased volumes and prices.

Operations and maintenance costs increased $0.7 million, or 11%, in the three months ended June 30, 2015 when compared to the same period in the prior year due to increased pipeline integrity work during the three months ended June 30, 2015.

Depreciation and amortization decreased $0.4 million, or 6%, in the three months ended June 30, 2015 when compared to the same period in the prior year as a result of an asset group which was fully depreciated during the first quarter of 2015.

General and administrative costs increased $0.2 million, or 6%, in the three months ended June 30, 2015 when compared to the same period in the prior year.

Taxes, other than income taxes, decreased $0.7 million, or 42%, in the three months ended June 30, 2015 when compared to the same period in the prior year, primarily due to revised property tax estimates as a result of successful appeals with state taxing authorities on the assessed value of property.

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Revenues. Natural Gas Transportation & Logistics segment revenues were $64.6 million for the six months ended June 30, 2015, compared to $73.6 million for the six months ended June 30, 2014, which represents a $9.0 million, or 12%, decrease in segment revenues primarily driven by a $5.5 million decrease in revenue from the sales of natural gas, NGLs, and crude oil as a result of lower volumes sold and a 45% decrease in natural gas prices and a $3.4 million decrease in natural gas transportation services revenue primarily driven by lower fuel reimbursements as a result of decreased prices.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $42.1 million for the six months ended June 30, 2015 compared to $52.3 million for the six months ended June 30, 2014, which represents a decrease of $10.2 million, or 20%.

Cost of sales decreased $5.8 million, or 102%, in the six months ended June 30, 2015 when compared to the same period in the prior year, due to lower volumes of natural gas sales and 31% lower prices. Cost of sales during the six months ended June 30, 2015 were negative due to a reduction in our fuel tracker obligations at Trailblazer driven by the FERC approval of our annual fuel tracker filing and decreased prices during the period.

Cost of transportation services decreased $4.3 million, or 41%, in the six months ended June 30, 2015 when compared to the same period in the prior year, primarily due to lower fuel reimbursements as a result of decreased prices and lower fuel recoveries as a result of decreased volumes and prices.

Operations and maintenance costs increased $0.4 million, or 3%, in the six months ended June 30, 2015 when compared to the same period in the prior year due to increased pipeline integrity work during the six months ended June 30, 2015.

Depreciation and amortization increased $0.1 million, or 1%, in the six months ended June 30, 2015 when compared to the same period in the prior year.

General and administrative costs increased $0.3 million, or 4%, in the six months ended June 30, 2015 when compared to the same period in the prior year.

Taxes, other than income taxes, decreased $0.9 million, or 27%, in the six months ended June 30, 2015 when compared to the same period in the prior year, primarily due to revised property tax estimates 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 June 30,						Six Months Ended June 30,
	2015			2014			2015		2014
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	1,197		$	—		$	1,197	$	—
Crude Oil transportation services	74,022			—			124,403		—
Total revenues	75,219			—			125,600		—
Operating costs and expenses:
Cost of sales	986			—			986		—
Cost of transportation services	11,528			—			20,237		—
Operations and maintenance	2,015			—			3,430		—
Depreciation and amortization	11,301			757			22,534		1,514
General and administrative	5,155			—			10,310		—
Taxes, other than income taxes	(1,281		)	—			8,315		—
Total operating costs and expenses	29,704			757			65,812		1,514
Operating income (loss)	$	45,515		$	(757	)	$	59,788	$	(1,514	)


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 15 – Reporting Segments to the accompanying condensed consolidated financial statements.

