Edgar Filing: Tallgrass Energy Partners, LP

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

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, 2013

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

6640 W. 143rd Street, Suite 200

Overland Park, Kansas 66223

(913) 928-6060

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

George E. Rider

6640 W. 143rd Street, Suite 200

Overland Park, Kansas 66223

(913) 928-6060

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

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 1, 2013, the Registrant had 24,300,000 Common Units, 16,200,000 Subordinated Units, and 826,531 General Partner Units outstanding.

TALLGRASS ENERGY PARTNERS, LP

TABLE OF CONTENTS


PART 1 – FINANCIAL INFORMATION			1

Item 1. Financial Statements			1

CONDENSED CONSOLIDATED STATEMENTS OF INCOME			1

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME			2

CONDENSED CONSOLIDATED BALANCE SHEETS			3

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS			4

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL			5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS			6

Item 3. Quantitative and Qualitative Disclosures About Market Risk			41

PART II – OTHER INFORMATION			43

Item 1. Legal Proceedings			43

Item 1A. Risk Factors			43

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			43

Item 3. Defaults Upon Senior Securities			43

Item 4. Mine Safety Disclosures			43

Item 5. Other Information			43

Item 6. Exhibits			44

SIGNATURES			45

Glossary of Common Industry and Measurement Terms

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.

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

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.

FERC: Federal Energy Regulatory Commission.

firm transportation and storage services: Those services pursuant to which customers receive firm assurances regarding the availability of capacity and deliverability of natural gas on our assets up to a contracted amount at specified receipt and delivery points.

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

GHGs: Greenhouse gases.

header system: Networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large diameter high pressure long-haul transportation pipelines.

HP: Horsepower.

interruptible transportation and storage services: Those services pursuant to which customers receive only limited assurances regarding the availability of capacity and deliverability in transportation or storage facilities, as applicable, and pay fees based on their actual utilization of such assets.

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

LNG: Natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.

Mcf: One thousand cubic feet.

MMcf: One million cubic feet.

NGLs: Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).

no-notice service: Those services pursuant to which customers receive the right to transport or store natural gas on 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.

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

play: A proven geological formation that contains commercial amounts of hydrocarbons.

receipt point: The point where production is received by or into a gathering system or transportation pipeline.

reservoir: A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

residue gas: The natural gas remaining after being processed or treated.

shale gas: Natural gas produced from organic (black) shale formations.

tailgate: The point at which processed natural gas and NGLs leave a processing facility for end-user markets.

TBtu: One trillion British Thermal Units.

Tcf: One trillion cubic feet.

throughput: The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period.

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 reservoir that is in addition to the cushion or base gas. It may or may not be completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be used more than once during any season.

working gas storage capacity: The maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes cushion gas and non-cycling working gas.

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 STATEMENTS OF INCOME

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

CONDENSED COMBINED STATEMENTS OF INCOME

(UNAUDITED)


	TEP			TEP Pre- Predecessor		TEP			TEP Pre- Predecessor
	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012		Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(in thousands, except per unit amounts)			(in thousands, except per unit amounts)		(in thousands, except per unit amounts)			(in thousands, except per unit amounts)
Revenues:
Natural gas liquids sales	$	32,216		$	28,519	$	97,307		$	91,257
Natural gas sales		3,053			7,705		7,242			13,118
Transportation services		23,785			26,801		73,446			81,565
Other operating revenues		4,205			1,453		8,924			4,586

Total Revenues		63,259			64,478		186,919			190,526

Operating Costs and Expenses:
Cost of sales and transportation services (exclusive of depreciation and amortization shown below)		31,465			31,060		91,850			85,393
Operations and maintenance		9,430			10,146		25,713			28,154
Depreciation and amortization		7,342			5,949		22,324			17,776
General and administrative		6,071			2,894		15,744			9,593
Taxes, other than income taxes		1,577			2,077		4,748			6,153

Total Operating Costs and Expenses		55,885			52,126		160,379			147,069

Operating Income		7,374			12,352		26,540			43,457

Other Income (Expense):
Interest (expense) income, net		(1,422	)		1,446		(1,458	)		1,446
Interest expense allocated from TD		—			—		(9,028	)		—
Loss on extinguishment of debt		—			—		(17,526	)		—
Other income (expense), net		1,054			87		1,822			(94	)

Total Other (Expense) Income		(368	)		1,533		(26,190	)		1,352

Income Before Income Taxes		7,006			13,885		350			44,809
Texas Margin Taxes		—			20		—			193

Net Income	$	7,006		$	13,865	$	350		$	44,616

Allocation of income for the three and nine months ended September 30, 2013:
Net income attributable to the period from the beginning of the period to May 16, 2013	$	—				$	6,982
Net income (loss) attributable to the period from May 17, 2013 to September 30, 2013		7,006					(6,632	)

Net income	$	7,006				$	350

General partner interest in net income (loss) for the period from May 17, 2013 to September 30, 2013	$	140				$	(133	)

Common and subordinated unitholders’ interest in net income (loss) for the period from May 17, 2013 to September 30, 2013	$	6,866				$	(6,499	)

Basic net income (loss) per common and subordinated unit	$	0.17				$	(0.16	)

Diluted net income (loss) per common and subordinated unit	$	0.17				$	(0.16	)

Basic average number of common and subordinated units outstanding		40,500					40,417
Diluted average number of common and subordinated units outstanding		40,863					40,417

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

CONDENSED COMBINED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)


	TEP		TEP Pre- Predecessor			TEP		TEP Pre- Predecessor
	Three Months Ended September 30, 2013		Three Months Ended September 30, 2012			Nine Months Ended September 30, 2013		Nine Months Ended September 30, 2012
	(in thousands)		(in thousands)			(in thousands)		(in thousands)
Net Income	$	7,006	$	13,865		$	350	$	44,616

Other Comprehensive Income:
Reclassification of change in fair value of derivatives to net income		—		(1,584	)		—		(3,535	)
Change in fair value of derivatives utilized for hedging purposes		—		(366	)		—		978

Total Other Comprehensive Loss		—		(1,950	)		—		(2,557	)

Comprehensive Income	$	7,006	$	11,915		$	350	$	42,059

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


	September 30, 2013		December 31, 2012
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	620	$	—
Accounts receivable, net		22,238		17,848
Accounts receivable from related parties		1,672		6,463
Gas imbalances		1,496		1,282
Inventories		2,670		2,204
Derivative assets at fair value		24		224
Prepayments and other current assets		377		47

Total Current Assets		29,097		28,068

Property, plant and equipment, net		671,720		669,476
Goodwill		302,916		301,852
Deferred financing costs		4,774		—
Deferred financing costs allocated from TD		—		13,352
Other deferred charges		17,729		23,066

Total Assets	$	1,026,236	$	1,035,814

LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities:
Accounts payable	$	33,602	$	35,496
Accounts payable to related parties		1,353		—
Notes payable to related parties		—		1,387
Gas imbalances		2,287		1,250
Derivative liabilities at fair value		5		23
Accrued taxes		4,796		3,465
Current portion of long-term debt allocated from TD		—		4,000
Accrued other current liabilities		13,633		26,233

Total Current Liabilities		55,676		71,854

Long-term debt		226,000		—
Long-term debt allocated from TD		—		390,491
Other long-term liabilities and deferred credits		4,215		1,635

Total Long-term Liabilities		230,215		392,126

Commitments and Contingencies (Note 15)

Partners’ Capital:
Common unitholders (24,300,000 units issued and outstanding at September 30, 2013)		452,273		—
Subordinated unitholder (16,200,000 units issued and outstanding at September 30, 2013)		274,088		—
General partner (826,531 units issued and outstanding at September 30, 2013)		13,984		—
Member’s Capital		—		571,834

Total Partners’ Capital		740,345		571,834

Total Liabilities and Partners’ Capital	$	1,026,236	$	1,035,814

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

CONDENSED COMBINED STATEMENT OF CASH FLOWS

(UNAUDITED)


	TEP			TEP Pre-Predecessor
	Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(in thousands)			(in thousands)
Cash Flows from Operating Activities:
Net income	$	350		$	44,616
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		23,802			17,776
Loss on extinguishment of debt		17,526			—
Noncash compensation expense		948			—
Changes in components of working capital:
Accounts receivable and other		8,614			4,843
Gas imbalances		823			3,821
Inventories		(185	)		(91	)
Accounts payable and accrued liabilities		(630	)		(4,476	)
Regulatory assets		(111	)		—
Other, net		(209	)		618

Net Cash Provided by Operating Activities		50,928			67,107

Cash Flows from Investing Activities:
Capital expenditures		(37,718	)		(12,566	)
Net cash paid for purchase and sale of gas in underground storage		—			(1,147	)
Disposal of property, plant and equipment (net of removal costs)		(274	)		145

Net Cash Used in Investing Activities		(37,992	)		(13,568	)

Cash Flows from Financing Activities:
Repayment of debt assumed from TD		(400,000	)		—
Borrowings under revolving credit facility, net		226,000			—
Payments for deferred financing costs		(5,157	)		—
Proceeds from initial public offering, net of offering costs		290,498			—
Distributions to Member, net		(118,538	)		(53,539	)
Distributions to unitholders		(5,877	)		—
Reimbursement of stock compensation expense from TD		758			—

Net Cash Used in Financing Activities		(12,316	)		(53,539	)

Net Change in Cash and Cash Equivalents		620			—
Cash and Cash Equivalents, beginning of period		—			—

Cash and Cash Equivalents, end of period	$	620		$	—


Supplemental Disclosures:
Cash payments for interest	$	2,155		$	—

Schedule of Noncash Investing and Financing Activities:
Fair value of TIGT and TMID assets contributed by TD	$	1,027,127		$	—
Fair value of TIGT and TMID liabilities contributed by TD	$	(566,849	)	$	—
Increase in accrual for reimbursable construction in progress projects	$	3,516			—
Receivable for unreimbursed stock compensation from TD	$	373			—

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

TALLGRASS ENERGY PARTNERS, LP AND

TALLGRASS ENERGY PARTNERS PREDECESSOR

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(UNAUDITED)


	TEP Predecessor Member’s Capital												Total
				Partners’ Capital
				Limited Partners						General Partner
				Common			Subordinated			General Partner
Balance at January 1, 2013	$	571,834		$	—		$	—		$	—		$	571,834
Net income attributable to the period from January 1, 2013 to May 16, 2013		6,982			—			—			—			6,982
Distributions to Member, net		(118,538	)		—			—			—			(118,538	)
Contribution of net assets of TIGT and TMID		(460,278	)		167,051			278,992			14,235			—
Issuance of units to public (including underwriter over-allotment), net of offering and other costs		—			290,498			—			—			290,498
Net loss attributable to the period from May 17, 2013 to September 30, 2013		—			(3,899	)		(2,600	)		(133	)		(6,632	)
Distributions to unitholders					(3,455	)		(2,304	)		(118	)		(5,877	)
Noncash compensation expense		—			2,078			—			—			2,078

Balance at September 30, 2013	$	—		$	452,273		$	274,088		$	13,984		$	740,345

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

TALLGRASS ENERGY PARTNERS, LP,

TALLGRASS ENERGY PARTNERS PREDECESSOR

AND TALLGRASS ENERGY PARTNERS PRE-PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.	Description of Business

Tallgrass Energy Partners, LP (“TEP”) is a Delaware limited partnership formed in February 2013. On May 17, 2013, TEP closed its initial public offering (the “Offering”) of 14,600,000 common units at a price of $21.50 per unit, which included 1,550,000 of a possible 1,957,500 common units from the partial exercise of the over-allotment option by the underwriters. Proceeds to TEP from the sale of the common units were approximately $295.9 million, net of the underwriters’ discount. In addition, TEP recognized $5.4 million of other costs associated with the offering, including legal, accounting, printing and consulting fees, resulting in total net proceeds of $290.5 million.

