Edgar Filing: Tallgrass Energy Partners, LP

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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 March 31, 2014

¨	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 Incorporation or Organization)

(Primary Standard Industrial Classification Code Number)

(IRS Employer

Identification Number)

6640 W. 143rd Street, Suite 200

Overland Park, Kansas 66223

(913) 928-6060

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

George E. Rider

6640 W. 143rd Street, Suite 200

Overland Park, Kansas 66223

(913) 928-6060

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

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 May 2, 2014, the Registrant had 24,685,140 Common Units, 16,200,000 Subordinated Units, and 834,391 General Partner Units outstanding.

TALLGRASS ENERGY PARTNERS, LP

TABLE OF CONTENTS


PART 1—FINANCIAL INFORMATION			1

Item 1. Financial Statements			1

TALLGRASS ENERGY PARTNERS, LP			1

CONDENSED CONSOLIDATED BALANCE SHEETS			1

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME			2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS			3

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL			4

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS			5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			20

Item 3. Quantitative and Qualitative Disclosures About Market Risk			30

Item 4. Controls and Procedures			32

PART II—OTHER INFORMATION			34

Item 1. Legal Proceedings			34

Item 1A. Risk Factors			34

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			34

Item 3. Defaults Upon Senior Securities			34

Item 4. Mine Safety Disclosures			34

Item 5. Other Information			34

Item 6. Exhibits			35

SIGNATURES			36

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.

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

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

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

dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

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

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

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.

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

MMBtu: One million British Thermal Units.

Mcf: One thousand cubic feet.

MMcf: One million cubic feet.

natural gas liquids or NGLs: Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or

cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).

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

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

(UNAUDITED)


	March 31, 2014		December 31, 2013
	(in thousands)
ASSETS
Current Assets:
Accounts receivable, net	$	25,663	$	27,615
Gas imbalances		2,743		2,598
Inventories		11,352		5,148
Prepayments and other current assets		4,264		16,986

Total Current Assets		44,022		52,347

Property, plant and equipment, net		593,301		594,911
Goodwill		304,474		304,474
Unconsolidated investment		3,031		1,255
Deferred financing costs		4,255		4,512
Deferred charges and other assets		9,994		10,299

Total Assets	$	959,077	$	967,798

LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities:
Accounts payable	$	43,021	$	54,621
Accounts payable to related parties		3,655		7,134
Gas imbalances		9,176		3,142
Derivative liabilities at fair value		535		184
Accrued taxes		5,172		4,427
Accrued other current liabilities		12,073		14,777

Total Current Liabilities		73,632		84,285
Long-term debt		135,000		135,000
Other long-term liabilities and deferred credits		4,510		4,572

Total Long-term Liabilities		139,510		139,572

Commitments and Contingencies (Note 12)

Partners’ Capital:
Common unitholders (24,300,000 units issued and outstanding at March 31, 2014 and December 31, 2013)		457,230		455,197
Subordinated unitholder (16,200,000 units issued and outstanding at March 31, 2014 and December 31, 2013)		274,570		274,666
General partner (826,531 units issued and outstanding at March 31, 2014 and December 31, 2013)		14,135		14,078

Total Partners’ Capital		745,935		743,941

Total Liabilities and Partners’ Capital	$	959,077	$	967,798

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(UNAUDITED)


	Three Months			Three Months
	Ended			Ended
	March 31, 2014			March 31, 2013
	(in thousands)
Revenues:
Natural gas liquids sales	$	48,907		$	33,401
Natural gas sales		2,196			301
Transportation services		27,051			24,337
Processing and other revenues		6,808			2,219

Total Revenues		84,962			60,258

Operating Costs and Expenses:
Cost of sales and transportation services		50,446			29,470
Operations and maintenance		7,286			6,535
Depreciation and amortization		6,514			7,546
General and administrative		6,201			4,634
Taxes, other than income taxes		1,456			1,777

Total Operating Costs and Expenses		71,903			49,962

Operating Income		13,059			10,296

Other (Expense) Income:
Interest (expense) income, net		(1,324	)		(5,564	)
Equity in earnings of unconsolidated investment		444			—
Other income, net		721			339

Total Other Expense		(159	)		(5,225	)

Net Income	$	12,900		$	5,071

Total comprehensive income	$	12,900		$	5,071

Allocation of income for the three months ended March 31, 2014:
General partner interest in net income	$	382
Common and subordinated unitholders’ interest in net income		12,518