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

Revenues. Crude Oil Transportation & Logistics segment revenues of $75.2 million for the three months ended June 30, 2015 represents transportation revenue at Pony Express, which was placed in service in October 2014 and the start of commercial operations at the lateral in Northeast Colorado during the second quarter of 2015. There were no revenues for the three months ended June 30, 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 $29.7 million for the three months ended June 30, 2015 compared to $0.8 million for the three months ended June 30, 2014. Operating costs and expenses for the three months ended June 30, 2015 include costs associated with the start of commercial operations in October 2014 and the start of commercial operations at the lateral in Northeast Colorado during the second quarter of 2015, as well as the amortization of the Pony Express oil conversion use rights. Pony Express recognized a net credit in taxes, other than income taxes of $1.3 million as a result of revised property tax estimates as a result of successful appeals with state taxing authorities on the assessed value of property. For the three months ended June 30, 2014, operating costs and expenses consisted of the amortization of the Pony Express oil conversion use rights.

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Revenues. Crude Oil Transportation & Logistics segment revenues of $125.6 million for the six months ended June 30, 2015 represents transportation revenue at Pony Express, which was placed in service in October 2014 and the start of commercial operations at the lateral in Northeast Colorado during the second quarter of 2015. There were no revenues for the six months ended June 30, 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 $65.8 million for the six months ended June 30, 2015 compared to $1.5 million for the six months ended June 30, 2014. Operating costs and expenses for the six months ended June 30, 2015 include costs associated with the start of commercial operations in October 2014 and the start of commercial operations at the lateral in Northeast Colorado during the second quarter of 2015, as well as the amortization of the Pony Express oil conversion use rights. For the six months ended June 30, 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 June 30,				Six Months Ended June 30,
Segment Financial Data - Processing & Logistics ⁽¹⁾	2015		2014		2015		2014
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	18,240	$	37,020	$	40,004	$	86,619
Processing and other revenues	9,886		7,690		20,152		14,494
Total revenues	28,126		44,710		60,156		101,113
Operating costs and expenses:
Cost of sales	16,397		35,368		35,916		79,747
Cost of transportation services	514		23		550		23
Operations and maintenance	3,034		3,407		5,454		5,371
Depreciation and amortization	3,300		2,653		6,601		4,600
General and administrative	1,109		1,000		2,220		1,891
Taxes, other than income taxes	106		82		212		163
Loss on sale of assets	—		—		4,483		—
Total operating costs and expenses	24,460		42,533		55,436		91,795
Operating income	$	3,666	$	2,177	$	4,720	$	9,318


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 15 – Reporting Segments to the accompanying condensed consolidated financial statements.

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

Revenues. Processing & Logistics segment revenues were $28.1 million for the three months ended June 30, 2015, compared to $44.7 million for the three months ended June 30, 2014, which represents a $16.6 million, or 37%, decrease in segment revenues. The decrease in segment revenues was primarily due to a $18.8 million decrease in revenue from sales of natural gas, NGLs, and crude oil driven by 60% lower NGL prices, partially offset by an increase in volumes processed, and a $2.2 million increase in processing and other revenues primarily driven by increased revenue at Water Solutions, including water transportation services and revenue associated with a third party pipeline construction project during the three months ended June 30, 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 for the period from April 1, 2014 to May 13, 2014.

Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $24.5 million for the three months ended June 30, 2015 compared to $42.5 million for the three months ended June 30, 2014, which represents a decrease of $18.1 million, or 42%.

Cost of sales decreased $19.0 million, or 54%, in the three months ended June 30, 2015 when compared to the same period in the prior year, primarily driven by a 64% decrease in NGL prices.

Cost of transportation services of $0.5 million in the three months ended June 30, 2015 includes costs associated with a third party pipeline construction project as well as costs of water transportation at the Water Solutions business, which was consolidated in May 2014.

Operations and maintenance costs decreased $0.4 million, or 11%, in the three months ended June 30, 2015 when compared to the same period in the prior year, primarily driven by an environmental reserve recorded during the second quarter of 2014 and costs associated with annual plant maintenance during the second quarter of 2014 which is not scheduled to occur again until the third quarter of 2015, partially offset by operations and maintenance costs at Water Solutions, which was consolidated in May 2014.

Depreciation and amortization increased $0.6 million, or 24%, in the three months ended June 30, 2015 when compared to the same period in the prior year, primarily driven by depreciation and amortization at Water Solutions, which was consolidated in May 2014.