In connection with the Offering, Tallgrass Development, LP (“TD”) contributed 100% of the membership interests in TIGT and TMID, as each is defined below, to TEP in exchange for (i) 9,700,000 common units, inclusive of the remaining 407,500 overallotment units not issued to the underwriters, and 16,200,000 subordinated units, (ii) TEP’s assumption of $400 million of indebtedness related to TD’s acquisition of TIGT and TMID and (iii) $85.5 million in cash as reimbursement for a portion of the capital expenditures made by TD to purchase the contributed assets. In addition, a payment of approximately $31.2 million, equal to the net proceeds from the issuance of the overallotment units to the underwriters, was distributed by TEP to TD. At the closing of the Offering, TEP used the total proceeds, net of the underwriters’ discount, of approximately $295.9 million to repay approximately $295.9 million of the debt assumed from TD.

The 14,600,000 common units held by the public constitute approximately 36% of TEP’s outstanding limited partner interests and approximately 35% of TEP’s total equity, exclusive of Incentive Distribution Rights (“IDRs”). TD’s 9,700,000 common units and 16,200,000 subordinated units collectively comprise approximately 64% of TEP’s outstanding limited partner interests and approximately 63% of TEP’s overall equity, exclusive of IDRs. In addition, as part of the contribution transaction, 826,531 general partner units, representing a 2% general partner interest in TEP, and all of our IDRs were issued to Tallgrass MLP GP, LLC (the “GP”). For detail regarding the IDRs see Note 10 – Partnership Equity and Distributions. In connection with the Offering, TEP entered into a revised partnership agreement on May 17, 2013. The revised partnership agreement requires TEP to distribute its available cash on a quarterly basis, subject to certain terms and conditions, beginning with the quarter ended June 30, 2013. For additional information, see Note 10 – Partnership Equity and Distributions.

The term “Predecessor Entities” refers to both Tallgrass Energy Partners Predecessor (“TEP Predecessor”) and Tallgrass Energy Partners Pre-Predecessor (“TEP Pre-Predecessor”), which are comprised of the businesses described below that were owned by Kinder Morgan Energy Partners, LP (“TEP Pre-Predecessor Parent”) prior to November 13, 2012. On November 13, 2012, TEP Pre-Predecessor Parent sold those assets, among others, to TD. The Predecessor Entities are referred to as TEP Predecessor for the period in which they were owned by TD, from November 13, 2012 through the completion of the Offering on May 17, 2013, and as TEP Pre-Predecessor for periods in which they were owned by TEP Pre-Predecessor Parent, prior to November 13, 2012.

The businesses included in the Predecessor Entities consist of:

•

Tallgrass Interstate Gas Transmission, LLC (“TIGT”), an interstate gas pipeline and storage system that is regulated by the Federal Energy Regulatory Commission (“FERC”). TIGT currently has approximately 5,250 miles of varying diameter natural gas transmission lines in Colorado, Kansas, Missouri, Nebraska and Wyoming. Upon receipt of FERC approval and completion of construction of certain gas facilities necessary to maintain existing natural gas service, TIGT will sell approximately 432 miles of natural gas pipeline, along with the associated rights of way and certain other equipment, to a subsidiary of TD. For more information, see Note 14 – Regulatory Matters.

•

Tallgrass Midstream, LLC (“TMID”) is a Delaware limited liability company that owns and operates one treating and two processing plants in Wyoming.

Prior to the sale of these assets to TD on November 13, 2012, TIGT was named Kinder Morgan Interstate Gas Transmission LLC and TMID was named KM Upstream LLC.

For additional information regarding the acquisition of TIGT and TMID, see Note 3 – Business Combinations.

2.	Summary of Significant Accounting Policies

Basis of Presentation

These unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2013 and the unaudited condensed combined financial statements for the three and nine months ended September 30, 2012 have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include disclosures required by GAAP for annual periods. The unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2013 and the unaudited condensed combined financial statements for the three and nine months ended September 30, 2012 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair presentation of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC.

Our financial results for the three and nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2013. These unaudited condensed consolidated financial statements should be read in conjunction with our combined financial statements and notes thereto included in our final prospectus dated May 13, 2013 (the “Prospectus”) and filed with the Securities Exchange Commission (the “SEC”) pursuant to Rule 424 on May 14, 2013.

The accompanying unaudited condensed consolidated financial statements of TEP include historical cost-basis accounts of the assets of TEP Predecessor, contributed to us by TD in connection with the Offering for the periods prior to May 17, 2013, the closing date of TEP’s Offering, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. Both TEP and TEP Predecessor are considered “entities under common control” as defined under GAAP and, as such, the transfer between the entities of the assets and liabilities has been recorded by TEP at historical cost. TEP, or the Partnership, as used herein refers to the consolidated financial results and operations for TEP Predecessor from its inception through its contribution to TEP and thereafter.

The condensed combined financial statements of the Predecessor Entities include legal entities, as detailed above, that are indirect wholly-owned subsidiaries of the Predecessor Entities. As the condensed combined financial statements reflect TEP Predecessor and TEP Pre-Predecessor as single entities, significant intra-entity items have been eliminated in the presentation. Net equity distributions of the Predecessor Entities included in the Condensed Combined Statements of Equity and Condensed Combined Statements of Cash Flows represent transfers of cash as a result of TD and TEP Pre-Predecessor Parent’s centralized cash management systems prior to May 17, 2013, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions.

TEP’s financial results as presented on the condensed consolidated statements of income, comprehensive income and cash flows have been separated from TEP Pre-Predecessor’s financial results by a bold vertical black line.

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 TEP or the Predecessor Entities’ business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

New Accounting Pronouncements Adopted

ASU No. 2011-11, Balance Sheet (Topic 210), “Disclosures about Offsetting Assets and Liabilities” and ASU No. 2013-01, Balance Sheet (Topic 210), “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities”

On December 16, 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210), “Disclosures about Offsetting Assets and Liabilities”. ASU 2011-11 requires entities to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. In January 2013, the FASB issued ASU No. 2013-01, Balance Sheet (Topic 210), “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarifies that the scope of ASU No. 2011-11 applies to derivatives accounted for in accordance with the Codification guidance for derivatives and hedging transactions, including bifurcated embedded derivatives, repurchase agreements and reverse purchase agreements, and certain securities borrowing and securities lending transactions. Entities are required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. All disclosures provided by those amendments are required to be provided retrospectively for all comparative periods presented. The adoption of ASU 2011-11 on January 1, 2013 did not have a material impact on TEP’s financial statements.

ASU No. 2013-02, Comprehensive Income (Topic 220), “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220), “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”. ASU 2013-02 does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, the amendments require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component, either on the face of the statement where net income is presented or in the notes, depending on whether or not the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. ASU 2013-02 is effective for public entities prospectively for reporting periods beginning after December 15, 2012, or January 1, 2013 for TEP. The adoption of ASU 2013-02 did not have a material impact on TEP’s financial statements.

3.	Business Combinations

On November 13, 2012, TD completed the acquisition of certain assets from TEP Pre-Predecessor Parent for approximately $1.8 billion in cash and approximately $1.5 billion of assumed debt. The acquisition included a 100% equity interest in both TIGT and TMID, as discussed in Note 1 – Description of Business. Of the approximately $1.8 billion in cash paid to acquire all of the net assets, $573.2 million was allocated to TIGT and TMID. The contribution of the assets and liabilities of TIGT and TMID from TD to TEP, which was effective on May 17, 2013, was accounted for as a transaction between entities under common control under ASC 805.

At December 31, 2012, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. TD is in the process of obtaining additional information to identify and measure all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be retrospectively adjusted to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts.

During the nine months ended September 30, 2013, the preliminary purchase price allocation was adjusted for certain immaterial items related to regulatory assets and accrued liabilities. As the changes were not considered material to TEP or the purchase price allocation, the adjustments are not retrospectively reflected in the accompanying condensed combined balance sheet as of December 31, 2012.

Prior to May 17, 2013, the long-term debt held by TD was guaranteed by TIGT and TMID, and $400 million of that debt was expected to be assumed by TEP concurrently with the Offering, and was therefore allocated to TIGT and TMID along with the related deferred financing costs at November 13, 2012. On May 17, 2013, concurrently with the closing of the Offering, this $400 million of the long-term debt held by TD was assumed and repaid by TEP. TIGT and TMID were also released as guarantors of the TD debt and became guarantors of the TEP revolving credit facility. For additional information, see Note 9 – Long-term Debt.

The goodwill recorded in the condensed consolidated balance sheet is expected to be deductible for tax purposes. The goodwill is primarily attributable to (i) the strategic location of the assets, including access to key supply sources and major customer demand markets; (ii) the complementary location of the assets relative to each other and relative to key market areas; (iii) growth opportunities through production growth requiring processing in the Rockies; (iv) future pipeline interconnects and fertilizer and power plant conversions that may potentially provide volume growth opportunities; and (v) a trained workforce. For additional information regarding goodwill, see Note 7 – Goodwill.

The following unaudited pro forma financial information for the historical periods is presented as if the acquisition of TIGT and TMID had been completed on January 1, 2012. 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 Pre-Predecessor for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements.


	TEP Pre-Predecessor
	Three Months Ended September 30, 2012		Nine Months Ended September 30, 2012


	(in thousands)
Revenue	$	64,478	$	190,526
Net income	$	6,497	$	22,512

Pro forma revenue contains no adjustments to the historical amounts. Pro forma net income includes adjustments for the three and nine months ended September 30, 2012 to give effect to the following:

(a)

Reduction in net income to reflect additional depreciation expense associated with the increase in the cost of property, plant and equipment that resulted from the allocation of the purchase price to the fair value of the assets and liabilities acquired by TD.

(b)

Reduction in net income to reflect interest expense on the long-term debt allocated to TIGT and TMID in connection with the acquisition of TIGT and TMID by TD.

4.	Related Party Transactions

TEP has no employees. TEP Pre-Predecessor Parent historically provided and charged TEP Pre-Predecessor for all direct and indirect costs of services provided to us or incurred on our behalf including employee labor costs, information technology services, employee health and life benefits, and all other expenses necessary or appropriate to the conduct of our business. Beginning November 13, 2012, TD provided and charged TEP for similar direct and indirect costs of services. TEP and TEP Pre-Predecessor record these costs on the accrual basis in the period in which TEP Pre-Predecessor Parent (or TD, beginning November 13, 2012) incurs them. Each of the wholly-owned companies comprising TEP and TEP Pre-Predecessor had agency arrangements with TEP Pre-Predecessor Parent or its affiliates (prior to November 13, 2012) and TD (beginning November 13, 2012) under which TEP Pre-Predecessor Parent, or its contractually obligated affiliate, or TD, as applicable, pay costs and expenses incurred by TEP and TEP Pre-Predecessor, act as agents for TEP and TEP Pre-Predecessor, and are reimbursed by TEP and TEP Pre-Predecessor for such payments. While the substance of the operating agreement remains the same, the cost structure under new management has changed, which affected the basis of certain allocations when the agreements transitioned from TEP Pre-Predecessor Parent to TD.

