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

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



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

For the Quarterly Period Ended September 30, 2016



¨	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 x 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 x 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 x

On November 2, 2016, the Registrant had 72,115,405 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 EQUITY	5
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	42
Item 4. Controls and Procedures	43
PART II - OTHER INFORMATION	44
Item 1. Legal Proceedings	44
Item 1A. Risk Factors	44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3. Defaults Upon Senior Securities	44
Item 4. Mine Safety Disclosures	44
Item 5. Other Information	44
Item 6. Exhibits	44
SIGNATURES	45

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.

Commodity sensitive contracts or arrangements: contracts or other arrangements, including tariff provisions, that directly expose our cash flows to increases and decreases in the price of commodities such as crude oil, natural gas and NGLs. Examples are Keep Whole Processing Contracts and Percent of Proceeds Processing Contracts, as well as pipeline loss allowances on our pipelines.

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 firm service assurance of capacity and deliverability to delivery points.

Delivery point: any point at which product in a pipeline is delivered to or for the account of a customer.

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.

FERC: Federal Energy Regulatory Commission.

Firm fee contracts: firm fee contracts generally obligate our customers to pay a fixed recurring charge to reserve an agreed upon amount of capacity and/or deliverability on our assets, regardless if the contracted capacity is actually used by the customer. Such contracts are also commonly known as "take-or-pay" contracts.

Firm services: services pursuant to which customers receive firm assurances regarding the availability of capacity and/or deliverability of natural gas, crude oil or other hydrocarbons or water on our assets up to a contracted amount.

Fractionation: the process by which NGLs are further separated into individual, typically 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.

Interruptible services: services pursuant to which customers receive limited, or no, assurances regarding the availability of capacity and deliverability in our assets.

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.

Long-term: with respect to any contract, a contract with an initial duration greater than one year.

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.

Produced water: all water removed from a well as a byproduct of the production of hydrocarbons and water removed from a well in connection with operations being conducted on the well, including naturally occurring water in the recovery formation, flow back water recovered during completion and fracturing operations and water entering the recovery formation through water flooding techniques.

Receipt point: the point where a product is received by or into a gathering system, processing facility, or transportation pipeline.

Reservoir: a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (such as 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 transportation to end-user markets.

TBtu: one trillion British Thermal Units.

Tcf: one trillion cubic feet.

Throughput: the volume of products, such as crude oil, natural gas or water, 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.

Volumetric fee contracts: volumetric fee contracts generally obligate a customer to pay fees based upon the extent to which such customer utilizes our assets for midstream energy services. Unlike firm fee contracts, under volumetric fee contracts our customers are not generally required to pay a charge to reserve an agreed upon amount of capacity and/or deliverability.

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)



	September 30, 2016			December 31, 2015
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	417		$	1,611
Accounts receivable, net	53,085			57,757
Gas imbalances	890			1,227
Inventories	13,375			13,793
Derivative assets at fair value	25,690			—
Prepayments and other current assets	3,838			2,835
Total Current Assets	97,295			77,223
Property, plant and equipment, net	2,003,532			2,025,018
Goodwill	343,288			343,288
Intangible asset, net	94,280			96,546
Unconsolidated investment	455,401			—
Deferred financing costs, net	5,676			5,105
Deferred charges and other assets	10,816			14,894
Total Assets	$	3,010,288		$	2,562,074
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)	$	17,046		$	22,218
Accounts payable to related parties	6,207			7,852
Gas imbalances	1,117			1,605
Derivative liabilities at fair value	197			—
Accrued taxes	20,676			13,844
Accrued liabilities	10,214			10,019
Deferred revenue	52,138			26,511
Other current liabilities	6,725			6,880
Total Current Liabilities	114,320			88,929
Long-term debt, net	1,398,003			753,000
Other long-term liabilities and deferred credits	7,341			5,143
Total Long-term Liabilities	1,405,344			758,143
Commitments and Contingencies
Equity:
Common unitholders (72,738,251 and 60,644,232 units issued and outstanding at September 30, 2016 and December 31, 2015, respectively)	2,094,821			1,618,766
General partner (834,391 units issued and outstanding at September 30, 2016 and December 31, 2015)	(637,945		)	(348,841		)
Total Partners' Equity	1,456,876			1,269,925
Noncontrolling interests	33,748			445,077
Total Equity	1,490,624			1,715,002
Total Liabilities and Equity	$	3,010,288		$	2,562,074

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands, except per unit amounts)
Revenues:
Crude oil transportation services	$	91,387		$	81,928		$	279,281		$	206,331
Natural gas transportation services	31,444			29,431			89,406			90,620
Sales of natural gas, NGLs, and crude oil	20,758			20,252			51,514			62,132
Processing and other revenues	8,536			6,557			24,260			26,730
Total Revenues	152,125			138,168			444,461			385,813
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	18,590			18,186			48,116			54,959
Cost of transportation services (exclusive of depreciation and amortization shown below)	13,528			14,862			43,924			39,069
Operations and maintenance	14,714			14,071			41,055			36,054
Depreciation and amortization	20,831			20,802			64,099			61,762
General and administrative	13,147			11,807			40,072			37,947
Taxes, other than income taxes	6,717			5,521			19,862			16,547
Loss on disposal of assets	—			—			1,849			4,483
Total Operating Costs and Expenses	87,527			85,249			258,977			250,821
Operating Income	64,598			52,919			185,484			134,992
Other Income (Expense):
Interest expense, net	(10,907		)	(3,871		)	(27,639		)	(11,204		)
Unrealized (loss) gain on derivative instrument	(4,419		)	—			5,588			—
Equity in earnings of unconsolidated investment	12,066			—			35,387			—
Other income, net	480			502			1,267			1,983
Total Other (Expense) Income	(2,780		)	(3,369		)	14,603			(9,221		)
Net income	61,818			49,550			200,087			125,771
Net income attributable to noncontrolling interests	(1,084		)	(6,871		)	(3,235		)	(5,874		)
Net income attributable to partners	$	60,734		$	42,679		$	196,852		$	119,897
Allocation of income to the limited partners:
Net income attributable to partners	$	60,734		$	42,679		$	196,852		$	119,897
General partner interest in net income	(27,674		)	(12,146		)	(73,347		)	(30,614		)
Common and subordinated unitholders' interest in net income	33,060			30,533			123,505			89,283
Basic net income per common and subordinated unit	$	0.45		$	0.50		$	1.75		$	1.54
Diluted net income per common and subordinated unit	$	0.45		$	0.50		$	1.73		$	1.52
Basic average number of common and subordinated units outstanding	73,089			60,576			70,686			57,917
Diluted average number of common and subordinated units outstanding	74,063			61,536			71,590			58,884

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Nine Months Ended September 30,
	2016			2015
	(in thousands)
Cash Flows from Operating Activities:
Net income	$	200,087		$	125,771
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	68,693			64,624
Equity in earnings of unconsolidated investment	(35,387		)	—
Distributions from unconsolidated investment	35,387			—
Noncash compensation expense	4,270			3,988
Noncash change in fair value of derivative financial instruments	(5,391		)	(218		)
Loss on disposal of assets	1,849			4,483
Changes in components of working capital:
Accounts receivable and other	7,924			(11,538		)
Inventories	(867		)	(5,265		)
Accounts payable and accrued liabilities	4,827			6,786
Deferred revenue	25,303			13,995
Other operating, net	(779		)	(5,142		)
Net Cash Provided by Operating Activities	305,916			197,484
Cash Flows from Investing Activities:
Capital expenditures	(45,252		)	(65,146		)
Acquisition of unconsolidated affiliate	(436,022		)	—
Acquisition of Pony Express membership interest	(49,118		)	(700,000		)
Contributions to unconsolidated investment	(35,452		)	—
Distributions from unconsolidated investment in excess of cumulative earnings	16,073			—
Other investing, net	205			(4,625		)
Net Cash Used in Investing Activities	(549,566		)	(769,771		)
Cash Flows from Financing Activities:
Acquisition of Pony Express membership interest	(425,882		)	—
Proceeds from issuance of long-term debt	400,000			—
Proceeds from public offering, net of offering costs	290,474			551,243
Borrowings under revolving credit facility, net	252,000			137,000
Distributions to unitholders	(207,539		)	(113,260		)
Partial exercise of call option	(151,434		)	—
Proceeds from private placement, net of offering costs	90,009			—
Contributions from noncontrolling interests	8,700			19,303
Other financing, net	(13,872		)	(4,161		)
Net Cash Provided by Financing Activities	242,456			590,125
Net Change in Cash and Cash Equivalents	(1,194		)	17,838
Cash and Cash Equivalents, beginning of period	1,611			867
Cash and Cash Equivalents, end of period	$	417		$	18,705

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



Schedule of Noncash Investing and Financing Activities:
Property, plant and equipment acquired via the cash management agreement with Tallgrass Development, LP	$	—	$	120,254
Contributions from noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	$	—	$	43,401
Distribution to noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	$	—	$	44,142

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)



	Limited Partners						General Partner			Total Partners’ Equity			Noncontrolling Interests			Total Equity
	Common			Subordinated			General Partner			Total Partners’ Equity			Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2016	$	1,618,766		$	—		$	(348,841	)	$	1,269,925		$	445,077		$	1,715,002
Net income	123,505			—			73,347			196,852			3,235			200,087
Issuance of units to public, net of offering costs	290,474			—			—			290,474			—			290,474
Issuance of units in a private placement, net of offering costs	90,009			—			—			90,009			—			90,009
Distributions to unitholders	(145,664		)	—			(61,875		)	(207,539		)	—			(207,539		)
Noncash compensation expense	5,931			—			—			5,931			—			5,931
Acquisition of additional 31.3% membership interest in Pony Express	268,607			—			(279,967		)	(11,360		)	(417,679		)	(429,039		)
Partial exercise of call option	(151,434		)	—			(25,858		)	(177,292		)	—			(177,292		)
Contributions from TD	—			—			5,308			5,308			—			5,308
Contributions from noncontrolling interest	—			—			—			—			8,700			8,700
Distributions to noncontrolling interest	—			—			—			—			(5,017		)	(5,017		)
Acquisition of noncontrolling interests	(5,373		)	—			(59		)	(5,432		)	(568		)	(6,000		)
Balance at September 30, 2016	$	2,094,821		$	—		$	(637,945	)	$	1,456,876		$	33,748		$	1,490,624

	Limited Partners						General Partner			Total Partners’ Equity			Noncontrolling Interests			Total 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	84,103			5,180			30,614			119,897			5,874			125,771
Issuance of units to public, net of offering costs	551,243			—			—			551,243			—			551,243
Distributions to unitholders	(82,382		)	(7,857		)	(23,021		)	(113,260		)	—			(113,260		)
Noncash compensation expense	7,325			—			—			7,325			—			7,325
LTIP units tendered by employees to satisfy tax withholding obligations	(6,562		)	—			—			(6,562		)	—			(6,562		)
Contributions from noncontrolling interest	—			—			—			—			110,553			110,553
Distributions to noncontrolling interest	—			—			—			—			(44,543		)	(44,543		)
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 September 30, 2015	$	1,625,516		$	—		$	(352,478	)	$	1,273,038		$	452,040		$	1,725,078

The accompanying notes are an integral part of these condensed 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 limited partnership formed 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 crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 25% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), a Delaware limited liability company which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio, (2) 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 (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). 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 (collectively, the "Midstream Facilities"), and NGL transportation services in Northeast Colorado. We perform water business services 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, Bakken, Marcellus and Utica shale formations.