General and administrative costs increased $0.1 million, or 11%, in the three months ended June 30, 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 June 30, 2015 and the three months ended June 30, 2014.

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Revenues. Processing & Logistics segment revenues were $60.2 million for the six months ended June 30, 2015, compared to $101.1 million for the six months ended June 30, 2014, which represents a $41.0 million, or 41%, decrease in segment revenues. The decrease in segment revenues was primarily due to a $46.6 million decrease in the sales of natural gas, NGLs, and crude oil primarily driven by a 61% decrease in NGL prices, partially offset by an increase in volumes processed, and a $5.7 million increase in processing and other revenues primarily driven by increased revenue at Water Solutions, including water transportation services and revenue associated with a third party pipeline construction project during the six months ended June 30, 2015.

Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $55.4 million for the six months ended June 30, 2015 compared to $91.8 million for the six months ended June 30, 2014, which represents a decrease of $36.4 million, or 40%.

Cost of sales decreased $43.8 million, or 55%, in the six months ended June 30, 2015 when compared to the same period in the prior year, primarily driven by a 66% decrease in NGL prices.

Cost of transportation services of $0.6 million in the six months ended June 30, 2015 represents costs associated with a third party pipeline construction project as well as costs of water transportation at the Water Solutions business, which was consolidated in May 2014.

Operations and maintenance costs increased $0.1 million, or 2%, in the six months ended June 30, 2015 when compared to the same period in the prior year, primarily driven by operations and maintenance costs at Water Solutions, which was consolidated in May 2014, partially offset by a decrease in operations and maintenance costs due to an environmental reserve recorded during the second quarter of 2014 and costs associated with annual plant maintenance during the second quarter of 2014 which is not scheduled to occur again until the third quarter of 2015.

Depreciation and amortization increased $2.0 million, or 44%, in the six months ended June 30, 2015 when compared to the same period in the prior year, primarily driven by depreciation and amortization at Water Solutions, which was consolidated in May 2014.

General and administrative costs increased $0.3 million, or 17%, in the six months ended June 30, 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 six months ended June 30, 2015 and the six months ended June 30, 2014.

Loss on sale of assets during the six months ended June 30, 2015 represents a noncash loss recognized on the sale of compressor assets.

Liquidity and Capital Resources Overview

Our primary sources of liquidity for the three months ended June 30, 2015 were borrowings under our revolving credit facility and cash generated from operations. We expect our sources of liquidity in the future to include:


•	cash generated from our operations;


•	borrowing capacity available under our revolving credit facility; and


•	future issuances of additional partnership units and/or debt securities.

We believe that cash on hand, cash generated from operations and availability under our 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 our revolving credit facility and issuances of debt and/or equity securities.

Our total liquidity as of June 30, 2015 and December 31, 2014 was as follows:



	June 30, 2015			December 31, 2014
	(in thousands)
Cash on hand	$	1,778		$	867
Total capacity under the TEP revolving credit facility	850,000			850,000
Less: Outstanding borrowings under the TEP revolving credit facility	(706,000		)	(559,000		)
Less: Letters of credit issued under the TEP revolving credit facility	—			—
Available capacity under the TEP revolving credit facility	144,000			291,000
Total liquidity	$	145,778		$	291,867

Revolving Credit Facility

The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict our ability (as well as the ability of our 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 our 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, we are 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 June 30, 2015, we are in compliance with the covenants required under the revolving credit facility.

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 $492.4 million after deducting the underwriter's discount and offering expenses paid by TEP. We 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. We used the net proceeds from this additional purchase of common units to reduce borrowings under our 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.

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, 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 June 30, 2015, we had a working capital surplus of $5.0 million compared to a working capital surplus of $35.7 million at December 31, 2014, which represents a decrease in working capital of $30.7 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, partially offset by a decrease of $33.7 million in accounts payable, driven by the timing of project invoices and payment of contractor retainages related to the construction of the Pony Express lateral in Northeast Colorado, which was placed in service in April 2015, and an increase in accounts receivable driven by the start of commercial operations at the Pony Express lateral in Northeast Colorado and the activation of the Hiland Pipeline Company joint tariff at Pony Express.