On May 17, 2013, in connection with the closing of the Offering, TEP and its subsidiaries entered into an Omnibus Agreement with TD and certain of its affiliates. The Omnibus Agreement provides that, among other things, TEP will reimburse TD and its affiliates for all expenses they incur and payments they make on our 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.

For the calendar year 2013, TEP’s annual cost reimbursements to TD for costs discussed above, are expected to be $18.5 million. Effective May 17, 2013, TEP will also pay a quarterly reimbursement to TD for costs associated with being a public company. The quarterly public company reimbursement amount is expected to be $625,000 in 2013. These reimbursement amounts will be periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEP.

Due to the cash management agreements discussed in Note 2 – Summary of Significant Accounting Policies, intercompany balances between the Predecessor Entities were periodically settled and treated as equity distributions prior to the completion of the Offering on May 17, 2013.

Totals of transactions with affiliated companies are as follows:


	TEP			TEP Pre-Predecessor		TEP			TEP Pre-Predecessor
	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012		Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(in thousands)			(in thousands)		(in thousands)			(in thousands)
Cost of sales and transportation services	$	1,119		$	680	$	1,016		$	4,313
Charges to TEP and TEP Pre-Predecessor:⁽¹⁾
Property, plant and equipment, net	$	140		$	153	$	4,979		$	990
Other deferred charges	$	6		$	49	$	1,098		$	106
Operation and maintenance	$	3,863		$	3,721	$	11,461		$	11,575
General and administrative	$	6,006	⁽²⁾	$	3,038	$	15,594	⁽²⁾	$	7,740

⁽¹⁾	Charges to TEP and TEP Pre-Predecessor include directly charged wages and salaries, other compensation and benefits, and shared services.

⁽²⁾	During the three and nine months ended September 30, 2013, TEP reimbursed TD for general and administrative expenses as discussed above, resulting in a single allocated amount for general and administrative costs rather than individual charges as in prior periods.

Details of balances with affiliates included in “Accounts receivable” and “Accounts payable” in the Condensed Consolidated Balance Sheets are as follows:


	September 30, 2013		December 31, 2012
	(in thousands)
Accounts receivable from affiliated companies:
Tallgrass Operations, LLC	$	—	$	6,244
Rockies Express Pipeline LLC		1,672		219

Total accounts receivable from affiliated companies	$	1,672	$	6,463

Payables to affiliated companies:
Note payable to TD	$	—	$	1,381
Interest payable to TD		—		6
Accounts payable to Tallgrass Operations, LLC		1,307		—
Accounts payable to Rockies Express Pipeline LLC		46		—

Total payables to affiliated companies	$	1,353	$	1,387

As of September 30, 2013 and December 31, 2012, TEP had $0.9 million and $0.3 million, respectively, in gas imbalance payables with affiliated entities.

Pursuant to the terms of a Purchase and Sale Agreement dated August 1, 2012, TD (on behalf of its wholly-owned subsidiary, Tallgrass Pony Express, LLC (“PXP”) is reimbursing TIGT for all costs TIGT incurs with respect to the Pony Express Pipeline Conversation Project, as defined in Note 14 – Regulatory Matters, inclusive of development costs, capital costs and related interest costs associated with securing regulatory approvals for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System (“Replacement Gas Facilities”). The Replacement Gas Facilities are required as part of the Pony Express Pipeline Conversion Project and are being made for TIGT to be able to continue existing service to customers after the Pony Express assets are sold to TD. Expenditures are being captured in Other Deferred Charges on the balance sheet as they are incurred and interest will be accrued until reimbursement takes place. At September 30, 2013 TEP had $6.8 million in Other Deferred Charges related to this project. During the three and nine months ended September 30, 2013, reimbursements of $4.3 million related to expenditures prior to the closing of the Offering on May 17, 2013 were settled as equity distributions with TD. During the three and nine months ended September 30, 2013, reimbursements of $7.7 million related to expenditures subsequent to the closing of the Offering on May 17, 2013 were cash settled with TD.

5.	Inventory

The components of inventory at September 30, 2013 and December 31, 2012 consisted of the following:


	September 30, 2013		December 31, 2012
	(in thousands)
Materials and supplies	$	1,606	$	1,567
Natural gas liquids		770		637
Gas in underground storage		294		—

Total inventory	$	2,670	$	2,204

6.	Property, Plant and Equipment

The components of property, plant and equipment at September 30, 2013 and December 31, 2012 consisted of the following:


	September 30, 2013			December 31, 2012
	(in thousands)
Natural gas pipelines	$	421,756		$	421,644
Processing and treating assets		199,743			195,108
Buildings		15,518			15,518
Vehicles		3,239			3,138
Gas in underground storage		1,768			2,345
Land		1,534			1,534
General and other		1,218			1,207
Construction work in progress		52,106			32,932
Accumulated depreciation and amortization		(25,162	)		(3,950	)

Total property, plant and equipment, net	$	671,720		$	669,476

7.	Goodwill

As discussed in Note 3 – Business Combinations, we recorded $302.9 million of goodwill in connection with the acquisition of TIGT and TMID in 2012. Of the $302.9 million of goodwill at September 30, 2013, $224.9 million was assigned to the Gas Transportation and Storage segment and $78.0 million was assigned to the Processing segment. For more information regarding our segments, see Note 12 – Reporting Segments.

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

TEP did not elect to apply the qualitative assessment option during our 2013 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 purposes 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 substantially 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 2013. 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

TEP and TEP Pre-Predecessor enter into derivative contracts with third parties for the purpose of hedging exposures that accompany their normal business activities. TEP and TEP Pre-Predecessor’s normal business activities expose them to risks associated with changes in the market price of natural gas, among other commodities. Specifically, the risks associated with changes in the market price of natural gas, include, among others (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. Prior to November 13, 2012, TEP Pre-Predecessor applied hedge accounting to these derivative contracts. As discussed below, TEP elected not to apply hedge accounting.

Beginning on November 13, 2012, all previously hedge-designated derivative contracts were de-designated and changes in the fair value of all derivative contracts are now recorded in earnings in the period in which the change occurs. Accumulated other comprehensive income associated with the derivative contracts was immaterial as of the de-designation date and was eliminated in purchase accounting.

During the three and nine months ended September 30, 2012, TEP Pre-Predecessor recognized no gain or loss on derivatives associated with the ineffectiveness of these hedges and did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness. Under hedge accounting, as the hedged sales and purchases took place and TEP Pre-Predecessor recorded them into earnings in the same period, TEP Pre-Predecessor also reclassified the associated gains and losses included in accumulated other comprehensive income into earnings. During the three and nine months ended September 30, 2012, no gain or loss was reclassified into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period.

Fair Value of Derivative Contracts

The following table summarizes the fair values of TEP’s derivative contracts included in the accompanying Condensed Consolidated Balance Sheets:


	Balance Sheet Location	September 30, 2013		December 31, 2012
		(in thousands)
Energy commodity derivative contracts	Current assets	$	24	$	224

Total derivative assets		$	24	$	224


	Balance Sheet Location	September 30, 2013		December 31, 2012
		(in thousands)
Energy commodity derivative contracts	Current liabilities	$	5	$	23

Total derivative liabilities		$	5	$	23

As of September 30, 2013, the fair value shown for commodity contracts was comprised of derivative volumes totaling 0.2 Bcf of both fixed price and basis swaps.

Effect of Derivative Contracts on the Income Statement

The following tables summarize the impact of derivative contracts for the three and nine months ended September 30, 2013 and 2012:

Amount of gain/(loss) recognized in OCI on derivatives (effective portion)

TEP

TEP Pre-Predecessor

TEP

TEP Pre-Predecessor

Three Months
Ended
September 30, 2013

Three Months
Ended
September 30, 2012

Nine Months
Ended
September 30, 2013

Nine Months
Ended
September 30, 2012

(in thousands)

Derivatives in cash flow hedging relationships:

Energy commodity derivative contracts

—

(366

)

—

978

Amount of (gain)/loss reclassified from Accumulated OCI into income (effective portion)

Location of gain/
(loss) reclassified
from AOCI
into income
(effective portion)

TEP

TEP Pre-Predecessor

TEP

TEP Pre-Predecessor

Three Months
Ended
September 30, 2013

Three Months
Ended
September 30, 2012

Nine Months
Ended
September 30, 2013

Nine Months
Ended
September 30, 2012

(in thousands)

Derivatives in cash flow hedging relationships:

Energy commodity derivative contracts

Natural gas sales

—

1,584

—

3,535

Amount of gain/(loss) recognized in income on derivatives

Location of gain/
(loss) recognized

in income on

derivative

TEP

TEP Pre-Predecessor

TEP

TEP Pre-Predecessor

Three Months
Ended
September 30, 2013

Three Months
Ended
September 30, 2012

Nine Months
Ended
September 30, 2013

Nine Months
Ended
September 30, 2012

(in thousands)

Derivatives not designated as hedging contracts:

Energy commodity derivative contracts

Natural gas sales

(91

)

—

(375

)

—

Credit Risk

TEP has counterparty credit risk as a result of their use of financial derivative contracts. TEP’s counterparties consist of major financial institutions. This concentration of counterparties may impact TEP’s 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.

TEP maintains credit policies that it believes minimize its overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings), (ii) collateral requirements under certain circumstances and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on its policies and exposure, TEP’s management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.

TEP’s over-the-counter swaps are entered into with counterparties outside central trading organizations such as a futures, options or stock exchange. These contracts are with a financial institution with an investment grade credit rating. While TEP enters into derivative transactions principally with investment grade counterparties and actively monitors their ratings, it is nevertheless possible that from time to time losses will result from

counterparty credit risk in the future. The maximum potential exposure to credit losses on TEP’s derivative contracts at September 30, 2013 was:


	Asset Position
	(in thousands)
Gross exposure	$	24
Netting agreement impact		(5	)
Cash collateral held		—

Net exposure	$	19

In addition, in conjunction with the purchase of exchange-traded derivative contracts, or when the market value of TEP’s derivative contracts with specific counterparties exceeds established limits, TEP is required to provide collateral to its counterparties, which may include posting letters of credit or placing cash in margin accounts. As of September 30, 2013 and December 31, 2012, TEP did not have any outstanding letters of credit in support of its hedging of commodity price risks associated with the sale of natural gas. As of September 30, 2013 and December 31, 2012, TEP had no margin deposits with counterparties associated with energy commodity contract positions. TEP also has agreements with certain counterparties to its derivative contracts that contain provisions requiring it to post additional collateral upon a decrease in its credit rating. As of September 30, 2013, TEP had no derivative instruments with credit-risk-related contingent features in a net liability position and would not have to post additional collateral if a downgrade was triggered.

Fair Value

Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or traded 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. TEP values exchange-traded derivative contracts using quoted market prices for identical securities.

OTC derivatives are valued using models utilizing a variety of inputs including contractual terms as well as 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. TEP uses similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.