Our reportable business segments are:


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


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


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

The table below summarizes our equity ownership as of September 30, 2016:



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 ⁽¹⁾	43,427,917	—	59.70	%	59.04	%
Tallgrass Equity, LLC	20,000,000	—	27.50	%	27.18	%
Tallgrass Development, LP ⁽²⁾	9,310,334	—	12.80	%	12.65	%
Tallgrass MLP GP, LLC⁽³⁾	—	834,391	—	%	1.13	%
Total⁽⁴⁾	72,738,251	834,391	100.00	%	100.00	%


⁽¹⁾	As discussed in Note 10 – Partnership Equity and Distributions, we issued and sold an additional 628,914 common units subsequent to September 30, 2016. As of November 2, 2016, there were 44,056,831 common units held by public unitholders outstanding.


⁽²⁾	As discussed in Note 8 – Risk Management, 1,251,760 of the common units held by Tallgrass Development, LP ("TD") as of September 30, 2016 were subsequently deemed cancelled as of October 31, 2016. As of November 2, 2016, there were 8,058,574 common units held by TD outstanding.


⁽³⁾	Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.


⁽⁴⁾	As of November 2, 2016, there were 72,949,796 total limited partner and general partner units outstanding.

2. Summary of Significant Accounting Policies

Basis of Presentation

These condensed consolidated financial statements and related notes for the three and nine months ended September 30, 2016 and 2015 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 all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three and nine months ended September 30, 2016 and 2015 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement 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 nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2016. The accompanying 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 for the year ended December 31, 2015 ("2015 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 17, 2016.

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. Prior to January 1, 2016, Pony Express participated in a cash management agreement with TD, which currently holds a 2.0% common membership interest in Pony Express, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. Effective January 1, 2016, Pony Express entered into a cash management agreement with TEP.

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 ended 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 ended 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 are 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 liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Our consolidated VIEs do not have material assets that can only be used to settle specific obligations of the consolidated VIEs. Pony Express was considered to be a VIE under the applicable authoritative guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express.

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.

Accounting Pronouncements Not Yet Adopted

Revenue Recognition

In May 2014, the FASB issued Accounting Standards Update ("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.

Throughout the first half of 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, and ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients.

The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, and ASU 2016-12 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. In light of this recently issued accounting guidance, we have started the process of reviewing our existing revenue contracts. Due to the early stage of this process, we are currently not in a position to estimate the impact the guidance will have on our consolidated financial statements. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts as of January 1, 2018 through a cumulative adjustment to equity. Consolidated revenues for periods prior to January 1, 2018 would not be revised.

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, but do not anticipate a material impact on our consolidated financial statements.

ASU No. 2016-02, "Leases (Topic 842)"

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the impact of ASU 2016-02.

ASU No. 2016-09, "Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting"

In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Among other changes, ASU 2016-09 allows an entity to make an entity-wide accounting policy election to either estimate the number of awards expected to vest (consistent with current GAAP) or account for forfeitures when they occur.

The amendments in ASU 2016-09 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 2016-09, but do not anticipate a material impact on our consolidated financial statements.

Accounting Pronouncements Recently Adopted

ASU No. 2016-15, "Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments"

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 provides explicit guidance on accounting for eight specific cash flow issues with the objective of reducing diversity in practice, including debt prepayment or debt extinguishment costs, settlement of certain debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle.

The amendments in ASU 2016-015 are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. We adopted the standard effective January 1, 2016. The adoption of ASU 2016-15 did not have a material impact on our financial position and results of operations.

ASU No. 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments"

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. ASU 2015-16 simplifies the accounting for measurement-period adjustments for provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the provisional amounts must be calculated as if the accounting had been completed at the acquisition date.

The amendments in ASU 2015-16 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2015-16 did not 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 changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 modifies the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, and changes 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. The adoption of ASU 2015-02 did not have a material impact on our financial position and results of operations.

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. The adoption of ASU 2014-12 did not have a material impact on our financial position and results of operations.

3. Acquisitions

Acquisition of a 25% Membership Interest in Rockies Express Pipeline LLC

On March 29, 2016, TD's indirect wholly owned subsidiary Rockies Express Holdings, LLC ("REX Holdings") signed a purchase agreement (the "REX Purchase Agreement") with a unit of Sempra U.S. Gas and Power ("Sempra") to acquire Sempra's 25% membership interest in Rockies Express for cash consideration of $440 million, subject to adjustment under the REX Purchase Agreement.

On April 28, 2016, we announced that TD offered TEP the right to assume the rights and obligations of REX Holdings under the REX Purchase Agreement. On May 6, 2016, TEP REX Holdings, LLC ("TEP REX"), an indirect wholly-owned subsidiary of TEP, and REX Holdings entered into an Assignment and Assumption Agreement pursuant to which REX Holdings assigned to TEP REX all of its rights under the REX Purchase Agreement and, in exchange, TEP REX assumed all of the rights and obligations of REX Holdings under the REX Purchase Agreement. Subsequently on May 6, 2016, TEP REX closed the purchase of a 25% membership interest in Rockies Express from Sempra pursuant to the REX Purchase Agreement for cash consideration of approximately $436.0 million, after making the adjustments to the purchase price required by the REX Purchase Agreement.

Our investment in Rockies Express is recorded under the equity method of accounting and reported as "Unconsolidated investment" on our condensed consolidated balance sheet. As of May 6, 2016, the difference between the fair value of our investment in Rockies Express of $436.0 million and the book value of the underlying net assets of approximately $840.7 million results in a negative basis difference of approximately $404.7 million. The basis difference has been allocated to property, plant and equipment and long-term debt based on their respective fair values at the date of acquisition. The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years, which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. The basis difference at September 30, 2016 was allocated as follows:



	Basis Difference			Amortization Period
	(in thousands)
Long-term debt	$	7,878		2 - 25 years
Property, plant and equipment	(406,987		)	35 years
Total basis difference	$	(399,109	)

During the period from May 6, 2016 to September 30, 2016, we recognized equity in earnings from Rockies Express of $35.4 million, inclusive of the amortization of the negative basis difference discussed above, and received distributions from and made contributions to Rockies Express of $51.5 million and $35.5 million, respectively.

Summarized financial information for Rockies Express is as follows:



	September 30, 2016
	(in thousands)
Current assets	$	170,472
Noncurrent assets	$	6,058,941
Current liabilities	$	173,447
Noncurrent liabilities	$	2,638,071
Members' equity	$	3,417,895



	Three Months Ended September 30, 2016		Period from May 6, 2016 to September 30, 2016
	(in thousands)
Revenue	$	159,421	$	257,582
Operating income	$	66,436	$	110,268
Net income to Members	$	34,184	$	118,925

Acquisition of Additional 31.3% Membership Interest in Pony Express

Effective January 1, 2016, TEP acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of our common units) issued to TD, for total consideration of approximately $743.6 million. The transaction increased our aggregate membership interest in Pony Express to 98.0%. As part of the transaction, TD granted us an 18 month call option covering the newly issued 6,518,000 common units at a price of $42.50. On the effective date of the acquisition, the call option was valued at $46.0 million. As discussed in Note 8 – Risk Management, on July 21, 2016, we partially exercised the option covering 3,563,146 of the common units. On October 31, 2016, we partially exercised the option covering 1,251,760 of the common units, leaving 1,703,094 remaining common units subject to the call option as of November 2, 2016. As a result of the partial exercise on July 21, 2016, TEP derecognized a portion of the derivative asset balance, recognizing approximately $25.9 million through equity during the nine months ended September 30, 2016, as discussed further in Note 10 – Partnership Equity and Distributions.

The acquisition of the additional 31.3% 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 has not been recast to reflect the additional 31.3% membership interest. The transaction resulted in a deemed distribution to our general partner as discussed further in Note 10 – Partnership Equity and Distributions.

Cash outflows to acquire an additional noncontrolling interest in Pony Express are classified as an investing activity in the accompanying condensed consolidated statements of cash flows to the extent the consideration paid was used to directly fund the construction of the underlying assets by the noncontrolling member. Cash outflows to acquire an additional noncontrolling interest in excess of the cost to construct the underlying assets are classified as financing activities. For the nine months ended September 30, 2016, $49.1 million of the $475 million paid to acquire the additional 31.3% membership interest in Pony Express was classified as an investing activity and $425.9 million was classified as a financing activity.

TEP Acquisition of BNN Western, LLC

On December 16, 2015, Whiting Oil and Gas Corporation ("Whiting"), BNN Redtail, LLC ("Redtail"), and BNN Western, LLC ("Western"), a newly formed Delaware limited liability company, entered into a definitive Transfer, Purchase and Sale Agreement, pursuant to which Redtail acquired 100% of the outstanding membership interests of Western from Whiting in exchange for total cash consideration of $75 million. Western's assets consist of a fresh water delivery and storage system and produced water gathering and produced water disposal system, which together comprise 62 miles of pipeline along with associated fresh water ponds and disposal wells. As part of the transaction with Whiting, Whiting also executed a five-year fresh water service contract and a nine-year gathering and disposal contract.

At December 31, 2015, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. The $75 million purchase price of the assets was allocated entirely to property, plant and equipment. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of September 30, 2016.

TEP's unaudited pro forma revenue and net income attributable to partners for the three and nine months ended September 30, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015:



	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015
	(in thousands)
Revenue	$	138,651	$	387,245
Net income attributable to partners	$	42,847	$	120,395

The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TEP would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of TEP for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma revenue and net income includes adjustments to give effect to TEP's consolidated interest in the estimated results of operations of Western for the periods presented.

Acquisition of Additional Membership Interest in Water Solutions

On July 1, 2016, we acquired the remaining 8% noncontrolling equity interest in Water Solutions and additional interests in certain of Water Solutions' subsidiaries from Regency Investments I, LLC and BSEG Water Group LLC for total cash consideration of $6.0 million, which will be accounted for as an acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate membership interest in Water Solutions is 100%.

4. Related Party Transactions

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

There was no interest income from TD recognized for the three and nine months ended September 30, 2016. During the nine months ended September 30, 2015 we recognized interest income from TD of $0.4 million on the receivable balance under the Pony Express cash management agreement in effect through December 31, 2015.