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:



	Six Months Ended June 30,
	2015			2014
	(in thousands)
Net cash provided by (used in):
Operating activities	$	112,218		$	31,125
Investing activities	$	(754,192	)	$	(638,547	)
Financing activities	$	642,885		$	607,448

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Operating Activities. Cash flows provided by operating activities were $112.2 million and $31.1 million for the six months ended June 30, 2015 and 2014, respectively. The increase in net cash flows provided by operating activities of $81.1 million was primarily driven by the increase in operating results and a net increase in cash inflows from changes in working capital, primarily driven by a $19.3 million decrease in net cash outflows from accounts payable and accrued liabilities due to increased property tax accruals and operating payables, partially offset by a decrease in net cash inflows of $14.4 million from accounts receivable, due to increased receivables at Pony Express, and $5.2 million from changes in inventory balances.

Investing Activities. Cash flows used in investing activities were $754.2 million and $638.5 million for the six months ended June 30, 2015 and 2014, respectively. During the six months ended June 30, 2015, net cash used in investing activities were driven by the $700.0 million cash outflow for the acquisition of an additional 33.3% membership interest in Pony Express, which allowed TD to continue funding the pipeline construction at Pony Express, and capital expenditures of $49.5 million, primarily due to construction of the Pony Express System, including the lateral in Northeast Colorado. During the six months ended June 30, 2014, net cash used in investing activities was driven by $479.3 million in capital expenditures, consisting primarily of spending on the conversion and construction of the Pony Express System, and cash outflows of $150.0 million and $7.6 million, respectively, for the acquisition of Trailblazer effective April 1, 2014 and the acquisition of an additional equity interest in Water Solutions effective May 13, 2014.

Financing Activities. Cash flows provided by financing activities were $642.9 million and $607.4 million for the six months ended June 30, 2015 and 2014, respectively. Financing cash inflows for the six months ended June 30, 2015 were primarily driven by $551.7 million and $147.0 million, respectively, from the issuance of 11,200,000 TEP common units in a public offering during the six months ended June 30, 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, as well as contributions from noncontrolling interests of $16.3 million primarily driven by contributions from TD to Pony Express. These financing cash inflows were partially offset by distributions to TEP unitholders and TEP's general partner of $67.1 million. Cash flows provided by financing activities for the six months ended June 30, 2014 consisted primarily of net contributions from Predecessor Members of $460.4 million, driven by contributions from TD to Pony Express to fund the conversion and construction of the Pony Express System, proceeds from net borrowings under the TEP revolver of $146.0 million, and a $27.5 million contribution from TD representing the difference between the carrying amount of the Replacement Gas Facilities, as discussed in Note 13 – Regulatory Matters, and the proceeds received from TD. These financing cash inflows were partially offset by distributions to TEP unitholders of $26.8 million.

Distributions

We intend to pay quarterly distributions at or above the amount of the MQD, which is $0.2875 per unit. As of July 30, 2015, we had a total of 61,410,748 common and general partner units outstanding, which equates to an aggregate MQD of approximately $17.7 million per quarter and approximately $70.6 million per year. We do not have a legal obligation to pay distributions except as provided in our partnership agreement. A distribution of $0.58 per unit for the three months ended June 30, 2015 was declared on July 15, 2015 and will be paid on August 14, 2015 to unitholders of record on July 31, 2015.

We believe that we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow. A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

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 $209 million for capital expenditures in 2015, of which approximately $176 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 $20 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:



	Six Months Ended June 30,
	2015		2014
	(in thousands)
Maintenance capital expenditures	$	4,578	$	3,472
Expansion capital expenditures	117,746		485,986
Total capital expenditures incurred	$	122,324	$	489,458

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 $4.6 million for the six months ended June 30, 2015 from $3.5 million for the six months ended June 30, 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 $117.7 million for the six months ended June 30, 2015 from $486.0 million for the six months ended June 30, 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 $117.7 million for the six months ended June 30, 2015 consisted primarily of spending on the Pony Express System lateral in Northeast Colorado.