Certain OTC derivative contracts trade in less liquid markets with limited pricing information, and the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to TEP’s 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 tables summarize the fair value measurements of TEP’s energy commodity derivative contracts as of September 30, 2013 and December 31, 2012 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)
TEP as of September 30, 2013
Energy commodity derivative contracts	$	24	$	—	$	24	$	—

TEP as of December 31, 2012
Energy commodity derivative contracts	$	224	$	—	$	224	$	—


	Liability fair value measurements using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)




	(in thousands)
TEP as of September 30, 2013
Energy commodity derivative contracts	$	5	$	—	$	5	$	—

TEP as of December 31, 2012
Energy commodity derivative contracts	$	23	$	—	$	23	$	—

The table below provides a summary of changes in the fair value of TEP and TEP Pre-Predecessor’s significant unobservable inputs (Level 3) energy commodity derivative contracts:


	TEP		TEP Pre-Predecessor		TEP		TEP Pre-Predecessor
	Three Months Ended September 30, 2013		Three Months Ended September 30, 2012		Nine Months Ended September 30, 2013		Nine Months Ended September 30, 2012


	(in thousands)		(in thousands)		(in thousands)		(in thousands)
Derivatives – net asset (liability):
Beginning of period	$	—	$	—	$	—	$	(352	)
Total gains or (losses)
Included in other comprehensive income		—		—		—		(62	)
Settlements		—		—		—		157
Transfers out of Level 3		—		—		—		257

End of period	$	—	$	—	$	—	$	—

The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets held at the reporting date	$	—	$	—	$	—	$	—

During the nine months ended September 30, 2012, derivative liabilities with a fair value of $257,000 were transferred from Level 3 to Level 2 as the level of observable inputs used to value those instruments was deemed to be significant.

9.	Long-term Debt

Long-term Debt Allocated from TD

On November 13, 2012, TD entered into a credit agreement with a syndicate of lenders which included a term loan, a delayed draw term loan and a revolving credit facility. The term loan matures on November 13, 2018 and bears interest at a variable rate equal to a reserve adjusted Eurodollar rate + 4.00%, subject to a LIBOR floor of 1.25%, or an alternate base rate + 3.00%. During the three months ended March 31, 2013, TD elected the reserve adjusted Eurodollar rate + 4.00% rate, however, on April 30, 2013 the $400 million of the term loan allocated to TEP was converted to the alternate base rate + 3.00%. As discussed in Note 3 – Business Combinations, $400 million of the term loan, along with the corresponding discount and deferred financing costs, was allocated to TEP on November 13, 2012. The term loan is an obligation of TD and prior to May 17, 2013, was guaranteed by TIGT and TMID.

Upon the closing of the Offering on May 17, 2013, TEP legally assumed the previously allocated $400 million portion of the TD term loan and used a portion of the Offering proceeds, along with borrowings under TEP’s new $500 million credit agreement effective May 17, 2013, to repay its $400 million portion of the term loan, at which time TIGT and TMID were released as guarantors of the TD debt. TEP recognized a loss on extinguishment of debt of $17.5 million during the nine months ended September 30, 2013 associated with the portion of deferred financing costs and unamortized discount on the amount of the TD term loan that was allocated to TEP.

New Revolving Credit Facility

On May 17, 2013, in connection with the Offering, TEP entered into a $500 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders (“the revolving credit facility”), which will mature on May 17, 2018. On the closing date of the Offering, TEP borrowed $231.0 million under the credit facility, the proceeds of which were used to (i) repay the approximately $104.1 million of debt assumed from TD that remained after payment of a portion of the assumed debt with proceeds from the Offering; (ii) pay a distribution to TD of $31.2 million equal to the net proceeds from the exercise of the underwriter’s overallotment option to purchase additional common units; (iii) pay $85.5 million to TD as reimbursement for a portion of the capital expenditures made by TD to purchase the contributed assets and (iv) pay origination fees related to the new revolving credit facility and certain other fees associated with the Offering, and fund working capital requirements of TEP. The remaining commitments under the credit facility are available to provide for capital expenditures, permitted acquisitions, working capital needs and for other general partnership purposes. The credit facility has an accordion feature that will allow TEP to increase the available revolving borrowings under the credit facility by up to an additional $100 million, subject to TEP’s receipt of increased or new commitments from lenders and satisfaction of certain other conditions. In addition, the credit facility includes a sublimit up to $40 million for swing line loans and a sublimit up to $50 million for letters of credit. As of September 30, 2013, TEP had outstanding borrowings of $226.0 million and had issued letters of credit totaling $0.7 million.

TEP’s obligations under the credit facility are (i) guaranteed by TEP and each of its existing and subsequently acquired or organized direct or indirect wholly-owned domestic subsidiaries, subject to TEP’s ability to designate certain of its subsidiaries as “Unrestricted Subsidiaries” and (ii) secured by a first priority lien on substantially all of the present and after acquired property owned by TEP and each guarantor (other than real property interests related to TEP’s pipelines).

enter into non arms-length transactions with affiliates and designate certain subsidiaries as “Unrestricted Subsidiaries.” In addition, 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 are required. As of September 30, 2013, TEP is in compliance with the covenants required under the revolving credit facility.

Borrowings under the credit facility bear interest, at TEP’s option, at either (a) a base rate, which is a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% or (iii) a one-month reserve adjusted Eurodollar rate plus 1.00%, in each case, plus an applicable margin, or (b) a reserve adjusted Eurodollar rate, plus an applicable margin. Swing line loans bear interest at the base rate plus an applicable margin. For borrowings bearing interest based on the base rate, the applicable margin is initially 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is initially 2.00%. After September 30, 2013, the applicable margin will range from 1.00% to 2.00% for base rate borrowings and from 2.00% to 3.00% for reserve adjusted Eurodollar rate borrowings, based upon TEP’s total leverage ratio. The unused portion of the credit facility is subject to a commitment fee, which is initially 0.375%, and after September 30, 2013, is either 0.375% or 0.500%, based on TEP’s total leverage ratio. As of September 30, 2013, the weighted average interest rate on outstanding borrowings was 2.21%.

TEP’s long-term debt consisted of the following at September 30, 2013 and December 31, 2012:


	September 30, 2013		December 31, 2012
	(in thousands)
Borrowings under revolving credit facility	$	226,000	$	—
Term loan due 2018 (allocated from TD)		—		400,000
Unamortized discount		—		(5,509	)

Total principal		226,000		394,491
Current maturities		—		(4,000	)

Total long-term debt	$	226,000	$	390,491

The following table sets forth the carrying amount and fair value of TEP’s long-term debt, which is not measured at fair value in the Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012, 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)
September 30, 2013	$	—	$	226,000	$	—	$	226,000	$	226,000
December 31, 2012	$	—	$	404,000	$	—	$	404,000	$	394,491

The long-term debt borrowed under the revolving credit facility and the term loan allocated from TD were carried at amortized cost. As of September 30, 2013, the fair value approximates the carrying amount for the borrowings under the revolving credit facility using a discounted cash flow analysis. The fair value of the debt allocated from TD at December 31, 2012 was estimated based on quoted market prices. TEP is not aware of any factors that would significantly affect the estimated fair value since September 30, 2013.

10.

Partnership Equity and Distributions

As discussed in Note 1 – Description of Business, TD completed the acquisition of TEP Pre-Predecessor subsidiary entities on November 13, 2012. On May 17, 2013, in conjunction with the closing of TEP’s initial

public offering, TD’s ownership interest in TIGT and TMID was contributed to TEP in exchange for 9,700,000 common and 16,200,000 subordinated units.

Distributions to Holders of Common Units, Subordinated Units and General Partner Units

TEP’s partnership agreement requires TEP to distribute its available cash, defined below, to unitholders of record on the applicable record date within 45 days after the end of each quarter, beginning with the quarter ended June 30, 2013. The first quarterly cash distribution, which was prorated for the period from May 17, 2013 to June 30, 2013, in the amount of $0.1422 per unit, was declared on July 18, 2013 and was paid on August 13, 2013 to unitholders of record on July 31, 2013. A distribution of $0.2975 per unit for the three months ended September 30, 2013 was declared on October 7, 2013 and will be paid on November 13, 2013 to unitholders of record on November 1, 2013.

TEP’s partnership agreement provides that available cash, each quarter, is first distributed to the common unitholders and the general partner on a pro rata basis until each common unitholder has received $0.2875 per unit, which amount is defined in TEP’s partnership agreement as the minimum quarterly distribution (“MQD”). During the subordination period, defined below, each holder of common units must receive the MQD, plus the cumulative amount of any arrearages in the payment of the MQD from prior quarters, before distributions of available cash from operating surplus may be made on the subordinated units.

Subordinated Units

All subordinated units are currently held by TD. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive a distribution of available cash until the holders of common units have received the MQD plus any cumulative arrearages in MQD from previous quarters. Furthermore, subordinated unitholders are not entitled to receive arrearages in previous quarter distributions. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution milestones described in the partnership agreement have been met. The earliest date on which the subordination period may end is June 30, 2014.

Incentive Distribution Rights

The GP owns a 2% general partner interest in TEP which is represented by 826,531 general partner units. The GP also owns all of the incentive distribution rights (“IDRs”). IDRs represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the MQD and the target distribution levels have been achieved. The GP may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. Under TEP’s partnership agreement, the general partner may at any time contribute additional capital to TEP in order to maintain its 2% general partner interest.

The following discussion related to incentive distributions assumes that TEP’s general partner maintains its 2.0% general partner interest and continues to own all of the IDRs.

If for any quarter:

•

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

•

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

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

•

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

•

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

•

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

•

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

Definition of Available Cash

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

•

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

•

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

•

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

•

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

•

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

Distributions to TD

As discussed in Note 2 – Summary of Significant Accounting Policies, prior to May 17, 2013, the net amount of transfers for loans made each day through the centralized cash management system, less reimbursement payments under the agency agreement described in Note 4 – Related Party Transactions, was recognized periodically as equity distributions. Excluding the second quarter cash distributions paid to TD as a common and subordinated unitholder, as discussed above, there were no distributions from TEP to TD for the three months ended September 30, 2013 and net distributions for the nine months ended September 30, 2013 of $118.5 million. The distribution for the nine months ended September 30, 2013 included the $85.5 million to TD related to the contribution of TIGT and TMID to TEP as well as the $31.2 million net proceeds from the exercise of the underwriter’s option to purchase additional common units as part of the Offering. Net distributions from TEP Pre-Predecessor to TD for the three and nine months ended September 30, 2012 were $13.5 million and $53.5 million, respectively.

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 using the two-class method by dividing net income available to common and subordinated unitholders by the weighted average number of outstanding limited partner units during the period. Net income available to common and subordinated unitholders is defined as the limited partners’ interest in the net income remaining after general partner incentive distributions.

Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. However, because our Offering was completed on May 17, 2013, the number of units issued following the Offering is utilized for the 2013 periods presented. Diluted earnings per unit reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.

As the Offering was completed on May 17, 2013, no income from the three months ended March 31, 2013 is allocated to the limited partner units that were issued on May 17, 2013. Net income per limited partner unit is not applicable for the three and nine months ended September 30, 2012 as no units were outstanding during those periods.

The following table illustrates the Partnership’s calculation of net income per limited partner unit for the periods indicated:


	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013			Period from January 1, 2013 to May 16, 2013		Period from May 17, 2013 to September 30, 2013
	(in thousands, except per unit amounts)
Net Income (Loss)	$	7,006	$	350		$	6,982	$	(6,632	)
General partner interest in net income (loss)		140		6,849			6,982		(133	)

Net income (loss) available to common and subordinated unitholders	$	6,866	$	(6,499	)	$	—	$	(6,499	)

Basic net loss per common and subordinated unit	$	0.17	$	(0.16	)			$	(0.16	)

Diluted net loss per common and subordinated unit	$	0.17	$	(0.16	)			$	(0.16	)

Basic average number of common and subordinated units outstanding		40,500		40,417					40,417
Equity Participation Unit equivalent units		363		—					—

Diluted average number of common and subordinated units outstanding		40,863		40,417					40,417

The calculation of the basic and diluted net income per common and subordinated unit are the same for the current period as distributable cash flow is greater than the reported net income (loss).