Transactions with affiliated companies, excluding transactions otherwise disclosed, are as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Cost of transportation services	$	7,313	$	7,180	$	21,864	$	17,771
Charges to TEP: ⁽¹⁾
Property, plant and equipment, net	$	432	$	958	$	1,953	$	3,859
Operation and maintenance	$	6,317	$	6,077	$	18,778	$	17,325
General and administrative	$	9,567	$	9,541	$	28,784	$	28,112


⁽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 "Accounts receivable, net" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows:



	September 30, 2016		December 31, 2015
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	126	$	15
Total receivable from related parties	$	126	$	15
Accounts payable to related parties:
Tallgrass Operations, LLC	$	6,139	$	7,792
Tallgrass Equity, LLC	68		36
Deeprock Development, LLC	—		17
Rockies Express Pipeline LLC	—		7
Total accounts payable to related parties	$	6,207	$	7,852

Balances of gas imbalances with affiliated shippers are as follows:



	September 30, 2016		December 31, 2015
	(in thousands)
Affiliate gas imbalance receivables	$	82	$	92
Affiliate gas imbalance payables	$	161	$	227

5. Inventory

The components of inventory at September 30, 2016 and December 31, 2015 consisted of the following:



	September 30, 2016		December 31, 2015
	(in thousands)
Crude oil	$	4,223	$	2,661
Materials and supplies	6,505		8,581
Natural gas liquids	255		395
Gas in underground storage	2,392		2,156
Total inventory	$	13,375	$	13,793

6. Property, Plant and Equipment

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



	September 30, 2016			December 31, 2015
	(in thousands)
Crude oil pipelines	$	1,182,806		$	1,172,684
Natural gas pipelines	553,437			550,710
Processing and treating assets	256,331			254,073
Water business assets	81,507			81,098
General and other	71,190			69,181
Construction work in progress	38,454			30,699
Accumulated depreciation and amortization	(180,193		)	(133,427		)
Total property, plant and equipment, net	$	2,003,532		$	2,025,018

7. Goodwill

Annual Goodwill Impairment Analysis

We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach depending on facts and circumstances of the reporting unit. If we, after performing the qualitative assessment, determine it is “more likely than not” that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two-step test, the carrying amount of the reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit's fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss.

We did not elect to apply the qualitative assessment option during our 2016 annual goodwill impairment testing; instead we proceeded directly to the two-step quantitative test. In Step 1 of the two-step quantitative test, we compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the Step 1 impairment analysis indicated no potential impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, Step 2 of the impairment analysis was not necessary as part of the annual impairment analysis in 2016. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.

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. For example, the risks associated with changes in the market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and 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	September 30, 2016		December 31, 2015
		(in thousands)
Call option derivative⁽¹⁾	Current assets	$	25,690	$	—
Natural gas derivative contracts ⁽²⁾	Current liabilities	$	190	$	—
Crude oil derivative contract ⁽³⁾	Current liabilities	$	7	$	—


⁽¹⁾	As discussed in Note 3 – Acquisitions, in conjunction with our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option covering the 6,518,000 common units issued to TD.


⁽²⁾	As of September 30, 2016, the fair value shown for natural gas derivative contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.8 Bcf. As of December 31, 2015 there were no natural gas derivative contracts outstanding.


⁽³⁾	As of September 30, 2016, the fair value shown for crude oil derivative contracts was comprised of the sale of 30,000 barrels in October 2016. As of December 31, 2015 there were no crude oil 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 nine months ended September 30, 2016 and 2015:



	Location of gain (loss) recognized in income on derivatives	Amount of gain (loss) recognized in income on derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,
		2016			2015		2016			2015
		(in thousands)
Derivatives not designated as hedging contracts:
Call option derivative	Unrealized (loss) gain on derivative instrument	$	(4,419	)	$	—	$	5,588		$	—
Natural gas derivative contracts	Sales of natural gas, NGLs, and crude oil	$	161		$	252	$	(190	)	$	211
Crude oil derivative contract	Sales of natural gas, NGLs, and crude oil	$	318		$	—	$	466		$	—

Exercise of Call Option

On July 21, 2016, we partially exercised the call option granted by TD in January 2016 as discussed in Note 3 – Acquisitions covering 3,563,146 common units for a cash payment of $151.4 million. On October 31, 2016, we partially exercised the call option again covering an additional 1,251,760 common units for a cash payment of $53.2 million. These common units were deemed canceled upon the exercise of the call option and as of such exercise date were no longer issued and outstanding. As of November 2, 2016, 1,703,094 common units remained subject to the call option.

Credit Risk

We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our crude oil and natural gas derivatives 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. The counterparty to our call option derivative is TD.

Our over-the-counter swaps are entered into with counterparties outside central trading organizations such as 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 September 30, 2016, the fair value of our crude oil and natural gas derivative contracts were a liability, resulting in no credit exposure from TEP's counterparties as of that date.

As of September 30, 2016 and December 31, 2015, 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 any margin deposits with counterparties associated with natural gas 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 commodity 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. The call option granted by TD is valued using a Black-Scholes option pricing model. Key inputs to the valuation model include the term of the option, risk free rate, the exercise price and current market price, expected volatility and expected distribution yield of the underlying units. The call option valuation is classified within Level 2 of the fair value hierarchy as the value is based on significant observable inputs.

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 derivative contracts as of September 30, 2016 based on the fair value hierarchy established by the Codification:



			Asset Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of September 30, 2016:
Call option derivative	$	25,690	$	—	$	25,690	$	—

			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)
As of September 30, 2016:
Natural gas derivative contracts	$	190	$	—	$	190	$	—
Crude oil derivative contract	$	7	$	—	$	7	$	—

9. Long-term Debt

Long-term debt consisted of the following at September 30, 2016 and December 31, 2015:



	September 30, 2016			December 31, 2015
	(in thousands)
Revolving credit facility	$	1,005,000		$	753,000
5.50% senior notes due September 15, 2024	400,000			—
Less: Deferred financing costs, net ⁽¹⁾	(6,997		)	—
Total long-term debt, net	$	1,398,003		$	753,000


⁽¹⁾	Deferred financing costs, net as presented above relate solely to the 2024 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our condensed consolidated balance sheets.

Senior Unsecured Notes

On September 1, 2016, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the "Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). TEP used the net proceeds of the offering to repay outstanding borrowings under its existing senior secured revolving credit facility.

The 2024 Notes are general unsecured senior obligations of the Issuers. The 2024 Notes are unconditionally guaranteed jointly and severally on a senior unsecured basis by TEP's existing direct and indirect wholly owned subsidiaries (other than the Co-Issuer) and certain of TEP's future subsidiaries (the "Guarantors"). The 2024 Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 2024 Notes will mature on September 15, 2024 and interest on the 2024 Notes is payable in cash semi-annually in arrears on each March 15 and September 15, commencing March 15, 2017. TEP may redeem the 2024 Notes prior to their scheduled maturity at the applicable redemption price set forth in the Indenture, plus accrued and unpaid interest.

The Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. As of September 30, 2016, we are in compliance with the covenants required under the 2024 Notes.

Revolving Credit Facility

Effective January 4, 2016, in connection with the acquisition of an additional 31.3% membership interest in Pony Express, TEP exercised the committed accordion feature to increase the total capacity of the revolving credit facility from $1.1 billion to $1.5 billion. In connection with the acquisition of a 25% membership interest in Rockies Express, TEP amended the revolving credit facility to increase the total capacity to $1.75 billion, which increase became effective May 6, 2016.

The following table sets forth the available borrowing capacity under the revolving credit facility as of September 30, 2016 and December 31, 2015:



	September 30, 2016			December 31, 2015
	(in thousands)
Total capacity under the revolving credit facility	$	1,750,000		$	1,100,000
Less: Outstanding borrowings under the revolving credit facility ⁽¹⁾	(1,005,000		)	(753,000		)
Available capacity under the revolving credit facility	$	745,000		$	347,000


⁽¹⁾	As of October 31, 2016, our outstanding borrowings under the revolving credit facility were approximately $1.003 billion.

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 September 30, 2016, 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 September 30, 2016, the weighted average interest rate on outstanding borrowings was 2.28%. During the nine months ended September 30, 2016, our weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 2.72%.

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 September 30, 2016 and December 31, 2015, 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)
As of September 30, 2016:
Revolving credit facility	$	—	$	1,005,000	$	—	$	1,005,000	$	1,005,000
2024 Notes	$	—	$	403,752	$	—	$	403,752	$	393,003
As of December 31, 2015:
Revolving credit facility	$	—	$	753,000	$	—	$	753,000	$	753,000

The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of September 30, 2016 and December 31, 2015, the fair value of borrowings under the revolving credit facility approximates the carrying amount of the borrowings using a discounted cash flow analysis. The 2024 Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 Notes is based upon quoted market prices adjusted for illiquid markets.

We are not aware of any factors that would significantly affect the estimated fair value subsequent to September 30, 2016.

10. Partnership Equity and Distributions

Equity Distribution Agreements

On October 31, 2014, we entered into an equity distribution agreement pursuant to which we may sell from time to time through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering price of up to $200 million. On May 13, 2015 the amount was subsequently amended to $100.2 million in order to account for follow-on equity offerings under our S-3 shelf registration statement. On May 17, 2016, we entered into a new equity distribution agreement allowing for the sale of common units with an aggregate offering price of up to $657.5 million. Sales of common units, if any, will be made by means of ordinary brokers' transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by the Partnership and one or more of the managers. We intend to use the net cash proceeds from any sale of the units for general partnership purposes, which may include, among other things, the Partnership's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with the Partnership's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital.

During the three months ended September 30, 2016, we issued and sold 622,846 common units with a weighted average sales price of $47.39 per unit under our equity distribution agreements for net cash proceeds of approximately $28.7 million (net of approximately $0.8 million in commissions and professional service expenses). During the nine months ended September 30, 2016, we issued and sold 6,703,984 common units with a weighted average sales price of $43.98 per unit under our equity distribution agreements for net cash proceeds of approximately $290.5 million (net of approximately $4.4 million in commissions and professional service expenses). During the period from October 1, 2016 to November 2, 2016, we issued and sold an additional 628,914 common units with a weighted average sales price of $48.05 per unit under our equity distribution agreement for net cash proceeds of approximately $29.9 million (net of approximately $0.3 million in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as described above.

Private Placement

On April 28, 2016, we issued an aggregate of 2,416,987 common units for net cash proceeds of $90.0 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C. The units were subsequently registered pursuant to our Form S-3/A (File No. 333-210976) filed with the SEC on May 6, 2016, which became effective May 17, 2016.

Tallgrass Development Purchase Program

On February 17, 2016, TEP and Tallgrass Energy GP, LP ("TEGP") announced that the Board of Directors of Tallgrass Energy Holdings, LLC, the sole member of TEGP's general partner and the general partner of TD, has authorized an equity purchase program under which TD may initially purchase up to an aggregate of $100 million of the outstanding Class A shares of TEGP or the outstanding common units of TEP. TD may purchase Class A shares or Common Units from time to time on the open market or in negotiated purchases. The timing and amounts of any such purchases will be subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The purchase plan does not obligate TD to acquire any specific number of Class A shares or Common Units and may be discontinued at any time. No purchases were made under this program during the nine months ended September 30, 2016.