Net Income	$	12,900

Basic net income per common and subordinated unit	$	0.31

Diluted net income per common and subordinated unit	$	0.30

Basic average number of common and subordinated units outstanding		40,500
Diluted average number of common and subordinated units outstanding		41,272

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Three Months			Three Months
	Ended			Ended
	March 31, 2014			March 31, 2013
	(in thousands)
Cash Flows from Operating Activities:
Net income	$	12,900		$	5,071
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		6,843			8,297
Noncash compensation expense		941			—
Noncash change in fair value of derivative financial instruments		351			919
Equity in earnings of unconsolidated investment		(444	)		—
Distributions from unconsolidated investment		444			—
Changes in components of working capital:
Accounts receivable and other		2,461			(565	)
Gas imbalances		628			307
Inventories		(942	)		(2,181	)
Accounts payable and accrued liabilities		(9,865	)		20,066
Other, net		6,290			107

Net Cash Provided by Operating Activities		19,607			32,021

Cash Flows from Investing Activities:
Capital expenditures		(5,947	)		(8,943	)
Net cash paid for purchase and sale of gas in underground storage		(31	)		—
Unconsolidated investment		(1,841	)		—
Distributions from unconsolidated investment in excess of cumulative earnings		64			—
Proceeds from disposal of property, plant and equipment (net of removal costs)		29			6

Net Cash Used in Investing Activities		(7,726	)		(8,937	)

Cash Flows from Financing Activities:
Distributions to Member, net		—			(23,084	)
Distributions to unitholders		(13,082	)		—
Reimbursement of stock compensation expense from TD		1,201			—

Net Cash Used in Financing Activities		(11,881	)		(23,084	)

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

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

Supplemental Disclosures:
Cash payments for interest	$	1,151		$	—
Schedule of Noncash Investing and Financing Activities:
Receivable for unreimbursed stock compensation from TD	$	437		$	—

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

TALLGRASS ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(UNAUDITED)


							General Partner			Total Partners’ Capital
	Limited Partners
	Common			Subordinated
Balance at January 1, 2014	$	455,197		$	274,666		$	14,078		$	743,941
Net Income		7,511			5,007			382			12,900
Distributions to unitholders		(7,654	)		(5,103	)		(325	)		(13,082	)
Noncash compensation expense		2,176			—			—			2,176

Balance at March 31, 2014	$	457,230		$	274,570		$	14,135		$	745,935

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

TALLGRASS ENERGY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.	Description of Business

Tallgrass Energy Partners, LP (“TEP” or the “Partnership”) is a Delaware limited partnership formed in February 2013.

On May 17, 2013, TEP closed its initial public offering (“IPO”). The 14,600,000 common units held by the public constitute approximately 36% of TEP’s aggregate outstanding common and subordinated units and approximately 35% of TEP’s aggregate outstanding common, subordinated and general partner units at March 31, 2014. TD held 9,700,000 common units and 16,200,000 subordinated units at March 31, 2014 which comprised approximately 64% of TEP’s aggregate outstanding common and subordinated units and approximately 63% of TEP’s aggregate outstanding common, subordinated and general partner units. In addition, as part of the contribution transaction, 826,531 general partner units, representing a 2% general partner interest in TEP at March 31, 2014, and all of the incentive distribution rights (“IDRs”) were issued to Tallgrass MLP GP, LLC (the “general partner”). In connection with the IPO, TEP entered into a revised partnership agreement on May 17, 2013. The amended and restated partnership agreement requires TEP to distribute its available cash on a quarterly basis, subject to certain terms and conditions, beginning with the quarter ending June 30, 2013. For additional information, see Note 8 – Partnership Equity and Distributions.

The term “Predecessor Entity” refers to Tallgrass Energy Partners Predecessor (“TEP Predecessor”), which is comprised of the businesses described below that were owned by TD, from November 13, 2012 through the completion of the IPO on May 17, 2013.

The businesses included in the Predecessor Entity consist of:

•

Tallgrass Interstate Gas Transmission, LLC (“TIGT”), which owns an interstate gas pipeline and storage system that is regulated by the FERC. TIGT currently has approximately 4,645 miles of varying diameter natural gas transmission lines in Colorado, Kansas, Missouri, Nebraska and Wyoming (the “TIGT System”).