The calculation of diluted net loss per common and subordinated unit for the nine months ended September 30, 2013 excluded approximately 1.5 million Equity Participation Units (“EPUs”) outstanding at September 30, 2013 that could potentially dilute net income per common and subordinated unit in the future. These EPUs were not included in the computation of diluted net income per common and subordinated unit for the nine months ended September 30, 2013 because their impact would be anti-dilutive given the reported net loss to common and subordinated unitholders. Had TEP generated net income available to common and subordinated unitholders in the nine months ended September 30, 2013, approximately 933,000 potential common units related to the EPUs would have been included in diluted average units outstanding. See Note 13 – Equity-Based Compensation for additional information regarding the EPUs.

12.

Reporting Segments

Our operations are located in the United States and are organized into two reporting segments: (1) Gas Transportation and Storage, and (2) Processing.

Gas Transportation and Storage

The Gas Transportation and Storage segment is engaged in ownership and operation of interstate natural gas pipelines and related natural gas storage facilities that provide services to third-party natural gas distribution utilities and other shippers.

Processing

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

Corporate and Other

Corporate and Other includes corporate overhead costs incurred subsequent to the Offering on May 17, 2013 which 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 reimbursed to TD, and equity-based compensation expense.

These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations.

Prior to the second quarter of 2013, the Predecessor Entities considered operating income to be its primary segment performance measure. Beginning in the second quarter of 2013, TEP began using Adjusted EBITDA as its primary segment performance measure as it provides a more meaningful measure to assess TEP’s financial condition and results of operations as a public entity. Adjusted EBITDA, a non-GAAP measure, is defined as net income before 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 disposals and gains or losses on the repurchase, redemption or early retirement of debt.

The following tables set forth TEP and TEP Pre-Predecessor’s segment information for the periods indicated:


	TEP							TEP Pre-Predecessor
	Three Months Ended September 30, 2013							Three Months Ended September 30, 2012
	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)							(in thousands)
Gas transportation and storage	$	26,434	$	(151	)	$	26,283	$	31,091	$	(184	)	$	30,907
Processing		36,976		—			36,976		33,571		—			33,571
Corporate and other		—		—			—		—		—			—

Total revenue	$	63,410	$	(151	)	$	63,259	$	64,662	$	(184	)	$	64,478


	TEP							TEP Pre-Predecessor
	Nine Months Ended September 30, 2013							Nine Months Ended September 30, 2012
	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)							(in thousands)
Gas transportation and storage	$	77,920	$	(521	)	$	77,399	$	90,637	$	(597	)	$	90,040
Processing		109,520		—			109,520		100,486		—			100,486
Corporate and other		—		—			—		—		—			—

Total revenue	$	187,440	$	(521	)	$	186,919	$	191,123	$	(597	)	$	190,526


	TEP									TEP Pre-Predecessor
	Three Months Ended September 30, 2013									Three Months Ended September 30, 2012
	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA		Inter- Segment			External Adjusted EBITDA
	(in thousands)									(in thousands)
Gas transportation and storage	$	13,733		$	(151	)	$	13,582		$	14,677	$	(184	)	$	14,493
Processing		3,644			151			3,795			3,711		184			3,895
Corporate and other		(632	)		—			(632	)		—		—			—

Reconciliation to Income (Loss) before Income Taxes:
Interest expense (income), net								1,422								(1,446	)
Texas Margin Taxes								—								20
Depreciation and amortization expense								7,342								5,949
Non-cash loss related to
derivative instruments								112								—
Non-cash compensation expense								863								—

Income before income taxes							$	7,006							$	13,865


	TEP									TEP Pre-Predecessor
	Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA		Inter- Segment			External Adjusted EBITDA
	(in thousands)									(in thousands)
Gas transportation and storage	$	37,043		$	(521	)	$	36,522		$	45,603	$	(597	)	$	45,006
Processing		15,713			521			16,234			15,536		597			16,133
Corporate and other		(939	)		—			(939	)		—		—			—

Reconciliation to Income (Loss) before Income Taxes:
Interest expense (income), net								10,486								(1,446	)
Texas Margin Taxes								—								193
Depreciation and amortization expense								22,324								17,776
Loss on extinguishment of debt								17,526								—
Non-cash loss related to derivative instruments								183								—
Non-cash compensation expense								948								—

Income before income taxes							$	350							$	44,616


	TEP
	Total Assets
	September 30, 2013		December 31, 2012
	(in thousands)
Gas transportation and storage	$	706,218	$	741,595
Processing		312,998		294,219
Corporate and other		7,020		—

Total assets	$	1,026,236	$	1,035,814

13.

Equity-Based Compensation

Long-term Incentive Plan

Effective May 13, 2013, our general partner adopted a Long-term Incentive Plan (“LTIP”) pursuant to which awards in the form of unrestricted units, restricted units, equity participation units, options, unit appreciation rights or distribution equivalent rights may be granted to employees, consultants, and directors of the general partner and its affiliates who perform services for or on behalf of TEP or its affiliates. Vesting and forfeiture requirements are at the discretion of the Board of Directors of our general partner at the time of the grant.

Equity Participation Units

On June 26, 2013, our general partner approved the grant of up to 1.5 million equity participation units (“EPUs”) under the LTIP. Effective the same date, 1.49 million EPUs were granted to employees and directors of our general partner and its affiliates. Vesting of the EPUs is contingent upon the Pony Express Pipeline Conversion Project (see Note 14 – Regulatory Matters) being placed in service and will occur in two parts, with one-third vesting on the later of the Pony Express in-service date or May 13, 2015, and remaining two-thirds vesting on the later of the Pony Express in-service date or May 13, 2017. If the Pony Express Pipeline project has not been placed in service by May 13, 2018, the EPUs will expire and no vesting of the EPUs will occur.

The EPU grants under the LTIP plan are measured at their grant date fair value. The EPUs are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TEP’s common units for the present value of the expected future dividends during the vesting period. Total equity-based compensation cost related to the EPU grants of approximately $2.0 million and $2.1 million was recognized during the three and nine months ended September 30, 2013, respectively. Of the total compensation cost, $0.9 million and $1.0 million was recognized as compensation expense at TEP for the three and nine month periods ending September 30, 2013 and the remainder was allocated to TD. As of September 30, 2013, $19.6 million of total compensation cost related to non-vested EPUs is expected to be recognized over a weighted-average period of 2.9 years, a portion of which will be charged as expense to TD.

The following table summarizes the changes in the EPUs outstanding for the three and nine months ended September 30, 2013:


	Three Months Ended September 30, 2013						Nine Months Ended September 30, 2013
	Shares			Weighted Average Grant Date Fair Value			Shares			Weighted Average Grant Date Fair Value
Beginning of period	$	1,490,000		$	17.49		$	—		$	—
Granted		5,500			18.92			1,495,500			17.49
Forfeited		(29,500	)		(17.49	)		(29,500	)		(17.49	)

End of period	$	1,466,000		$	17.49		$	1,466,000		$	17.49

14.

Regulatory Matters

TIGT

Pony Express Pipeline Conversion Project – FERC Docket CP12-495

On August 6, 2012, TIGT filed an application to: (1) abandon for FERC purposes approximately 432 miles of mainline natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the “Pony Express Assets”), and the natural gas service therefrom by transfer to an affiliate, PXP, for the purpose of converting the facilities into crude oil pipeline facilities; and (2) construct and operate certain replacement-type facilities necessary to continue service to existing natural gas firm transportation customers following the proposed conversion. We refer to this project as the Pony Express Pipeline Conversion Project. The FERC abandonment does not constitute an abandonment for accounting purposes. Pursuant to the terms of the Purchase and Sale Agreement filed in this docket and cited by FERC in approving the Conversion Project, PXP will reimburse TIGT for the net book value of the natural gas pipeline facilities plus other TIGT incurred costs required to construct gas replacement facilities and to arrange substitute gas transportation services to certain TIGT shippers.

The Pony Express Pipeline Conversion Project, upon FERC approval and implementation, will re-deploy existing pipeline assets to meet the growing market need to transport oil supplies from the Bakken Shale while, at the same time continuing to operate TIGT’s natural gas transportation facilities to meet all current and expected needs of its natural gas customers. Such application, upon approval by the FERC, will authorize the reconversion of a portion of the Pony Express Pipeline back to the transportation of crude oil as it was prior to 1997. By order issued September 12, 2013, TIGT was granted authorization to abandon the Pony Express Assets and construct the Pony Express Pipeline Conversion Project facilities. On October 7, 2013 TIGT commenced the mobilization of personnel and equipment for the construction of the project facilities necessary to complete the Pony Express Pipeline Conversion Project to continue service to existing TIGT customers.

15.

Legal and Environmental Matters

Legal

Other than the matters discussed below, TEP is a defendant in various lawsuits arising from the day-to-day operations of their business. Although no assurance can be given, TEP believes, based on its experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on its business, financial position, results of operations or cash flows.

TEP records a liability for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. TEP has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and, accordingly, recorded no reserve for claims as of September 30, 2013. TEP recorded aggregate reserves for all claims of approximately $0.1 million as of December 31, 2012. This reserve is reported on the accompanying Condensed Combined Balance Sheets within “other accrued liabilities.”

TMID

West Frenchie Draw

TMID was a party to the following legal actions pertaining to its West Frenchie Draw treating plant:

Elkhorn Construction, Inc. v. KM Upstream LLC and Newpoint Gas Services, Inc., Civil Action No. 36823 in the District Court of Fremont County, Wyoming (9^th Judicial District) (the “Trial Court Action”); Elkhorn Construction, Inc. v. KM Upstream LLC, Appeal No. S-11-0186 and S-11-0208 in the Wyoming Supreme Court (the “Appeal”); In Re: Newpoint Gas, L.P., Case No. 10-16104 in the U.S. Bankruptcy Court for the Western District of Oklahoma (Oklahoma City) (“the Newpoint Bankruptcy”).

Elkhorn Construction, Inc., (“Elkhorn”) a sub-contractor to Newpoint Gas Services, Inc. (“Newpoint Gas Services”) filed suit on March 23, 2009 in Fremont County, Wyoming to enforce liens against TMID arising in connection with the West Frenchie Draw Amine Plant in the principal amount of approximately $4.9 million plus interest, late charges, attorney’s fees and costs from January 16, 2009. On November 24, 2009, Newpoint Gas Services was added to the litigation as a defendant. TMID and Newpoint Gas Services filed cross-claims against each other. On September 21, 2012, TMID paid the adjudicated portion of Elkhorn’s mechanics lien of $4.7 million plus 7% interest from the date of the lien for a total payment of $5.9 million. On April 30, 2013, the Court awarded Elkhorn additional principal and interest (including post-judgment interest) on its mechanic’s lien claim. On May 30, 2013, TMID paid approximately $0.2 million to satisfy the remaining portion of Elkhorn’s mechanic’s lien claim. On June 12, 2013, the Court granted Elkhorn’s motion for summary judgment seeking enforcement and foreclosure of its oil and gas lien claim, which provides for the recovery of attorney’s fees and costs by Elkhorn.