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

Our partnership agreement requires us to distribute our available cash, as defined in the partnership agreement, to unitholders of record on the applicable record date within 45 days after the end of each quarter. The following table shows the distributions for the periods indicated:



		Distributions
		Limited Partner Common Units		General Partner						Distributions per Limited Partner Unit
Three Months Ended	Date Paid	Limited Partner Common Units		Incentive Distribution Rights		General Partner Units		Total		Distributions per Limited Partner Unit
		(in thousands, except per unit amounts)
September 30, 2016	November 14, 2016 ⁽¹⁾	$	57,332	$	26,987	$	976	$	85,295	$	0.7950
June 30, 2016	August 12, 2016	54,442		24,262		911		79,615		0.7550
March 31, 2016	May 13, 2016	48,238		19,816		830		68,884		0.7050
December 31, 2015	February 12, 2016	42,984		15,332		724		59,040		0.6400
September 30, 2015	November 13, 2015	36,347		11,567		660		48,574		0.6000
June 30, 2015	August 14, 2015	35,135		10,418		627		46,180		0.5800
March 31, 2015	May 14, 2015	31,322		6,934		530		38,786		0.5200


⁽¹⁾	The distribution announced on October 5, 2016 for the third quarter of 2016 will be paid on November 14, 2016 to unitholders of record at the close of business on October 31, 2016.

Other Contributions and Distributions

During the nine months ended September 30, 2016, TEP was deemed to have made noncash capital distributions of $280.0 million and $25.9 million to the general partner, which represent the excess purchase price over the carrying value of the additional 31.3% membership interest in Pony Express acquired effective January 1, 2016 and the derecognition of a portion of the derivative asset associated with the partial exercise of the call option, respectively. See Note 3 – Acquisitions for additional information regarding these transactions. During the nine months ended September 30, 2016, TEP also received contributions of $5.3 million from TD to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 13 – Legal and Environmental Matters, and received contributions and distributions from noncontrolling interests of $8.7 million and $5.0 million, which primarily consisted of activity associated with TD's 2% noncontrolling interest in Pony Express.

During the nine months ended September 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. TEP also recognized contributions from noncontrolling interests of $110.6 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 $44.5 million.

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.

The following table illustrates the Partnership's calculation of net income per common and subordinated unit for the three and nine months ended September 30, 2016 and 2015:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands, except per unit amounts)
Net income	$	61,818		$	49,550		$	200,087		$	125,771
Net income attributable to noncontrolling interests	(1,084		)	(6,871		)	(3,235		)	(5,874		)
Net income attributable to partners	60,734			42,679			196,852			119,897
General partner interest in net income	(27,674		)	(12,146		)	(73,347		)	(30,614		)
Net income available to common and subordinated unitholders	$	33,060		$	30,533		$	123,505		$	89,283
Basic net income per common and subordinated unit	$	0.45		$	0.50		$	1.75		$	1.54
Diluted net income per common and subordinated unit	$	0.45		$	0.50		$	1.73		$	1.52
Basic average number of common and subordinated units outstanding	73,089			60,576			70,686			57,917
Equity Participation Unit equivalent units	974			960			904			967
Diluted average number of common and subordinated units outstanding	74,063			61,536			71,590			58,884

12. Regulatory Matters

There are currently no proceedings challenging the currently effective transportation rates of Pony Express, Rockies Express or Trailblazer Pipeline Company LLC ("Trailblazer"). On October 30, 2015, Tallgrass Interstate Gas Transmission, LLC ("TIGT") filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), discussed in more detail below. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable law, to challenge the rates that we charge at our regulated entities. Further, applicable law 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 like the Pony Express System 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

General Rate Case Filing – FERC Docket RP16-137

On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA. The rate case proposed a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT. In addition, TIGT proposed certain changes to the transportation rate design of its system to replace the current rate zone structure with a single "postage stamp" rate. TIGT also proposed new incremental charges, including (i) a charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a Cost Recovery Mechanism ("CRM") charge to completely or partially reimburse TIGT for certain costs it incurred to maintain system safety, environmental compliance and reliability. TIGT also proposed to replace its fixed fuel and lost and unaccounted for ("FL&U") charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period's under/over collection and the forecasted FL&U expense for the upcoming period. TIGT also proposed to implement a power cost tracker to recover the actual power costs incurred by TIGT to power its compressors. Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under the NGA and the FERC's regulations, TIGT's shippers and other interested parties, including the FERC's Trial Staff, had a right to challenge any aspect of TIGT's rate case filing. Accordingly, numerous TIGT customers protested aspects of TIGT's NGA Section 4 rate filing.

On November 30, 2015, the FERC issued an order accepting and suspending the proposed rates and certain proposed tariff records to be effective upon motion May 1, 2016, subject to refund, certain modifications to TIGT's proposed CRM charge, and the outcome of an evidentiary hearing before a FERC Administrative Law Judge (the "Suspension Order"). In the Suspension Order, the FERC also accepted two tariff records related to force majeure events and reservation charge crediting to be effective December 1, 2015, subject to certain modifications. On December 21, 2015, TIGT made a compliance filing with the FERC to modify TIGT's proposed CRM charge and update the tariff records related to force majeure events and reservation charge crediting as directed by the FERC in the Suspension Order. No comments or protests were filed in response to the compliance filing and the FERC accepted the compliance filing on February 1, 2016. On March 22, 2016, a Settlement Judge was appointed in the case to assist the participants in exploring the possibility of settlement. On March 31, 2016, the FERC issued an order denying certain rehearing requests concerning the CRM, granting in part a motion to remove certain pro forma tariff records from the hearing, and also requested comments in order to assess the need for a technical conference. The FERC also retained for resolution through hearing the pro forma tariff records related to TIGT's proposed charge at delivery points lacking electronic flow measurement and removed from hearing the other issues related to the pro forma tariff records. Whether any issues will be resolved through technical conference is pending. The FERC also directed TIGT to provide additional information related to certain pro forma tariff records, which TIGT filed on April 14, 2016. On June 23, 2016, the FERC approved the implementation of TIGT's filed postage stamp rates, subject to refund, effective on May 1, 2016.

TIGT has reached an agreement in principle with customers representing a majority of firm fee revenue on the TIGT System for the year ended December 31, 2015 to settle all rate related issues set for hearing in its existing FERC rate case, including the issues of a cost recovery mechanism and a non-Electronic Flow Measurement charge. On May 5, 2016, the Acting Chief Administrative Law Judge issued an Order suspending the procedural schedule in the case as a result of the agreement in principle. On June 8, 2016, TIGT filed with the FERC its offer of settlement which resolves all issues in the case, with the exception of certain non-rate related tariff issues which remain subject to the FERC's review and approval. On June 9, 2016, the Presiding Administrative Law Judge issued an Order shortening the period for any comments on the settlement, such that comments were due by June 13, 2016. No adverse comments were filed. The offer of settlement was certified to the FERC by the Administrative Law Judge on July 14, 2016. The Judge found that the settlement is uncontested, presents no issues of first impression, has no FERC policy implications, and appears to be just, reasonable, and in the public interest. The FERC issued an order on November 2, 2016 approving the settlement, finding that it appears to be fair and reasonable and in the public interest.

Trailblazer

2016 Annual Fuel Tracker Filing – FERC Docket Nos. RP16-814-000 and RP16-814-001

On April 1, 2016, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2016 in Docket No. RP16-814-000. The FERC accepted this filing on April 18, 2016. On May 19, 2016, Trailblazer filed its refund report associated with the April 1, 2016 annual fuel tracker filing, which the FERC accepted on July 11, 2016.

On September 7, 2016, Trailblazer filed an adjustment to its April 1, 2016 fuel tracker filing. As a result of this adjustment, Trailblazer proposed to issue additional cash-out refunds to applicable shippers and also reflect this adjustment in its applicable fuel accounts. The FERC accepted this filing on October 3, 2016. On October 14, 2016, Trailblazer filed its refund report associated with its September 7, 2016 adjustment filing.

Rockies Express

Annual FERC Fuel Tracking Filings – FERC Docket Nos. RP16-702-000 and RP16-1301-000

On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016.

On September 30, 2016, Rockies Express elected to make an interim fuel tracker filing with a proposed effective date of November 1, 2016 in Docket No. RP16-1301-000. This interim filing proposes increases to most applicable fuel and power rates as a result of increased system utilization. On October 12, 2016, certain shippers filed a protest with the FERC regarding the proposed increases. Rockies Express filed a response to the protest on October 20, 2016, to which the shippers replied on October 25, 2016. On October 20, 2016, Rockies Express also filed an errata to rates applicable to a pooling and wheeling service. The FERC set a November 1, 2016 comment deadline on the errata filing. The interim filing remains pending before the FERC.

Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000

On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the FERC an application for (1) authorization to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio (Seneca Lateral Facilities described in Docket Nos. CP13-539-000 and CP14-194-000) from Natural Gas Policy Act of 1978 Section 311 authority to Natural Gas Act Section 7 jurisdiction, and (2) issuance of a certificate of public convenience and necessity authorizing Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC issued a Certificate to Rockies Express granting its requested authorizations. As directed by the FERC, Rockies Express filed revised rates for Natural Gas Act service on the Seneca Lateral, and the Seneca Lateral commenced Natural Gas Act service on June 1, 2016.

Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000

On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The proposed facilities will increase the Rockies Express Zone 3 east-to-west mainline capacity by 800,000 Dth/d from receipts at Clarington, Ohio to corresponding deliveries of 520,000 Dth/d and 280,000 Dth/d to Lebanon, Ohio and Moultrie County, Illinois, respectively. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities.

13. 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 no reserve for legal claims as of September 30, 2016 or December 31, 2015.

Rockies Express

Mineral Management Service Lawsuit

On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA") conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay. On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on June 23, 2016.

Ultra Resources

In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, in which Rockies Express seeks approximately $303 million in damages and other relief. Specifically, Rockies Express has asserted that Ultra owes approximately $303 million for past transportation service charges and for reservation charge fees that Rockies Express would have received over the term of the service agreement had Ultra not defaulted, in addition to other amounts owed under law or equity.

On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of Texas. On May 10, 2016, Ultra filed a notice of bankruptcy in the Harris County state court proceeding, which asserted that pursuant to section 362(a) of the Bankruptcy Code, the filing of Ultra's Chapter 11 petition operated as a stay of the Harris County state court proceeding. Accordingly, Rockies Express intends to pursue its approximately $303 million claim in Ultra's Chapter 11 proceeding.

Michels Corporation

On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels seeks unspecified damages from Rockies Express and asserts claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels has also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. The case is currently scheduled to go to trial in April 2017. Rockies Express also previously filed Petition for Declaratory Judgment, Injunctive Relief and Damages against Michels in Johnson County, Kansas. That claim was dismissed without prejudice in September 2015. Rockies Express believes Michels' claims are without merit and plans to continue 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 $4.3 million and $4.8 million at September 30, 2016 and December 31, 2015, respectively.

TMID

Casper Plant, EPA Notice of Violation

In August 2011, the 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 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 EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including the expected 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.