•

Tallgrass Midstream, LLC (“TMID”), which owns and operates one treating and two processing plants in Wyoming.

2.	Summary of Significant Accounting Policies

Basis of Presentation

These unaudited condensed consolidated financial statements and related notes for the three months ended March 31, 2014 and 2013 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include disclosures required by GAAP for annual periods. The unaudited condensed consolidated financial statements for the three months ended March 31, 2014 and 2013 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair presentation of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.

TEP’s financial results for the three months ended March 31, 2014 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2014. These unaudited condensed

consolidated financial statements should be read in conjunction with TEP’s audited consolidated financial statements and notes thereto included in its Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Form 10-K”) filed with the Securities Exchange Commission (the “SEC”) on March 11, 2014.

The accompanying consolidated financial statements of TEP include historical cost-basis accounts of the assets of TEP Predecessor, contributed to TEP by TD in connection with the IPO for the periods prior to May 17, 2013, the closing date of TEP’s IPO, 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 consolidated financial statements include the accounts of TEP and its subsidiaries. Significant intra-entity items have been eliminated in the presentation. Net equity distributions of the Predecessor Entity included in the Consolidated Statements of Cash Flows represent transfers of cash as a result of TD’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.

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’s 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.

3.	Related Party Transactions

TEP has no employees. Beginning November 13, 2012, TD provided and charged TEP 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. TEP recorded these costs on the accrual basis in the period in which TD incurred them. Each of the wholly-owned companies comprising TEP had an agency arrangement with TD under which TD paid costs and expenses incurred by TEP, acted as an agent for TEP, and was reimbursed by TEP for such payments.

On May 17, 2013, in connection with the closing of TEP’s IPO, TEP and its subsidiaries entered into an Omnibus Agreement with TD and certain of its affiliates (the “Omnibus Agreement”). The Omnibus Agreement provides that, among other things, TEP will reimburse TD and its affiliates for all expenses they incur and payments they make on TEP’s behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by TD, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP.

For the calendar year 2014, TEP’s annual cost reimbursements to TD for costs discussed above, are expected to be $19.9 million, inclusive of costs associated with our acquisition of Trailblazer Pipeline Company, LLC (“Trailblazer”) in April 2014, as discussed in Note 14 – Subsequent Events. TEP also pays a quarterly reimbursement to TD for costs associated with being a public company. The quarterly public company reimbursement was $625,000 for the first quarter of 2014 and TEP currently expects it to remain the same for each subsequent quarter in 2014. However, 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 agreement discussed in Note 2 – Summary of Significant Accounting Policies, intercompany balances at the Predecessor Entity were periodically settled and treated as equity distributions prior to the completion of the IPO on May 17, 2013.

Totals of transactions with affiliated companies are as follows:


	Three Months		Three Months
	Ended		Ended
	March 31, 2014		March 31, 2013
	(in thousands)
Charges to TEP: ⁽¹⁾
Property, plant and equipment, net	$	5,316	$	4,709
Other deferred charges	$	582	$	1,038
Operation and maintenance	$	3,840	$	3,586
General and administrative ⁽²⁾	$	4,224	$	4,634

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

⁽²⁾	During the three months ended March 31, 2014 and 2013, TEP reimbursed TD for general and administrative expenses as discussed above, resulting in allocated amounts for general and administrative costs.

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


	March 31, 2014		December 31, 2013
	(in thousands)
Accounts receivable from affiliated companies:
Rockies Express Pipeline LLC	$	29	$	—

Total accounts receivable from affiliated companies	$	29	$	—

Payables to affiliated companies:
Accounts payable to Tallgrass Operations, LLC	$	3,655	$	7,106
Accounts payable to Rockies Express Pipeline LLC		—		28

Total payables to affiliated companies	$	3,655	$	7,134

Balances of gas imbalances with affiliated shippers are as follows:


	March 31, 2014		December 31, 2013
	(in thousands)
Affiliate gas balance receivables	$	—	$	7

Affiliate gas balance payables	$	1,633	$	116

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 Pipeline, LLC (“PXP”), is reimbursing TIGT for all costs TIGT incurs with respect to the Pony Express Abandonment, as defined in Note 11 – 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 (the “Replacement Gas Facilities”). The Replacement Gas Facilities are required as part of the Pony Express Abandonment in order for TIGT to continue service to existing customers after having sold approximately 430 miles of natural gas pipeline, and associated rights of way and certain other equipment, to PXP in 2013. For more information, see Note 5 – Property, Plant and Equipment and Note 11 – Regulatory Matters.