Newpoint Gas L.P. (“Newpoint LP”), a closely held affiliate of Newpoint Gas Services, commenced the above-referenced bankruptcy court case under Chapter 7 of the Bankruptcy Code. TMID filed an adversary proceeding in the bankruptcy action seeking to consolidate the assets and liabilities of Newpoint Gas Services with Newpoint LP. The judge issued an order dismissing the adversary proceeding on June 10, 2013 based on a finding that the Trustee was the only party with standing to seek substantive consolidation. TMID’s claim in the bankruptcy case has been withdrawn.

In August of 2013, the Company fully and finally settled all legal actions with Newpoint Gas Services and Elkhorn. In exchange for cash settlement payments from TMID, the parties released and dismissed all claims against each other with prejudice.

ConocoPhillips Off-Spec Product Deliveries

In April and May of 2009, TMID delivered to ConocoPhillips NGL product that was alleged by a ConocoPhillips affiliate to contain fluoride levels that exceeded contract tolerances. In February 2012, TMID paid $1.1 million to settle this issue with the affiliated refinery that received the product from ConocoPhillips. TMID recognized the full settlement amount of $1.1 million in 2009. In 2012, TMID recovered $350,000 from two parties who delivered the contested product to TMID and this matter is now concluded.

TIGT

Cornhusker Energy Lexington Plant Explosion

TIGT is the defendant in a lawsuit pending in state court in Douglas County, Nebraska (CI 10 9387384). Plaintiffs in the suit are Cornhusker Energy Lexington, LLC and its insurer, National Union Fire Insurance Company of Pittsburgh, Pennsylvania. The suit was initiated in February 2010. Plaintiffs allege that Cornhusker received natural gas that was transported on the TIGT System that did not meet required pipeline specifications, and as a result Cornhusker’s ethanol plant suffered an explosion and subsequent fire. Plaintiffs complaint requests monetary relief, attorney’s fees, costs and interest of approximately $3.9 million; however in connection with mediation in May 2013, Plaintiffs increased the amount of their alleged damages in a statement to the mediator. Although we believe Cornhusker’s claims to be without merit, TD has agreed to indemnify TIGT for any settlement of damage award in excess of the $3.9 million, pursuant to an Omnibus Agreement between TD and TEP, among others. A trial date has been set by the Court for November 2013.

System Failures

On May 4, 2013 and on June 13, 2013, a failure occurred on two separate segments of the TIGT pipeline system; one in Kimball County, Nebraska and one in Goshen County, Wyoming. The failures both resulted in the release of natural gas. Both lines were promptly brought back into service and neither failure caused any known injuries, fatalities, fires or evacuations. The costs to repair or replace the damaged section in Kimball County,

Nebraska were not material; such costs related to the Goshen County failure are not currently believed to be material. The scope and cost of any additional investigation and remediation activities are currently being evaluated.

Environmental

TEP is 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. TEP believes that compliance with these laws will not have a material adverse impact on their business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause TEP to incur significant costs. TEP had recorded environmental accruals of $3.5 million at September 30, 2013 and December 31, 2012.

TMID

Casper and Douglas Plants, United States Environmental Protection Agency Notice of Violation

In March 2011, the United States Environmental Protection Agency (“U.S. EPA”) and the Wyoming Department of Environmental Quality (“WDEQ”) conducted an inspection at the Douglas and Casper Gas Plants in Wyoming. In June 2011, TMID received two letters from the U.S. EPA alleging violations at both gas plants of the Risk Management Program requirements under the Clean Air Act. TMID has executed Combined Complaint and Consent Agreements with the U.S. EPA, including monetary penalties of $158,000 for each facility, to resolve these allegations, which were approved by the U.S. EPA in September 2012.

Casper Plant, U.S. EPA Notice of Violation

In August 2011, the U.S. EPA and the WDEQ conducted an inspection of the Leak Detection and Repair (“LDAR”) Program at the Casper Gas Plant in Wyoming. In September 2011, TMID received a letter from the U.S. EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. In April 2013, TMID received a letter from the U.S. EPA concerning settlement of this matter. Settlement negotiations with the U.S. EPA are continuing, including resolution of more recently identified LDAR issues.

Casper Mystery Bridge Superfund Site

The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and TEP has requested that the portion of the site attributable to TEP be delisted from the National Priorities List.

16.

Subsequent Events

On October 1, 2013, TIGT received a payment from TD, on behalf of PXP, in the amount of $84.9 million in connection with the expected sale of the Pony Express Assets, the proceeds of which were used to repay $85.0 million of borrowings under the revolving credit facility. For additional information regarding the sale of the Pony Express Assets, see Note 14 – Regulatory Matters.

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

The historical financial statements included in this Quarterly Report reflect the combined results of operations of Tallgrass Interstate Gas Transmission, LLC and Tallgrass Midstream, LLC, which we refer to collectively as “our Predecessor.” In connection with our initial public offering on May 17, 2013, Tallgrass Development LP (“TD”) contributed to us its equity interests in our Predecessor. The following discussion analyzes the financial condition and results of operations of our Predecessor. In certain circumstances and for ease of reading we discuss the financial results of our Predecessor as being “our” financial results during historic periods, although our Predecessor was owned by Kinder Morgan prior to November 13, 2012 and by TD from November 13, 2012 until May 17, 2013. As used in this Quarterly Report, unless the context otherwise requires, “we,” us,” our,” the “Partnership” and similar terms refer to Tallgrass Energy Partners, LP, together with its consolidated subsidiaries.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report and the audited financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations for the year ended December 31, 2012 included in our final prospectus dated May 13, 2013 (the “Prospectus”) and filed with the Securities Exchange Commission (the “SEC”) pursuant to Rule 424 on May 14, 2013.

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:

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changes in general economic conditions;

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competitive conditions in our industry;

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

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the demand for natural gas storage and transportation services;

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our ability to successfully implement our business plan;

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our ability to complete internal growth projects on time and on budget;

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the price and availability of debt and equity financing;

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the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels;

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competition from the same and alternative energy sources;

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energy efficiency and technology trends;

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operating hazards and other risks incidental to transporting, storing and processing natural gas;

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

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interest rates;

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labor relations;

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large customer defaults;

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changes in the availability and cost of capital;

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changes in tax status;

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the effects of existing and future laws and governmental regulations;

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the effects of future litigation; and

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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 growth-oriented Delaware limited partnership that owns, operates, acquires and develops midstream energy assets in North America. We currently provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions through our TIGT System and provide processing services for customers through our Midstream Facilities located in Wyoming.

We intend 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:

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

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

How We Evaluate Our Operations

We evaluate our results using, among other measures, contract mix and volumes, operating costs and expenses, Adjusted EBITDA and distributable cash flow. Adjusted EBITDA and distributable cash flow are non-GAAP measures and are defined below.

Contract Mix and Volumes

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

Operating Costs and Expenses

The primary components of our operating costs and expenses that we evaluate include cost of sales and transportation services, operations and maintenance and general and administrative. Our operating expenses 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:

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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;

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

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

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

We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Non-GAAP Measures

We define Adjusted EBITDA as net income before 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 disposals and gains or losses on the repurchase, redemption or early retirement of debt. We have not quantified distributable cash flow on a historical basis, however subsequent to the closing of the Offering we began to use distributable cash flow, which we define as Adjusted EBITDA less cash interest cost and maintenance capital expenditures, to analyze our performance. Neither Adjusted EBITDA nor distributable cash flow will be impacted by changes in working capital balances that are reflected in operating cash flow. Distributable cash flow and Adjusted EBITDA are not presentations made in accordance with GAAP.

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

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:


	TEP			TEP Pre-Predecessor			TEP			TEP Pre-Predecessor
	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012			Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(in thousands)			(in thousands)			(in thousands)			(in thousands)
Reconciliation of Adjusted EBITDA to Net Income (Loss)
Net income	$	7,006		$	13,865		$	350		$	44,616
Add:
Interest (income) expense, net		1,422			(1,446	)		10,486			(1,446	)
Depreciation and amortization expense		7,342			5,949			22,324			17,776
Loss on extinguishment of debt		—			—			17,526			—
Non-cash (gain) loss related to derivative instruments		112			—			183			—
Texas Margin Tax		—			20			—			193
Non-cash compensation expense		863			—			948			—

Adjusted EBITDA	$	16,745		$	18,388		$	51,817		$	61,139

Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	21,291		$	16,553		$	50,928		$	67,107
Add:
Interest expense, net		1,422			(1,446	)		10,486			(1,446	)
Texas Margin Tax		—			20			—			193
Other, including changes in operating working capital		(5,968	)		3,261			(9,597	)		(4,715	)

Adjusted EBITDA	$	16,745		$	18,388		$	51,817		$	61,139

Less:
Maintenance capital expenditures		(3,725	)					(5,670	)
Cash interest cost		(1,559	)					(2,322	)

Distributable Cash Flow	$	11,461					$	43,825

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:


	TEP		TEP Pre-Predecessor		TEP		TEP Pre-Predecessor
	Three Months Ended September 30, 2013		Three Months Ended September 30, 2012		Nine Months Ended September 30, 2013		Nine Months Ended September 30, 2012
	(in thousands)		(in thousands)		(in thousands)		(in thousands)
Reconciliation of Adjusted EBITDA to Operating Income in the Gas Transportation and Storage Segment⁽¹⁾
Operating income	$	6,988	$	9,450	$	17,751	$	30,288
Add:
Depreciation and amortization expense		5,693		5,140		17,399		15,409
Non-cash (gain) loss related to derivative instruments		112		—		183		—
Other income (expense)		940		87		1,710		(94	)

Segment Adjusted EBITDA	$	13,733	$	14,677	$	37,043	$	45,603

Reconciliation of Adjusted EBITDA to Operating Income in the Processing Segment⁽¹⁾
Operating income	$	1,874	$	2,902	$	10,667	$	13,169
Add:
Depreciation and amortization expense		1,649		809		4,925		2,367
Other income (expense)		121		—		121		—

Segment Adjusted EBITDA	$	3,644	$	3,711	$	15,713	$	15,536

(1)

Segment results as presented represent total revenue and Adjusted EBITDA, including intersegment activity, for the Gas Transportation and Storage and Processing segments. Corporate and Other segment activity is excluded. For reconciliations to the consolidated financial data, see Note 12 – Reporting Segments to the accompanying consolidated financial statements.

Results of Operations

The following provides a summary of our results of operations for TEP and TEP Pre-Predecessor for the periods indicated:


	TEP			TEP Pre-Predecessor		TEP			TEP Pre-Predecessor
	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012		Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(in thousands, except operating data)			(in thousands, except operating data)		(in thousands, except operating data)			(in thousands, except operating data)
Statements of Operations Data
Revenues:
Natural gas liquids sales	$	32,216		$	28,519	$	97,307		$	91,257
Natural gas sales		3,053			7,705		7,242			13,118
Transportation services		23,785			26,801		73,446			81,565
Other operating revenues		4,205			1,453		8,924			4,586

Total revenues		63,259			64,478		186,919			190,526

Operating costs and expenses:
Cost of sales and transportation services		31,465			31,060		91,850			85,393
Operations and maintenance		9,430			10,146		25,713			28,154
Depreciation and amortization		7,342			5,949		22,324			17,776
General and administrative		6,071			2,894		15,744			9,593
Taxes, other than income taxes		1,577			2,077		4,748			6,153

Total operating costs and expenses		55,885			52,126		160,379			147,069

Operating income		7,374			12,352		26,540			43,457
Interest income (expense), net		(1,422	)		1,446		(1,458	)		1,446
Interest expense allocated from TD		—			—		(9,028	)		—
Loss on extinguishment of debt		—			—		(17,526	)		—
Other income (expense), net		1,054			87		1,822			(94	)

Income before income taxes		7,006			13,885		350			44,809
Texas Margin Taxes		—			20		—			193

Net Income (Loss) to Member	$	7,006		$	13,865	$	350		$	44,616

Other Financial Data⁽¹⁾
Adjusted EBITDA	$	16,745		$	18,388	$	51,817		$	61,139
Operating Data
Operating Data (Mmcf/d):
Transportation firm contracted capacity		667			747		669			777
Natural gas processing inlet volumes		120			124		128			121

(1)	For more information regarding Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable GAAP measure, please see “Management’s Discussion and Analysis – Non-GAAP Financial Measures” above.