Trailblazer

Pipeline Integrity Management Program

In 2014 and 2015, Trailblazer conducted 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. Such repair or replacement will likely occur over a period of years, depending upon final assessment of corrosion growth rates and the remediation and repair plan implemented by Trailblazer. Trailblazer is currently operating at less than its current maximum allowable operating 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 completed 32 excavation digs at an aggregate cost of approximately $1.3 million based on preliminary analysis of the smart tool surveys performed in 2014. 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 continuing to develop 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. In 2016, Trailblazer intends to replace approximately 8 miles of pipe, install additional ground beds, and continue remediating areas with external control anomalies at an estimated cost of $21.5 million. 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 incurred 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 an annual $1.5 million deductible. During the nine months ended September 30, 2016, TEP received contributions of $5.3 million from TD related to the indemnity.

14. Reporting Segments

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

Crude Oil Transportation & Logistics

The Crude Oil Transportation & Logistics segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, 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 the second quarter of 2015.

Natural Gas Transportation & Logistics

The Natural Gas Transportation & Logistics segment is engaged in the 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. The Natural Gas Transportation & Logistics segment includes our 25% membership interest in Rockies Express effective May 6, 2016, as discussed in Note 3 – Acquisitions.

Processing & Logistics

The Processing & Logistics segment is engaged in the ownership and operation of natural gas processing, treating and fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, as well as water business services provided primarily to the oil and gas exploration and production industry and the transportation of NGLs.

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 our revolving credit facility, public company costs, 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 September 30, 2016							Three Months Ended September 30, 2015
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Crude Oil Transportation & Logistics	$	95,826	$	—		$	95,826	$	83,272	$	—		$	83,272
Natural Gas Transportation & Logistics	33,812		(1,427		)	32,385		33,636		(1,346		)	32,290
Processing & Logistics	23,914		—			23,914		22,606		—			22,606
Corporate and Other	—		—			—		—		—			—
Total Revenue	$	153,552	$	(1,427	)	$	152,125	$	139,514	$	(1,346	)	$	138,168



	Nine Months Ended September 30, 2016							Nine Months Ended September 30, 2015
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Crude Oil Transportation & Logistics	$	283,868	$	—		$	283,868	$	208,872	$	—		$	208,872
Natural Gas Transportation & Logistics	94,949		(4,192		)	90,757		98,215		(4,036		)	94,179
Processing & Logistics	69,836		—			69,836		82,762		—			82,762
Corporate and Other	—		—			—		—		—			—
Total Revenue	$	448,653	$	(4,192	)	$	444,461	$	389,849	$	(4,036	)	$	385,813



	Three Months Ended September 30, 2016									Three Months Ended September 30, 2015
Adjusted EBITDA:	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA
	(in thousands)
Crude Oil Transportation & Logistics	$	65,431		$	1,346		$	66,777		$	47,526		$	1,346		$	48,872
Natural Gas Transportation & Logistics	41,253			(1,427		)	39,826			15,983			(1,346		)	14,637
Processing & Logistics	3,210			81			3,291			3,046			—			3,046
Corporate and Other	(1,368		)	—			(1,368		)	(703		)	—			(703		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investment							12,066									—
Less:
Interest expense, net of noncontrolling interest							(10,907		)							(3,872		)
Depreciation and amortization expense, net of noncontrolling interest							(21,102		)							(18,826		)
Distributions from unconsolidated investment							(21,804		)							—
Non-cash (loss) gain related to derivative instruments, net of noncontrolling interest							(4,410		)							259
Non-cash compensation expense							(1,635		)							(734		)
Net income attributable to partners							$	60,734								$	42,679



	Nine Months Ended September 30, 2016									Nine Months Ended September 30, 2015
Adjusted EBITDA:	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA
	(in thousands)
Crude Oil Transportation & Logistics	$	195,732		$	4,037		$	199,769		$	119,352		$	4,036		$	123,388
Natural Gas Transportation & Logistics	104,168			(4,192		)	99,976			51,820			(4,036		)	47,784
Processing & Logistics	10,110			155			10,265			18,841			—			18,841
Corporate and Other	(3,809		)	—			(3,809		)	(2,374		)	—			(2,374		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investment							35,387									—
Non-cash loss allocated to noncontrolling interest							—									9,377
Less:
Interest expense, net of noncontrolling interest							(27,639		)							(11,205		)
Depreciation and amortization expense, net of noncontrolling interest							(64,909		)							(57,661		)
Distributions from unconsolidated investment							(51,460		)							—
Non-cash gain related to derivative instruments, net of noncontrolling interest							5,391									218
Non-cash compensation expense							(4,270		)							(3,988		)
Non-cash loss from asset sales							(1,849		)							(4,483		)
Net income attributable to partners							$	196,852								$	119,897



	Nine Months Ended September 30,
Capital Expenditures:	2016		2015
	(in thousands)
Crude Oil Transportation & Logistics	$	25,985	$	40,579
Natural Gas Transportation & Logistics	11,146		10,858
Processing & Logistics	8,121		13,709
Corporate and Other	—		—
Total capital expenditures	$	45,252	$	65,146



Assets:	September 30, 2016		December 31, 2015
	(in thousands)
Crude Oil Transportation & Logistics	$	1,417,241	$	1,439,418
Natural Gas Transportation & Logistics	1,155,372		706,576
Processing & Logistics	405,760		409,795
Corporate and Other	31,915		6,285
Total assets	$	3,010,288	$	2,562,074

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. The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the 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 our 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 for the year ended December 31, 2015 (our "2015 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 17, 2016.

A reference to a "Note" herein refers to the accompanying Notes to Condensed 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 a 25% membership interest in Rockies Express that was completed in May 2016, our purchase of an additional 31.3% membership interest in Pony Express that was completed in January 2016, and our acquisition of water business assets in Weld County, Colorado that was completed in December 2015;


•	large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;


•	changes in general economic conditions;


•	competitive conditions in our industry;


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


•	the demand for our services, including crude oil transportation services, natural gas transportation, storage and processing services and water business 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 level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil, natural gas, NGLs, and other hydrocarbons;


•	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, transporting, storing and processing natural gas, and transporting, gathering and disposing of water produced in connection with hydrocarbon exploration and production activities;


•	natural disasters, weather-related delays, casualty losses and other matters beyond our control;


•	interest rates;


•	labor relations;


•	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

We are a publicly traded, growth-oriented limited partnership formed in 2013 to own, operate, acquire and develop midstream energy assets in North America. We currently provide crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 25% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), a Delaware limited liability company which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio, (2) 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 (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). 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 (collectively, the "Midstream Facilities"), and NGL transportation services in Northeast Colorado. We perform water business services 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, Bakken, Marcellus and Utica 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:


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


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


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

Recent Developments

Distribution Announced

On October 5, 2016, we announced a cash distribution for the quarter ended September 30, 2016 of $0.795 per common unit. The distribution will be paid on November 14, 2016, to unitholders of record on October 31, 2016.

Exercise of Call Option

On October 31, 2016, we partially exercised the call option granted by TD in January 2016 as discussed in Note 3 – Acquisitions covering 1,251,760 common units. These common units were deemed canceled upon the exercise of the call option and as of the exercise date were no longer issued and outstanding. As of November 2, 2016, 1,703,094 common units remained subject to the call option.

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, natural gas transportation and storage capacity, NGL transportation capacity, and water transportation, gathering and disposal capacity under firm fee contracts, as well as 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 generally 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 generally define as Adjusted EBITDA, plus deficiency payments received from or utilized by our customers and preferred distributions received from Pony Express in excess of its distributable cash flow attributable to our net interest, less cash interest expense, maintenance capital expenditures, distributions to noncontrolling interests in excess of earnings allocated to noncontrolling interests, and certain cash reserves permitted by our partnership agreement, 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, and are presented net of noncontrolling interest and reimbursements. As discussed in Note 2 – Summary of Significant Accounting Policies, prior to December 31, 2015, we received preferred distributions from Pony Express. Effective January 1, 2016 with our acquisition of an additional 31.3% membership interest in Pony Express, distributable cash flow from Pony Express is distributed pro rata based on ownership. 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. Earnings at Pony Express prior to December 31, 2015 were 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
Net income attributable to partners	$	60,734		$	42,679		$	196,852		$	119,897
Add:
Interest expense, net of noncontrolling interest	10,907			3,872			27,639			11,205
Depreciation and amortization expense, net of noncontrolling interest	21,102			18,826			64,909			57,661
Distributions from unconsolidated investment	21,804			—			51,460			—
Non-cash loss (gain) related to derivative instruments, net of noncontrolling interest	4,410			(259		)	(5,391		)	(218		)
Non-cash compensation expense	1,635			734			4,270			3,988
Non-cash loss from disposal of assets	—			—			1,849			4,483
Less:
Equity in earnings of unconsolidated investment	(12,066		)	—			(35,387		)	—
Non-cash loss allocated to noncontrolling interest	—			—			—			(9,377		)
Adjusted EBITDA	$	108,526		$	65,852		$	306,201		$	187,639
Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	109,370		$	85,266		$	305,916		$	197,484
Add:
Interest expense, net of noncontrolling interest	10,907			3,872			27,639			11,205
Other, including changes in operating working capital	(11,751		)	(23,286		)	(27,354		)	(21,050		)
Adjusted EBITDA	$	108,526		$	65,852		$	306,201		$	187,639
Add:
Deficiency payments received, net	9,114			8,342			24,892			12,050
Less:
Cash interest cost	(9,950		)	(3,518		)	(25,183		)	(10,031		)
Maintenance capital expenditures, net	(2,828		)	(4,659		)	(7,085		)	(9,237		)
Distributions to noncontrolling interest in excess of earnings	—			(11,520		)	—			(22,517		)
Distributable Cash Flow	$	104,862		$	54,497		$	298,825		$	157,904

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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)
Reconciliation of Adjusted EBITDA to Operating Income in the Crude Oil Transportation & Logistics Segment ⁽¹⁾
Operating income	$	53,227		$	44,069		$	159,619		$	103,857
Add:
Depreciation and amortization expense, net of noncontrolling interest	13,112			10,323			39,276			30,752
Adjusted EBITDA attributable to noncontrolling interests	(1,060		)	(6,866		)	(3,170		)	(5,880		)
Non-cash loss related to derivative instruments, net of noncontrolling interest, net of noncontrolling interests	152			—			7			—
Less:
Non-cash loss allocated to noncontrolling interest	—			—			—			(9,377		)
Segment Adjusted EBITDA	$	65,431		$	47,526		$	195,732		$	119,352
Reconciliation of Adjusted EBITDA to Operating Income in the Natural Gas Transportation & Logistics Segment ⁽¹⁾
Operating income	$	14,254		$	10,499		$	35,018		$	32,989
Add:
Depreciation and amortization expense	4,876			5,241			16,233			17,066
Distributions from unconsolidated investment	21,804			—			51,460			—
Non-cash (gain) loss related to derivative instruments	(161		)	(259		)	190			(218		)
Other income, net	480			502			1,267			1,983
Segment Adjusted EBITDA	$	41,253		$	15,983		$	104,168		$	51,820
Reconciliation of Adjusted EBITDA to Operating (Loss) Income in the Processing & Logistics Segment⁽¹⁾
Operating income (loss)	$	120		$	(212	)	$	(1,074	)	$	4,508
Add:
Depreciation and amortization expense, net of noncontrolling interest	3,114			3,262			9,400			9,843
Non-cash loss from disposal of assets	—			—			1,849			4,483
Adjusted EBITDA attributable to noncontrolling interests	(24		)	(4		)	(65		)	7
Segment Adjusted EBITDA	$	3,210		$	3,046		$	10,110		$	18,841
Total Segment Adjusted EBITDA	$	109,894		$	66,555		$	310,010		$	190,013
Corporate general and administrative costs	(1,368		)	(703		)	(3,809		)	(2,374		)
Total Adjusted EBITDA	$	108,526		$	65,852		$	306,201		$	187,639


⁽¹⁾	Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for the Crude Oil Transportation & Logistics, Natural Gas Transportation & Logistics, and Processing & Logistics segments. For reconciliations to the consolidated financial data, see Note 14 – Reporting Segments to the accompanying condensed consolidated financial statements.