In addition, we invested cash in unconsolidated affiliates of $2.0 million during the six months ended June 30, 2014 to fund our share of capital expansion projects. There were no investments in unconsolidated affiliates during the six months ended June 30, 2015.

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

Contractual Obligations

There have been no material changes in our contractual obligations as reported in our 2014 Form 10-K/A.

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 consolidated financial statements are set forth in our 2014 Form 10-K/A for the year ended December 31, 2014 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 June 30, 2015 approximately 90% of our reserved processing capacity was subject to fee-based processing contracts, with the remaining 10% 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 10% and 13% of our Adjusted EBITDA for the three and six months ended June 30, 2015, 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 June 30, 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 & Logistics segment through the end of 2015. The fair value of these swaps was a liability of approximately $41,000 at June 30, 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 June 30, 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 our debt obligations as of June 30, 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 61% 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 June 30, 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 June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Note 14 – Legal and Environmental Matters to the condensed consolidated financial statements included in Part I—Item 1.—Financial Statements of this Quarterly Report, which is incorporated here by reference.

Item 1A. Risk Factors

Item 1A of our 2014 Form 10-K/A for the year ended December 31, 2014 sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended June 30, 2015. Other than as set forth below, there have been no material changes to the risk factors contained in our 2014 Form 10-K/A for the year ended December 31, 2014.

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 ownership in TEP’s IDRs, its direct ownership of the Acquired TEP Units and its indirect ownership of TEP’s 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 Tallgrass Equity's cash flows are currently derived. Additionally, this could ultimately result in a change in control of TEP GP, which would constitute an immediate event of default under our credit facility. This would have a material adverse effect on our business, financial condition and results of operations.

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

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Tallgrass Development and its direct and indirect owners own a substantial interest in our capital and profits. Therefore, a transfer by them of all or a portion of their interests in us could result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year if the termination occurs on a day other than December 31 and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year

other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

We have a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate level income taxes and may conduct additional activities in taxable corporate subsidiaries in the future.

Even though we (as a partnership for U.S. federal income tax purposes) are not subject to U.S. federal income tax, we have a subsidiary that is organized as a corporation for U.S. federal income tax purposes. Although this subsidiary has not previously generated any material income, we may elect to conduct additional activities in one or more subsidiaries treated as corporations for U.S. federal income tax purposes in the future that could generate material income. For example, it is unclear whether and to what extent our share of water business services income from Water Solutions will be treated as qualifying income. The IRS recently issued proposed regulations providing that income from water delivery services is not qualifying income unless the partnership providing those services also collects and cleans, recycles, or otherwise disposes of the water after use in accordance with applicable law. While we have not requested a ruling from the IRS that income from Water Solutions, or a portion of such income, is qualifying income, we may request such a ruling in the future. If the treatment of water services income in the proposed regulations is adopted as final regulations or if the IRS is unwilling or unable to provide a favorable ruling in a timely manner, and if it becomes necessary or prudent in order to preserve our status as a partnership, we may elect to conduct all or portions of our Water Solutions business in a taxable corporate subsidiary (see "Risk Factors - Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.").

The taxable income, if any, of a subsidiary that is treated as a corporation for U.S. federal income tax purposes, is subject to corporate-level U.S. federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that this corporation has more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filing positions taken by corporate subsidiaries could require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment could also be required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by our corporate subsidiaries would be fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

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

None.

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

12.1*		Computation of Ratio of Earnings to Fixed Charges

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 Partners, LP
		(registrant)
		By:	Tallgrass MLP GP, LLC, its general partner

Date:	July 30, 2015	By:	/s/ Gary J. Brauchle
			Name:	Gary J. Brauchle
			Title:	Executive Vice President and Chief Financial Officer