	TEP		TEP Pre-Predecessor		TEP		TEP Pre-Predecessor
	Three Months Ended September 30, 2013		Three Months Ended September 30, 2012		Nine Months Ended September 30, 2013		Nine Months Ended September 30, 2012
	(in thousands)		(in thousands)		(in thousands)		(in thousands)
Segment Financial Data – Gas Transportation and Storage⁽¹⁾
Revenues:
Natural gas sales	$	2,494	$	4,096	$	3,935	$	8,195
Transportation services		23,936		26,985		73,967		82,162
Other operating revenues		4		10		18		280

Total revenues		26,434		31,091		77,920		90,637

Operating costs and expenses:
Cost of sales and transportation services		2,042		5,423		7,731		10,536
Operations and maintenance		6,478		7,117		19,295		21,246
Depreciation and amortization		5,693		5,140		17,399		15,409
General and administrative		3,733		2,217		11,231		7,526
Taxes, other than income taxes		1,500		1,744		4,513		5,632

Total operating costs and expenses		19,446		21,641		60,169		60,349

Operating income	$	6,988	$	9,450	$	17,751	$	30,288

Segment Adjusted EBITDA	$	13,733	$	14,677	$	37,043	$	45,603
Segment Financial Data – Processing⁽¹⁾
Revenues:
Natural gas liquids sales	$	32,216	$	28,519	$	97,307	$	91,257
Natural gas sales		559		3,609		3,307		4,923
Other operating revenues		4,201		1,443		8,906		4,306

Total revenues		36,976		33,571		109,520		100,486

Operating costs and expenses:
Cost of sales and transportation services		29,574		25,821		84,640		75,454
Operations and maintenance		2,952		3,029		6,418		6,908
Depreciation and amortization		1,649		809		4,925		2,367
General and administrative		850		677		2,635		2,067
Taxes, other than income taxes		77		333		235		521

Total operating costs and expenses		35,102		30,669		98,853		87,317

Operating income	$	1,874	$	2,902	$	10,667	$	13,169

Segment Adjusted EBITDA	$	3,644	$	3,711	$	15,713	$	15,536

(1)

Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012

Revenues. Total revenues were $63.3 million for the three months ended September 30, 2013, compared to $64.5 million for the three months ended September 30, 2012, which represents a 2% decrease in total revenues. The decrease in revenues in the Gas Transportation and Storage segment was 15%, which was partially offset by an increase in revenues in the Processing segment of 10%.

In the Processing segment, the $3.4 million increase in revenues during the three months ended September 30, 2013 compared to the same period in 2012, was primarily driven by an increase in sales of NGLs as well as an increase in processing fee income, which were partially offset by a decrease in natural gas sales. The increase in NGL sales of $3.7 million was driven by a 5% higher average sales price as well as increased volume of gas processed due to new contracts in 2013. The increase in NGL revenue would have been even greater on a comparative basis if not for the annual planned plant downtime and additional downtime associated with expansion projects at the Douglas plant in the third quarter of 2013. The annual planned downtime at the Douglas plant occurred in the second quarter of 2012. Increased processing fee revenue of $2.8 million during the third quarter 2013 is primarily attributable to new or revised fee-based contracts that were not in effect during the third quarter 2012. Partially offsetting the increases in NGL sales revenue of the Processing segment, natural gas sales revenue decreased by $3.1 million due to decreased natural gas sales in the third quarter of 2013 compared to the third quarter of 2012 as a result of natural gas purchase and sales transactions during the third quarter of 2012 to redirect processed dry gas around the Casper plant in order to optimize plant capacity and efficiency. These transactions increased both revenue and cost of sales by $2.0 million in the third quarter of 2012. In the Gas Transportation and Storage segment, total revenue decreased $4.7 million, or 15%, for the three months ended September 30, 2013. The decrease in revenues was primarily driven by a $3.1 million decrease in transportation services revenue and a $1.6 million decrease in natural gas sales revenue. The decrease in transportation services revenue was primarily due to a decrease in transportation firm contracted capacity. The decrease in natural gas sales revenue was primarily caused by lower sales volume as well as a 24% decrease in the average sales price.

Operating costs and expenses. Operating costs and expenses were $55.9 million for the three months ended September 30, 2013 compared to $52.1 million for the three months ended September 30, 2012, which represents an increase of 7%.

Cost of sales and transportation services increased by $0.4 million in the three months ended September 30, 2013 when compared to the three months ended September 30, 2012. The increase in cost of sales and transportation services was primarily driven by an increase of $3.8 million in the Processing segment due to higher prices and an increase in NGL producer payments resulting from the conversion of certain keep whole processing contracts to fee-based during 2013. The increases were partially offset by a decrease in natural gas purchases during 2013 due to the natural gas purchase and sales transactions in 2012 and the timing of the annual planned plant downtime at Douglas, both discussed above. The increase in cost of sales and transportation services in the Processing segment was partially offset by a decrease in cost of sales and transportation services in the Gas Transportation and Storage segment of $3.4 million primarily due to decreased costs associated with gas sales, a high volume shipper imbalance cash settled during the third quarter of 2013, and decreased penalties associated with shipper imbalances.

Operations and maintenance costs decreased by $0.7 million during the three months ended September 30, 2013 when compared to the same period in 2012, primarily driven by decreased operating costs in the Gas Transportation and Storage segment.

Depreciation and amortization was higher in both segments in the three months ended September 30, 2013 compared to the three months ended September 30, 2012 due to the higher cost basis of property, plant and equipment as a result of the acquisition of TIGT and TMID on November 13, 2012.

General and administrative expenses during the three months ended September 30, 2013 were $3.2 million, or 110%, higher than they were in the comparable prior period. The increase was largely reflective of the parent company of TEP Pre-Predecessor Parent’s scale advantage during the 2012 period in supporting similar required administrative functions by a substantially larger number of operated business, as well as the costs associated with being a public company beginning in the second quarter of 2013.

Texas Margin Taxes. During 2012, TEP Pre-Predecessor incurred Texas Margin Taxes because it was a part of an affiliated group that generated sales in the State of Texas. Subsequent to the acquisition of TIGT and TMID by TD in November 2012, we are no longer subject to Texas Margin Taxes or any other income-based taxes based on currently enacted tax legislation.

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012

Revenues. Total revenues were $186.9 million for the nine months ended September 30, 2013, compared to $190.5 million for the nine months ended September 30, 2012, which represents a 2% decrease in total revenues. Revenue in the Gas Transportation and Storage segment decreased 14% while revenues in the Processing segment increased 9%.

The Gas Transportation and Storage segment total revenues for the nine months ended September 30, 2013 decreased $12.7 million to $77.9 million from $90.6 million for the nine months ended September 30, 2012. The decrease in revenues was primarily driven by an $8.2 million decrease in transportation services revenue and a $4.3 million decrease in natural gas sales revenue. The decrease in transportation services revenue was primarily due to a decrease in transportation firm contracted capacity partially offset by an increase in fuel recoveries. The decrease in natural gas sales revenue was primarily caused by lower sales volume as well as a 26% decrease in the average sales price. The Processing segment total revenues for the nine months ended September 30, 2013 increased $9.0 million to $109.5 million from $100.5 million for the nine months ended September 30, 2012. The increase in revenues was primarily driven by (i) increased NGL sales revenue of $6.1 million due to an increase in volumes of NGLs during the nine months ended September 30, 2013 compared to the same period in 2012 as a result of new contracts, and (ii) an increase in processing fees of $4.6 million resulting from new or revised fee-based contracts that were not in effect during the 2012 period. These increases were partially offset by a $1.6 million decrease in natural gas sales due to the natural gas purchase and sales transactions discussed above, which resulted in $2.0 million of revenue in the third quarter of 2012.

Operating costs and expenses. Operating costs and expenses were $160.4 million for the nine months ended September 30, 2013 compared to $147.1 million for the nine months ended September 30, 2012, which represents a 9% increase.

Cost of sales and transportation services for the nine months ended September 30, 2013 increased by $6.5 million when compared to the nine months ended September 30, 2012. The increase was primarily driven by a $9.2 million increase in the Processing segment cost of sales due to increased processing volumes related to new contracts in 2013 offset by gas purchases of $2.0 million related to the natural gas purchases in 2012 discussed above, partially offset by a $2.8 million decrease in the Gas Transportation and Storage segment due to decreased costs associated with lower gas sales.

Operations and maintenance costs decreased $2.4 million during the nine months ended September 30, 2013 when compared to the same period in 2012. The decrease is primarily driven by decreased expenses at the Gas Transportation and Storage segment related to (i) decreased operating costs associated with a section of pipe which was idle during the third quarter of 2013 as the sole shipper under contract for that section was not transporting gas during the quarter; (ii) decreased electrical costs associated with lower compression usage; and (iii) a reduction in the amount of maintenance projects during 2013 when compared to the same period in 2012.

Depreciation and amortization was higher in both segments during the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 due to the higher cost basis of property, plant and equipment as a result of the acquisition of TIGT and TMID on November 13, 2012.

General and administrative expenses during the nine months ended September 30, 2013 were $6.2 million higher than they were for the same period in the prior year. The increase was largely reflective of the parent company of TEP Pre-Predecessor Parent’s scale advantage during the 2012 period in supporting similar required administrative functions by a substantially larger number of operated businesses, as well as the additional costs associated with being a public company beginning in the second quarter of 2013.

Liquidity and Capital Resources Overview

Our primary sources of liquidity for the three and nine months ended September 30, 2013 were proceeds from the Offering, borrowings under our revolving credit facility, and cash generated from operations. We expect our sources of liquidity in the future to include:

•

cash generated from our operations;

•

proceeds from the sale of the Pony Express Assets, a significant portion of which was received on October 1, 2013 (see Note 14 – Regulatory Matters and Note 16 – Subsequent Events to the accompanying financial statements in this Form 10-Q);

•

borrowing capacity available under our revolving credit facility that was entered into on May 17, 2013 in connection with the Offering; and

•

future issuances of additional partnership units and debt securities.

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

Initial Public Offering

On May 17, 2013, TEP closed the Offering of 14,600,000 common units at a price of $21.50 per unit, which included 1,550,000 of a possible 1,957,500 common units from the partial exercise of the over-allotment option by the underwriters. Proceeds to TEP from the sale of the common units were approximately $295.9 million, net of the underwriters’ discount. In addition, TEP recognized $5.4 million of other costs associated with the offering, including legal, accounting, printing and consulting fees, resulting in total net proceeds of $290.5 million.