Results of Operations

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands, except operating data)
Revenues:
Crude oil transportation services	$	91,387		$	81,928		$	279,281		$	206,331
Natural gas transportation services	31,444			29,431			89,406			90,620
Sales of natural gas, NGLs, and crude oil	20,758			20,252			51,514			62,132
Processing and other revenues	8,536			6,557			24,260			26,730
Total Revenues	152,125			138,168			444,461			385,813
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	18,590			18,186			48,116			54,959
Cost of transportation services (exclusive of depreciation and amortization shown below)	13,528			14,862			43,924			39,069
Operations and maintenance	14,714			14,071			41,055			36,054
Depreciation and amortization	20,831			20,802			64,099			61,762
General and administrative	13,147			11,807			40,072			37,947
Taxes, other than income taxes	6,717			5,521			19,862			16,547
Loss on disposal of assets	—			—			1,849			4,483
Total Operating Costs and Expenses	87,527			85,249			258,977			250,821
Operating Income	64,598			52,919			185,484			134,992
Other Income (Expense):
Interest expense, net	(10,907		)	(3,871		)	(27,639		)	(11,204		)
Unrealized (loss) gain on derivative instrument	(4,419		)	—			5,588			—
Equity in earnings of unconsolidated investment	12,066			—			35,387			—
Other income, net	480			502			1,267			1,983
Total Other (Expense) Income	(2,780		)	(3,369		)	14,603			(9,221		)
Net income	61,818			49,550			200,087			125,771
Net income attributable to noncontrolling interests	(1,084		)	(6,871		)	(3,235		)	(5,874		)
Net income attributable to partners	$	60,734		$	42,679		$	196,852		$	119,897
Other Financial Data:
Adjusted EBITDA ⁽¹⁾	$	108,526		$	65,852		$	306,201		$	187,639
Operating Data:
Crude oil transportation average throughput (Bbls/d) ⁽²⁾	276,138			252,540			284,512			218,697
Gas transportation average firm contracted volumes (MMcf/d)⁽³⁾	1,440			1,506			1,464			1,543
Natural gas processing inlet volumes (MMcf/d)	103			110			102			128


⁽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.


⁽²⁾	Approximate average daily throughput for the three and nine months ended September 30, 2015 is reflective of the volumetric ramp up due to commercial in-service of the Pony Express System beginning in October 2014 and delays in the construction and expansion efforts of third-party pipelines with which Pony Express shares joint tariffs.


⁽³⁾	Excludes firm contracted volumes of Rockies Express.

Three Months Ended September 30, 2016 Compared to the Three Months Ended September 30, 2015

Revenues. Total revenues were $152.1 million for the three months ended September 30, 2016, compared to $138.2 million for the three months ended September 30, 2015, which represents an increase of $14.0 million, or 10%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $12.6 million and $1.3 million in the Crude Oil Transportation & Logistics and Processing & Logistics segments, respectively, as discussed further below.

Operating costs and expenses. Operating costs and expenses were $87.5 million for the three months ended September 30, 2016 compared to $85.2 million for the three months ended September 30, 2015, which represents an increase of $2.3 million, or 3%. The overall increase in operating costs and expenses was primarily driven by increased operating costs and expenses of $3.4 million, $1.5 million and $1.0 million in the Crude Oil Transportation & Logistics, Corporate and Other, and Processing & Logistics segments, respectively, partially offset by decreased operating costs and expenses of $3.6 million in the Natural Gas Transportation & Logistics segment, as discussed further below.

Interest expense, net. Interest expense of $10.9 million for the three months ended September 30, 2016 and $3.9 million for the three months ended September 30, 2015 was primarily composed of interest and fees associated with our revolving credit facility, as well as the 2024 Notes issued on September 1, 2016. The increase in interest and fees associated with our revolving credit facility is primarily due to increased borrowings to fund a portion of our December 2015 acquisition of BNN Western, LLC ("Western") and our recent acquisitions of an additional 31.3% membership interest in Pony Express effective January 1, 2016 and 25% membership interest in Rockies Express effective May 6, 2016.

Unrealized loss on derivative instrument. Unrealized loss on derivative instrument of $4.4 million represents the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016.

Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $12.1 million for the three months ended September 30, 2016 reflects our portion of earnings and the amortization of a negative basis difference of $3.5 million associated with our acquisition of a 25% membership interest in Rockies Express effective May 6, 2016.

Other income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income was $0.5 million for the three months ended September 30, 2016 and 2015.

Net income attributable to noncontrolling interests. Net income attributable to noncontrolling interests of $1.1 million for the three months ended September 30, 2016 primarily reflects the net income allocated to TD's 2% noncontrolling interest in Pony Express. Net income attributable to noncontrolling interest of $6.9 million for the three months ended September 30, 2015 primarily reflects income allocated to TD's 33.3% noncontrolling interest of Pony Express.

Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015

Revenues. Total revenues were $444.5 million for the nine months ended September 30, 2016, compared to $385.8 million for the nine months ended September 30, 2015, which represents an increase of $58.6 million, or 15%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $75.0 million in the Crude Oil Transportation & Logistics segment, partially offset by decreased revenues of $12.9 million and $3.3 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, as discussed further below.

Operating costs and expenses. Operating costs and expenses were $259.0 million for the nine months ended September 30, 2016 compared to $250.8 million for the nine months ended September 30, 2015, which represents an increase of $8.2 million, or 3%. The overall increase in operating costs and expenses is primarily driven by increased operating costs and expenses of $19.2 million in the Crude Oil Transportation & Logistics segment, partially offset by decreased operating costs and expenses of $7.3 million and $5.3 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, as discussed further below.

Interest expense, net. Interest expense of $27.6 million for the nine months ended September 30, 2016 was primarily composed of interest and fees associated with our revolving credit facility and the 2024 Notes issued on September 1, 2016. Interest expense of $11.2 million for the nine months ended September 30, 2015 was primarily composed of interest and fees associated with our 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. The increase in interest and fees associated with our revolving credit facility is primarily due to increased borrowings to fund a portion of our 2015 acquisitions and our recent acquisitions of an additional 31.3% membership interest in Pony Express effective January 1, 2016 and a 25% membership interest in Rockies Express effective May 6, 2016.

Unrealized gain on derivative instrument. Unrealized gain on derivative instrument of $5.6 million represents the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016.

Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $35.4 million for the nine months ended September 30, 2016 reflects our portion of earnings and the amortization of a negative basis difference of $5.6 million associated with our acquisition of a 25% membership interest in Rockies Express effective May 6, 2016. The equity in earnings for the nine months ended September 30, 2016 includes recognition of our portion of the $65 million settlement received by Rockies Express related to the lawsuit between Interior and Rockies Express as discussed in Note 13 – Legal and Environmental Matters.

Other income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income for the nine months ended September 30, 2016 was $1.3 million compared to $2.0 million for the nine months ended September 30, 2015.

Net income attributable to noncontrolling interests. Net income attributable to noncontrolling interests of $3.2 million for the nine months ended September 30, 2016 primarily reflects the net income allocated to TD's 2% noncontrolling interest in Pony Express. Net income attributable to noncontrolling interest of $5.9 million for the nine months ended September 30, 2015 primarily reflects the net income 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 September 30, 2015.

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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Revenues:
Crude oil transportation services	$	91,387	$	81,928	$	279,281	$	206,331
Sales of natural gas, NGLs, and crude oil	4,439		1,344		4,587		2,541
Total revenues	95,826		83,272		283,868		208,872
Operating costs and expenses:
Cost of sales	3,487		1,482		3,487		2,468
Cost of transportation services	12,939		13,393		41,586		33,630
Operations and maintenance	3,203		2,657		10,244		6,087
Depreciation and amortization	12,836		12,257		38,448		34,791
General and administrative	4,866		5,155		15,236		15,465
Taxes, other than income taxes	5,268		4,259		15,248		12,574
Total operating costs and expenses	42,599		39,203		124,249		105,015
Operating income	$	53,227	$	44,069	$	159,619	$	103,857


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 14 – Reporting Segments to the accompanying condensed consolidated financial statements.

Three Months Ended September 30, 2016 Compared to the Three Months Ended September 30, 2015

Revenues. Crude Oil Transportation & Logistics segment revenues were $95.8 million for the three months ended September 30, 2016, compared to $83.3 million for the three months ended September 30, 2015, which represents an increase of $12.6 million, or 15%, in segment revenues. The increase in segment revenues was primarily due to a $9.5 million increase in crude oil transportation services and a $3.1 million increase in the sales of natural gas, NGLs, and crude oil driven by increased volumes of crude oil sold. The increase in crude oil transportation services revenue was primarily driven by increased revenues of $4.5 million related to increased commitments on two throughput and deficiency agreements during the second quarter of 2016 and $4.3 million due to increased volumes transported under existing commitments during the three months ended September 30, 2016 compared to the three months ended September 30, 2015.

Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were $42.6 million for the three months ended September 30, 2016 compared to $39.2 million for the three months ended September 30, 2015, which represents an increase of $3.4 million, or 9%. The overall increase in operating costs and expenses was primarily driven by a $2.0 million increase in cost of sales due to increased volumes of crude oil sold, partially offset by decreased crude oil prices, and a $1.0 million increase in taxes, other than income taxes, as a result of the lateral in Northeast Colorado which was placed in service during the second quarter of 2015.

Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015

Revenues. Crude Oil Transportation & Logistics segment revenues were $283.9 million for the nine months ended September 30, 2016, compared to $208.9 million for the nine months ended September 30, 2015, which represents an increase of $75.0 million, or 36%, in segment revenues primarily due to increased revenues of $40.2 million from a full period of operations on the lateral in Northeast Colorado, which began commercial operations during the second quarter of 2015, an $18.7 million increase related to the activation of one of our joint tariffs in the second quarter of 2015, lower revenue of $9.7 million due to a force majeure at one of our joint tariff partners during the nine months ended September 30, 2015, and a $7.6 million increase in incremental barrels shipped during the nine months ended September 30, 2016.

Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were $124.2 million for the nine months ended September 30, 2016 compared to $105.0 million for the nine months ended September 30, 2015, which represents an increase of $19.2 million, or 18%. The overall increase in operating costs and expenses was primarily driven by a $8.0 million increase in cost of transportation services, a $4.2 million increase in operations and maintenance costs, a $3.7 million increase in depreciation and amortization, and a $2.7 million increase in taxes, other than income taxes all primarily driven by the costs associated with a full period of operations on the lateral in Northeast Colorado, which began commercial operations during the second quarter of 2015.

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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)
Revenues:
Natural gas transportation services	$	32,871	$	30,777	$	93,598	$	94,656
Sales of natural gas, NGLs, and crude oil	935		2,855		1,331		3,534
Processing and other revenues	6		4		20		25
Total revenues	33,812		33,636		94,949		98,215
Operating costs and expenses:
Cost of sales	749		2,565		2,268		2,436
Cost of transportation services	874		2,808		4,171		8,918
Operations and maintenance	8,025		7,263		21,711		20,362
Depreciation and amortization	4,876		5,241		16,233		17,066
General and administrative	3,872		4,104		12,068		12,789
Taxes, other than income taxes	1,162		1,156		3,480		3,655
Total operating costs and expenses	19,558		23,137		59,931		65,226
Operating income	$	14,254	$	10,499	$	35,018	$	32,989


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 14 – Reporting Segments to the accompanying condensed consolidated financial statements.

Three Months Ended September 30, 2016 Compared to the Three Months Ended September 30, 2015

Revenues. Natural Gas Transportation & Logistics segment revenues were $33.8 million for the three months ended September 30, 2016, compared to $33.6 million for the three months ended September 30, 2015, which represents an increase of $0.2 million, or 1%. The increase in segment revenues was primarily due to an increase of $2.1 million in natural gas transportation services primarily driven by increased tariff rates, partially offset by a change in the fuel recovery structure, recognized at TIGT beginning May 1, 2016 as a result of the rate case settlement discussed in Note 12 – Regulatory Matters. The increase in transportation services revenue was partially offset by a $1.9 million decrease in sales of natural gas, NGLs, and crude oil as a result of lower volumes of natural gas sales.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $19.6 million for the three months ended September 30, 2016 compared to $23.1 million for the three months ended September 30, 2015, which represents a decrease of $3.6 million, or 15%. The overall decrease in operating costs and expenses was primarily driven by a $1.9 million decrease in cost of transportation services due to lower costs associated with fuel reimbursements as a result of the change in the fuel recovery structure discussed above and a $1.8 million decrease in cost of sales as a result of lower volumes sold. These decreases were partially offset by a $0.8 million increase in operations and maintenance due to increased pipeline integrity work during the three months ended September 30, 2016.

Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015

Revenues. Natural Gas Transportation & Logistics segment revenues were $94.9 million for the nine months ended September 30, 2016, compared to $98.2 million for the nine months ended September 30, 2015, which represents a decrease of $3.3 million, or 3%, in segment revenues as a result of a $2.2 million decrease in sales of natural gas, NGLs, and crude oil as a result of lower volumes of natural gas sold and a 14% decrease in natural gas prices and a $1.1 million decrease in natural gas transportation services primarily driven by a change in the fuel recovery structure as discussed above and warmer weather conditions that created less demand for short-term transportation capacity during the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015. These decreases were partially offset by increased tariff rates recognized at TIGT subsequent to the rate case settlement effective May 1, 2016.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $59.9 million for the nine months ended September 30, 2016, compared to $65.2 million for the nine months ended September 30, 2015, which represents a decrease of $5.3 million, or 8%. The overall decrease in operating costs and expenses was primarily driven by a $4.7 million decrease in cost of transportation services due to lower costs associated with fuel reimbursements as a result of the change in the fuel recovery structure discussed above, a $0.8 million decrease in depreciation and amortization due to lower depreciation rates as of May 1, 2016 as a result of the TIGT rate case settlement, a $0.7 million decrease in general and administrative costs due to a reduction in allocated costs to the segment and a $0.2 million decrease in cost of sales due to decreased volumes of natural gas sold, partially offset by a reduction in our fuel tracker obligations at Trailblazer driven by the FERC approval of our annual fuel tracker filing during the nine months ended September 30, 2015. These decreases were partially offset by a $1.3 million increase in operations and maintenance due to increased pipeline integrity work during the nine months ended September 30, 2016.

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 September 30,					Nine Months Ended September 30,
Segment Financial Data - Processing & Logistics ⁽¹⁾	2016		2015			2016			2015
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	15,384	$	16,053		$	45,596		$	56,057
Processing and other revenues	8,530		6,553			24,240			26,705
Total revenues	23,914		22,606			69,836			82,762
Operating costs and expenses:
Cost of sales	14,435		14,139			42,516			50,055
Cost of transportation services	1,061		7			2,204			557
Operations and maintenance	3,486		4,151			9,100			9,605
Depreciation and amortization	3,119		3,304			9,418			9,905
General and administrative	1,406		1,111			4,689			3,331
Taxes, other than income taxes	287		106			1,134			318
Loss on disposal of assets	—		—			1,849			4,483
Total operating costs and expenses	23,794		22,818			70,910			78,254
Operating (loss) income	$	120	$	(212	)	$	(1,074	)	$	4,508


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 14 – Reporting Segments to the accompanying condensed consolidated financial statements.

Three Months Ended September 30, 2016 Compared to the Three Months Ended September 30, 2015

Revenues. Processing & Logistics segment revenues were $23.9 million for the three months ended September 30, 2016, compared to $22.6 million for the three months ended September 30, 2015, which represents a $1.3 million, or 6%, increase in segment revenues. The increase in segment revenues was primarily due to a $2.0 million increase in processing and other revenues driven by increased revenue of $2.0 million at Water Solutions primarily attributable to BNN Western, LLC ("Western"), which was acquired on December 16, 2015, and BNN West Texas, LLC ("West Texas"), which commenced operations in March 2016. The increase in processing and other revenues was partially offset by a $0.7 million decrease in the sales of natural gas, NGLs, and crude oil driven by lower NGL sales of $0.4 million due to lower volumes processed, partially offset by increased NGL prices, and lower natural gas sales of $0.3 million due to decreased volumes of natural gas sold.

Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $23.8 million for the three months ended September 30, 2016 compared to $22.8 million for the three months ended September 30, 2015, which represents an increase of $1.0 million, or 4%. The increase in operating costs and expenses was driven by a $1.1 million increase in cost of transportation services due to costs associated with Western, which was acquired on December 16, 2015, a $0.3 million increase in general and administrative costs due to increased costs allocated to Water Solutions as a result of increased operating income related to our acquisitions of Western and West Texas and a $0.3 million increase in cost of sales, partially offset by a $0.7 million decrease in operations and maintenance costs due to less downtime for plant maintenance activities during the three months ended September 30, 2016 compared to the three months ended September 30, 2015.

Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015

Revenues. Processing & Logistics segment revenues were $69.8 million for the nine months ended September 30, 2016, compared to $82.8 million for the nine months ended September 30, 2015, which represents a $12.9 million, or 16%, decrease in segment revenues. The decrease in segment revenues was primarily due to a $10.5 million decrease in the sales of natural gas, NGLs, and crude oil driven by lower NGL sales of $9.4 million due to lower volumes processed and a 7% decrease in NGL prices and a $2.5 million decrease in processing and other revenues driven by lower processing fees at TMID due to decreased volumes processed, partially offset by a $2.3 million increase in revenue at Water Solutions primarily attributable to the recently acquired Western and West Texas assets.

Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $70.9 million for the nine months ended September 30, 2016 compared to $78.3 million for the nine months ended September 30, 2015, which represents a decrease of $7.3 million, or 9%. The decrease in operating costs and expenses was driven by a decrease of $7.5 million in cost of sales, primarily due to decreased NGL prices and volumes processed as discussed above, a decrease of $2.6 million in loss on disposal of assets as a result of the $1.8 million loss on Western assets destroyed by fire as a result of a lightning strike during the nine months ended September 30, 2016, compared to a $4.5 million non-cash loss recognized on the sale of compressor assets at TMID in 2015 and a $0.5 million decrease in operations and maintenance costs due to less downtime for plant maintenance activities during the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015. These decreases were partially offset by a $1.6 million increase in cost of transportation services due to costs associated with Western, which was acquired on December 16, 2015, a $1.4 million increase in general and administrative costs due to increased costs allocated to Water Solutions as a result of increased operating income related to our acquisitions of Western and West Texas and a $0.8 million increase in taxes, other than income taxes, due to higher property tax estimates for 2016 as a result of the Western acquisition.

Liquidity and Capital Resources Overview

Our primary sources of liquidity for the three months ended September 30, 2016 were proceeds from the issuance of long-term debt as discussed further below, borrowings under our revolving credit facility, cash generated from operations, and proceeds from the issuance of common units. 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 maintenance 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 September 30, 2016 and December 31, 2015 was as follows:



	September 30, 2016			December 31, 2015
	(in thousands)
Cash on hand	$	417		$	1,611

Total capacity under the revolving credit facility	1,750,000			1,100,000
Less: Outstanding borrowings under the revolving credit facility ⁽¹⁾	(1,005,000		)	(753,000		)
Available capacity under the revolving credit facility	745,000			347,000
Total liquidity	$	745,417		$	348,611


⁽¹⁾	As of October 31, 2016, our outstanding borrowings under the revolving credit facility were approximately $1.003 billion.

Revolving Credit Facility

Senior Unsecured Notes

On September 1, 2016, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the "Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of the Issuers' 5.50% senior notes due 2024 (the "2024 Notes"). TEP used the net proceeds of the offering to repay outstanding borrowings under its existing senior secured revolving credit facility.

Equity Distribution Agreements

Private Placement

Working Capital

Working capital is the amount by which current assets exceed current liabilities. While various other factors may impact our working capital requirements from period to period, our working capital requirements have typically been, and we expect will continue to be, driven by changes in accounts receivable, accounts payable and deferred revenue. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, and the level of spending for capital expenditures. Changes in the market prices of energy commodities, primarily NGLs, that we buy and sell in the normal course of business can also impact the timing of changes in accounts receivable and accounts payable. Factors impacting deferred revenue include the volume of crude oil transported, the amount of deficiency payments received, and the volume of prior deficiencies utilized during the period.

As of September 30, 2016, we had a working capital deficit of $17.0 million compared to a working capital deficit of $11.7 million at December 31, 2015, which represents a decrease in working capital of $5.3 million. The overall decrease in working capital was primarily attributable to changes in the following components:


•	an increase in deferred revenue of $25.6 million primarily from deficiency payments collected by Pony Express;


•	an increase in accrued taxes of $6.8 million as a result of tax assessments; and


•	a decrease of $4.7 million in accounts receivable primarily due to a decrease in incremental barrels shipped at Pony Express in September 2016 compared to December 2015.

These working capital decreases were partially offset by:


•	an increase of $25.7 million in derivative assets at fair value as a result of the reclassification of the call option derivative to current assets as of September 30, 2016; and


•	a decrease of $5.2 million in accounts payable, primarily driven by the timing of project invoices and payment of contractor retainages related to the construction of the Pony Express lateral in Northeast Colorado.