In connection with the Offering, TD contributed 100% of the membership interests in TIGT and TMID to TEP in exchange for (i) 9,700,000 common units, inclusive of the remaining 407,500 overallotment units not issued to the underwriters, and 16,200,000 subordinated units, (ii) TEP’s assumption of $400 million of indebtedness related to TD’s acquisition of TIGT and TMID and (iii) $85.5 million in cash as reimbursement for a portion of the capital expenditures made by TD to purchase the contributed assets. In addition, TEP distributed to TD a payment equal to the net proceeds from the issuance of the overallotment units to the underwriters, of approximately $31.2 million, also as a reimbursement for a portion of the capital expenditures made by TD to purchase the contributed assets. At the closing of the Offering, TEP used the total proceeds, net of the underwriters’ discount, of approximately $295.9 million to repay approximately $295.9 million of the debt assumed from TD.

Revolving Credit Facility

On May 17, 2013, in connection with the closing of the Offering, TEP entered into a $500 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 17, 2018. On the closing date of the Offering, TEP borrowed $231.0 million under the credit facility, the proceeds of which were used to (i) repay the remaining approximately $104.1 million of debt

assumed from TD; (ii) pay a distribution to TD of $31.2 million, equal to the net proceeds from the exercise of the underwriter’s option to purchase additional Units (iii) pay $85.5 million to TD as reimbursement for a portion of the capital expenditures made by TD to purchase the contributed assets and (iv) pay origination fees related to the new revolving credit facility and certain other fees associated with the Offering, and fund working capital requirements of TEP. The remaining commitments under the credit facility are available for capital expenditures and permitted acquisitions, to provide for working capital requirements and for other general partnership purposes. The credit facility has an accordion feature that will allow TEP to increase the available revolving borrowings under the credit facility by up to an additional $100 million, subject to TEP’s receipt of increased or new commitments from lenders and satisfaction of certain other conditions. In addition, the credit facility includes a sublimit up to $40 million for swing line loans and a sublimit up to $50 million for letters of credit. As of September 30, 2013, our borrowings under the revolving credit facility were $226.0 million. In addition, letters of credit totaling $0.7 million were issued and outstanding under the credit facility at September 30, 2013.

The credit facility contains various covenants and restrictive provisions that, among other things, limits or restricts TEP’s ability (as well as the ability of TEP’s restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions, including distributions from available cash, if a default or event of default under the credit agreement then exists or would result therefrom, change the nature of TEP’s business, engage in certain mergers or make certain investments and acquisitions, enter into non arms-length transactions with affiliates and designate certain subsidiaries as “Unrestricted Subsidiaries,” and also requires maintenance of 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.

Borrowings under the credit facility bear interest, at TEP’s option, at either (a) a base rate, which is 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%, in each case, plus an applicable margin, or (b) a reserve adjusted Eurodollar rate, plus an applicable margin. Swing line loans bear interest at the base rate plus an applicable margin. For borrowings bearing interest based on the base rate, the applicable margin is initially 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is initially 2.00%. After September 30, 2013, the applicable margin will range from 1.00% to 2.00% for base rate borrowings and 2.00% to 3.00% for reserve adjusted Eurodollar rate borrowings, based upon TEP’s total leverage ratio. The unused portion of the credit facility is subject to a commitment fee, which is initially 0.375%, and after September 30, 2013, is either 0.375% or 0.500%, based on TEP’s total leverage ratio. As of September 30, 2013, the weighted average interest rate on outstanding borrowings was 2.21%.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of September 30, 2013, we had a working capital deficit of $26.6 million compared to a working capital deficit of $43.8 million at December 31, 2012, which represents a decrease in the working capital deficit of $17.2 million.

Our working capital requirements have been and we expect will continue to be primarily driven by changes in accounts receivable and accounts payable. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers and payments to suppliers, as well as the level of spending for capital expenditures and changes in the market prices of energy commodities that we buy and sell in the normal course of business. The overall decrease in the working capital deficit from December 31, 2012 to

September 30, 2013 was primarily attributable to (i) a decrease in accounts payable and accrued other current liabilities of $14.5 million, primarily driven by accruals at December 31, 2012 for interest associated with the debt allocated from TD, which was no longer accrued at September 30, 2013, as well as a decrease in the accruals related to capital projects that were completed during the second quarter of 2013; (ii) $4 million related to the current portion of the long-term debt allocated from TD at December 31, 2012, which was retired in the second quarter of 2013; and (iii) increases in cash, accounts receivable, net and inventory. These decreases were partially offset by changes in related party balances and imbalances to net payable positions.

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

Cash Flows

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


	TEP			TEP Pre-Predecessor
	Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	(in thousands)			(in thousands)
Net cash provided by (used in):
Operating activities	$	50,928		$	67,107
Investing activities	$	(37,992	)	$	(13,568	)
Financing activities	$	(12,316	)	$	(53,539	)

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012

Operating Activities. Cash flows provided by operating activities were $50.9 million and $67.1 million for the nine months ended September 30, 2013 and 2012, respectively. The overall decrease in net cash flows provided by operating activities of $16.2 million was primarily driven by the significant decrease in operating results, partially offset by cash inflows from changes in working capital balances driven by the settlement of related party receivables during the period.

Investing Activities. Cash flows used in investing activities were $38.0 million and $13.6 million for the nine months ended September 30, 2013 and 2012, respectively. Investing cash flows are primarily attributable to capital expenditures. Cash flows used in investing activities for the nine months ended September 30, 2013 consisted primarily of the capacity expansion and efficiency upgrade projects at TMID, and to a lesser extent, capital expenditures at TIGT. Cash flows used in investing activities for the nine months ended September 30, 2012 consisted of $6.8 million of maintenance capital expenditures and $5.8 million of expansion capital expenditures, partially offset by net cash paid for sale and purchase of gas in underground storage of $1.2 million in the nine months ended September 30, 2012. Effective November 13, 2012, TEP adopted an accounting policy in which working gas is accounted for as part of inventory. As a result, cash flows associated with changes in gas in underground storage are now presented as cash flows from operating activities.

Financing Activities. Cash flows used in financing activities of $12.3 million for the nine months ended September 30, 2013 consisted of net distributions to TD of $118.5 million for the period from January 1, 2013 to May 17, 2013 in addition to distributions paid to unitholders of $5.9 million and the proceeds net of expenses associated with the Offering and the associated debt transactions. Gross proceeds from the Offering totaled $313.9 million, and were partially offset by costs incurred in connection with the Offering of $23.4 million. In addition, cash flows provided by financing activities reflect a net outflow of $179.2 million related to the associated debt transactions, including the repayment of $400.0 million of debt assumed from TD, partially offset by net borrowings under the revolving credit facility of $226.0 million and payments for deferred financing costs

of $5.2 million. Cash flows used in financing activities of $53.5 million for the nine months ended September 30, 2012 consisted entirely of net distributions. Prior to November 13, 2012, cash flows used in financing activities consisted entirely of cash distributions paid to TEP Pre-Predecessor Parent, as TEP Pre-Predecessor participated in its parent’s centralized cash management system prior to that time. Between November 13, 2012 and May 17, 2013, TEP Predecessor participated in a similar centralized cash management system with TD. Under these cash management systems, all cash balances of the Predecessor Entities were swept on a daily basis and the balances were periodically settled and recorded as equity distributions. Therefore, the Predecessor Entities do not have cash balances at the end of any period and cash flows from financing activities is equal to the total of cash flows from operating activities and cash flows from investing activities in all periods presented. Beginning on May 17, 2013, TEP maintains the cash balances of TIGT and TMID. As a result, the practice of settling and distributing these balances as equity distributions to TD was discontinued on that date.

Distributions

We intend to pay quarterly distributions at or above the amount of the MQD, which is $0.2875 per unit. As of the date of this Quarterly Report, we have a total of 41,326,531 common, subordinated and general partner units outstanding, which equates to an annualized MQD distribution of approximately $11.9 million per quarter and $47.5 million per year. We do not have a legal obligation to pay distributions except as provided in our partnership agreement. Distributions of $0.1422 per unit were declared on July 18, 2013 for the second quarter of 2013 and were paid on August 13, 2013 to unitholders of record on July 31, 2013, which represented a prorated amount of TEP’s minimum quarterly distribution of $0.2875 per common unit, based upon the number of days between the closing of the Offering on May 17, 2013 to June 30, 2013. A distribution of $0.2975 per unit for the three months ended September 30, 2013 was declared on October 7, 2013 and will be paid on November 13, 2013 to unitholders of record on November 1, 2013.

Capital Requirements

Our business is capital-intensive, requiring significant investment to maintain and improve existing assets. We have budgeted approximately $17 million for capital expenditures for the remainder of 2013. Our budgeted expansion capital expenditures for the remainder of 2013 primarily relate to the ongoing capacity expansion and efficiency upgrade projects at TMID. In addition, we estimate that we will incur expansion capital expenditures related to the Pony Express Pipeline Conversion Project of approximately $46.9 million, for which we will receive reimbursement from TD.

Contractual Obligations

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The condensed consolidated financial statements of TEP and the condensed combined financial statements of the TEP Pre-Predecessor are prepared in conformity with GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. Our significant accounting policies are described in Note 2 to the audited combined financial statements included in the Prospectus. Our critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Prospectus. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities,

revenues and expenses and the related disclosure of contingent assets and liabilities. The critical accounting policies are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on our results of operations, equity or cash flows. We have reviewed and determined that those policies remain TEP’s critical accounting policies as of and for the three months ended September 30, 2013.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

The profitability of our processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. We do not currently hedge the commodity exposure in our processing contracts. Our Processing segment comprised approximately 30% of our Adjusted EBITDA for the nine months ended September 30, 2013.

We also have a limited amount of direct commodity price exposure related to electrical compression costs and lost and unaccounted for gas on the TIGT System. Historically, we have entered into derivative contracts with third parties for the purpose of hedging these commodity price exposures. As of September 30, 2013, we had natural gas swaps outstanding with a notional volume of approximately 0.2 Bcf, representing a portion of the natural gas that is expected to be sold by our Gas Transportation and Storage segment through the end of 2013. The fair value of these swaps was an asset of approximately $19,000 at September 30, 2013.

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 movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. We enter into derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, both the sensitivity analysis model and the change in the market value of our outstanding derivative contracts are offset largely by changes in the value of the underlying physical natural gas sales.

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

Interest Rate Risk

As described in “Capital Resources and Liquidity” above, at the closing of the Offering, we entered into a $500 million revolving credit facility. Borrowings under the credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin will initially be 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin will initially be 2.00%. After September 30, 2013, the applicable margin will range from 1.00% to 3.00%, based upon our total leverage ratio and whether we have elected the base rate or the reserve adjusted Eurodollar rate. We may or may not hedge the interest on portions of our borrowings under the credit

facility from time-to-time through interest rate swaps or caps in order to manage risks associated with floating interest rates. Additionally, we may choose longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time.

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, fee-based contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with the majority having investment grade credit ratings as of September 30, 2013.

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 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, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Assessment of Internal Control over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the recently enacted Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act. Our first Annual Report on Form 10-K will not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to newly public companies. Our management will be required to provide an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2014.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

See Note 15 – Legal and Environmental Matters to the consolidated financial statements included in Part 1 – Item 1.– Financial Statements of this Quarterly Report, which is incorporated here by reference.

Item 1A. Risk Factors

For information regarding our risk factors, see Item 1A.—Risk Factors to our Quarterly Report for the three months ended March 31, 2013.

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

Not applicable.

Item 6. Exhibits


Exhibit No.		Description
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 7, 2013	By:	/s/ Gary J. Brauchle
		Name:	Gary J. Brauchle
		Title:	Executive Vice President, Chief Financial Officer and Treasurer