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:



	Nine Months Ended September 30,
	2016			2015
	(in thousands)
Net cash provided by (used in):
Operating activities	$	305,916		$	197,484
Investing activities	$	(549,566	)	$	(769,771	)
Financing activities	$	242,456		$	590,125

Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015

Operating Activities. Cash flows provided by operating activities were $305.9 million and $197.5 million for the nine months ended September 30, 2016 and 2015, respectively. The increase in net cash flows provided by operating activities of $108.4 million was primarily driven by the increase in operating results as discussed above, distributions received from Rockies Express, and a net increase in cash inflows from changes in working capital, primarily driven by a $19.5 million increase in net cash inflows from accounts receivable due to collection of receivables during the nine months ended September 30, 2016 associated primarily with an increase of incremental barrels shipped at Pony Express, and a $11.3 million increase in deferred revenue associated primarily with deficiency payments received by Pony Express.

Investing Activities. Cash flows used in investing activities were $549.6 million and $769.8 million for the nine months ended September 30, 2016 and 2015, respectively. During the nine months ended September 30, 2016, net cash used in investing activities were driven by cash outflows of $436.0 million for the acquisition of a 25% membership interest in Rockies Express on May 6, 2016, $49.1 million for a portion of the acquisition of an additional 31.3% membership interest in Pony Express on January 1, 2016, the remainder of which is classified as a financing activity as discussed below, capital expenditures of $45.3 million, primarily due to post in-service spending on Pony Express System projects, and contributions to Rockies Express in the amount of $35.5 million. During the nine months ended September 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 $65.1 million, primarily due to construction of the Pony Express System, including the lateral in Northeast Colorado.

Financing Activities. Cash flows provided by financing activities were $242.5 million and $590.1 million for the nine months ended September 30, 2016 and 2015, respectively. Financing cash inflows for the nine months ended September 30, 2016 were primarily driven by:


•	proceeds from the issuance of $400 million in aggregate principal amount of 5.50% Senior Notes due 2024;


•	the issuance of 6,703,984 common units under the Equity Distribution Agreements for net cash proceeds of $290.5 million;


•	net borrowings under the revolving credit facility of $252.0 million;


•	the issuance of 2,416,987 common units representing limited partnership interests in a private placement transaction for net cash proceeds of $90.0 million; and


•	contributions from noncontrolling interests of $8.7 million, which primarily consisted of contributions from TD to Pony Express.

These financing cash inflows were partially offset by cash outflows of:


•	$425.9 million for the portion of the acquisition of an additional 31.3% membership interest in Pony Express which exceeds the cumulative capital spending on the underlying assets acquired; and


•	distributions to unitholders of $207.5 million; and


•	$151.4 million for the partial exercise of the call option granted by TD covering 3,563,146 common units.

Cash flows provided by financing activities for the nine months ended September 30, 2015 were primarily driven by:


•	net cash proceeds of $551.2 million from the issuance of 11,200,000 common units in a public offering;


•	net borrowings under the revolving credit facility of $137.0 million; and


•	contributions from noncontrolling interests of $19.3 million, primarily driven by contributions from TD to Pony Express.

These financing cash inflows were partially offset by distributions to unitholders of $113.3 million.

Distributions

We do not have a legal obligation to pay distributions except as provided in our partnership agreement. A distribution of $0.795 per unit, or $85.3 million in the aggregate, for the three months ended September 30, 2016 was announced on October 5, 2016 and will be paid on November 14, 2016 to unitholders of record on October 31, 2016. As of November 2, 2016, we had a total of 72,949,796 common and general partner units outstanding, which equates to an aggregate minimum quarterly distribution of approximately $21.0 million per quarter and approximately $83.9 million per year. We intend to continue to pay quarterly distributions at or above the amount of the minimum quarterly distribution, which is $0.2875 per unit.

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 $46 million for capital expenditures in 2016, of which approximately $34 million is expected for expansion projects and approximately $12 million, net of anticipated reimbursements from affiliates, 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:



	Nine Months Ended September 30,
	2016		2015
	(in thousands)
Maintenance capital expenditures	$	7,085	$	9,237
Expansion capital expenditures	19,308		17,453
Total capital expenditures incurred	$	26,393	$	26,690

Capital expenditures incurred represent capital expenditures paid and accrued during the period. Capital expenditures are presented net of noncontrolling interest, and contributions and reimbursements received. The decrease in maintenance capital expenditures to $7.1 million for the nine months ended September 30, 2016 from $9.2 million for the nine months ended September 30, 2015 is primarily driven by decreased maintenance capital expenditures in the Processing & Logistics and the Natural Gas Transportation & Logistics segments. 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 increase in expansion capital expenditures to $19.3 million for the nine months ended September 30, 2016 from $17.5 million for the nine months ended September 30, 2015 is primarily driven by spending on the Pony Express System lateral in Northeast Colorado prior to commencement of commercial operations in the second quarter of 2015. Expansion capital expenditures of $19.3 million for the nine months ended September 30, 2016 consisted primarily of post in-service spending on Pony Express System projects.

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 revolving credit facility, 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 2015 Form 10-K.

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 2015 Form 10-K for the year ended December 31, 2015 and have not changed. Our disclosure of critical accounting policies and estimates with respect to goodwill is repeated below for the purpose of providing additional information regarding the impairment testing performed as of December 31, 2015.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Impairment of Goodwill
We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.	We determine fair value using widely accepted valuation techniques, primarily discounted cash flow and market multiple analyses. These techniques are also used when assigning the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. Our impairment analyses require management to apply judgment in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, assessing the probability of different outcomes, including anticipated volumes, contract renewals and changes in our regulated rates, and selecting the discount rate that reflects the risk inherent in future cash flows. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.	We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of the reporting unit, to the extent of the balance of goodwill. A prolonged period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill impairment for reporting units due to the potential impact on our operations and cash flows. We completed our impairment testing of goodwill in the third quarter of 2015 using the methodology described herein, and determined there was no impairment. As a result of a decreased commodity prices in late 2015 and into early 2016, which caused a significant drop in the volumes anticipated from several producers from which TMID receives natural gas for processing, we identified a potential impairment trigger with respect to the $79.2 million of goodwill at the TMID reporting unit, which is a component of our Processing & Logistics segment. We tested TMID's goodwill for impairment as of December 31, 2015 and determined that the fair value of the reporting unit exceeds the carrying value by approximately 21%. As a result, no impairment charge was recorded, however our analysis includes assumptions of a gradual recovery of commodity prices and a corresponding increase in volumes over time. If our outlook for long-term commodity prices is not realized, or our producers further decrease volumes, we could have an impairment in the future. While commodity prices do not have a significant direct exposure to the cash flows projected at TMID, the current commodity price environment has had an indirect impact on TMID's business as certain producers have significantly reduced their anticipated volumes. Keeping all other assumptions constant, as of December 31, 2015 an increase in the discount rate applied of approximately 1.38% or a decrease in overall cash flows by more than 16% would result in a step one failure, however we do not believe that these represent reasonably likely assumptions. If the reporting unit fails step one in the future, we would be required to perform step two of the goodwill impairment test and up to $79.2 million of goodwill at the TMID reporting unit could be written off in the period that the impairment is triggered. During the third quarter of 2016, we completed our annual goodwill impairment testing for all reporting units, and determined that there was no impairment.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

As of September 30, 2016 approximately 91% of our reserved processing capacity was subject to firm or volumetric fee contracts, with the majority of fee revenue based on the volumes actually processed. The remaining 9% was subject to commodity sensitive contracts such as percent of proceeds or keep whole processing contracts. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. We do not currently hedge the commodity exposure in our commodity sensitive contracts in our Processing & Logistics segment and we do not expect to in the foreseeable future. Starting in 2014, the prices of crude oil, natural gas, and NGLs were extremely volatile and declined significantly. Downward pressure and volatility on commodity prices continued in 2015 and the first half of 2016 and may continue for the foreseeable future. These declines directly and indirectly resulted in lower realizations and processing volumes on our percent of proceeds and keep whole processing contracts. Our Processing & Logistics segment comprised approximately 3% of our Adjusted EBITDA for both the three and nine months ended September 30, 2016.

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. During the third quarter of 2016, we entered into a derivative contract for the sale of 30,000 barrels of crude oil, which settled in October 2016. The fair value of this swap was a liability of approximately $7,000 at September 30, 2016.

Historically, we have also had a limited amount of direct commodity price exposure related to natural gas collected for electrical compression costs and lost and unaccounted for gas on the TIGT System. 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. As of September 30, 2016, we had short natural gas swaps outstanding with a notional volume of approximately 0.8 Bcf, representing a portion of the natural gas that is expected to be sold by our Natural Gas Transportation & Logistics segment through the first quarter of 2017. The fair value of these swaps was a liability of approximately $0.2 million at September 30, 2016.

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 commodity prices. A hypothetical 10% increase in the crude oil price forward curve would result in a decrease of approximately $0.1 million in the net fair value of our crude oil derivative instruments as of September 30, 2016. A hypothetical 10% increase in the natural gas price forward curve would result in a decrease of approximately $0.2 million in the fair value of our natural gas derivative instruments as of September 30, 2016 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 2016.

The Commodity Futures Trading Commission ("CFTC") has promulgated regulations to implement the Dodd-Frank Wall Street Reform and Consumer Protection Act'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 Wall Street Reform and Consumer Protection 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, on September 1, 2016 we issued $400 million in 5.50% senior notes due 2024. In addition, we currently have a $1.75 billion revolving credit facility with borrowings of approximately $1.0 billion as of September 30, 2016. 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 revolving 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 $0.5 million based on our debt obligations as of September 30, 2016.

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 or guarantees as forms of credit support. We have historically experienced only minimal credit losses in connection with our receivables.

A substantial majority of our revenue is produced under long-term firm fee contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with slightly under 50% of our revenues derived from customers who have an investment grade credit rating or are part of corporate families with investment grade credit ratings as of September 30, 2016. This represents a decrease in the portion of our revenues derived from customers with an investment grade credit rating from 2015, primarily as a result of credit downgrades at several of our customers and throughout the industry due to the current commodity price environment.

We also have indirect credit risk exposure with respect to our investment in Rockies Express. See Item 1A.—Risk Factors for additional information.

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 September 30, 2016 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 13 – 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 2015 Form 10-K for the year ended December 31, 2015 and Item 1A of our Form 10-Qs for the three months ended March 31, 2016 and June 30, 2016 set 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 September 30, 2016. There have been no material changes to the risk factors contained in our 2015 Form 10-K for the year ended December 31, 2015 and our Form 10-Qs for the quarters ended March 31, 2016 and June 30, 2016.

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

4.1		Indenture, dated September 1, 2016, among Tallgrass Energy Partners, LP, Tallgrass Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee. (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed on September 1, 2016).

4.2		Form of 5.50% Senior Note (included as Exhibit A in Exhibit 4.1 which is incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed on September 1, 2016).

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:	November 2, 2016	By:	/s/ Gary J. Brauchle
			Name:	Gary J. Brauchle
			Title:	Executive Vice President and Chief Financial Officer
				(Duly Authorized Officer and Principal Financial Officer)