TIGT’s expenditures for the Replacement Gas Facilities are being captured in “Prepayments and other current assets” in the Condensed Consolidated Balance Sheets as they are incurred and interest is accrued until reimbursement takes place (which is usually monthly). At March 31, 2014, TEP had $4.0 million in “Prepayments and other current assets” related to this project due to $26.2 million of expenditures during the three months ended March 31, 2014, which were partially offset by reimbursements of $22.2 million that were cash settled by TD. At December 31, 2013, TEP had $17.0 million in “Prepayments and other current assets” related to this project that were cash settled by TD in the first quarter of 2014.

4.	Inventory

The components of inventory at March 31, 2014 and December 31, 2013 consisted of the following:


	March 31, 2014		December 31, 2013
	(in thousands)
Materials and supplies	$	1,730	$	1,736
Natural gas liquids		1,164		1,009
Gas in underground storage		8,458		2,403

Total inventory	$	11,352	$	5,148

5.	Property, Plant and Equipment

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


	March 31, 2014			December 31, 2013
	(in thousands)
Natural gas pipelines	$	348,481		$	339,430
Processing and treating assets		234,541			209,329
General and other		25,202			24,859
Construction work in progress		7,984			39,369
Accumulated depreciation and amortization		(22,907	)		(18,076	)

Total property, plant and equipment, net	$	593,301		$	594,911

6.	Risk Management

TEP occasionally enters into derivative contracts with third parties for the purpose of hedging exposures that accompany its normal business activities. TEP’s normal business activities expose it to risks associated with changes in the market price of commodities, including, among others, natural gas. 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. TEP has elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.

Fair Value of Derivative Contracts

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


	Balance Sheet Location	March 31, 2014		December 31, 2013
		(in thousands)
Energy commodity derivative contracts	Current liabilities	$	535	$	184

As of March 31, 2014, the fair value shown for commodity contracts was comprised of derivative volumes totaling 0.9 Bcf of fixed-price swaps. TEP did not recognize any derivative contracts in asset positions as of March 31, 2014 or December 31, 2013.

Effect of Derivative Contracts on the Income Statement

The following table summarizes the impact of derivative contracts included in the accompanying Condensed Consolidated Statements of Income and Comprehensive Income for the three months ended March 31, 2014 and 2013:

Amount of loss recognized in

income on derivatives

Location of
loss recognized
in income on
derivatives

Three Months
Ended
March 31, 2014

Three Months
Ended
March 31, 2013

(in thousands)

Derivatives not designated as hedging contracts:

Energy commodity derivative contracts

Natural gas sales

(351

)

(919

)

Credit Risk

TEP has counterparty credit risk as a result of its 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 currently anticipate a material adverse effect on TEP’s 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. As of March 31, 2014, the fair value of TEP’s derivative contracts was a liability, resulting in no credit exposure from TEP’s counterparty as of that date.

In addition, 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. Additionally, entity valuation adjustments are necessary to reflect the effect of TEP’s own credit quality on the fair value of TEP’s net liability position with each counterparty. The

methodology to determine this adjustment is consistent with how TEP evaluates counterparty credit risk, taking into account current credit spreads for its comparative industry sector, as well as any change in such spreads since the last measurement date. As of March 31, 2014 and December 31, 2013, TEP did not have any outstanding letters of credit or cash in margin accounts in support of its hedging of commodity price risks associated with the sale of natural gas nor did TEP have margin deposits with counterparties associated with energy commodity contract positions.

Fair Value

Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter (“OTC”). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. 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, commodity and interest rate curves and measures of volatility. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. 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; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to 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 in a liability position as of March 31, 2014 and December 31, 2013 based on the fair value hierarchy established by the Codification:


			Liability fair value measurements using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
TEP as of March 31, 2014
Energy commodity derivative contracts	$	535	$	—	$	535	$	—

TEP as of December 31, 2013
Energy commodity derivative contracts	$	184	$	—	$	184	$	—

TEP did not recognize any derivative contracts in asset positions as of March 31, 2014 or December 31, 2013.

7.	Long-term Debt

Revolving Credit Facility

TEP has 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. As of March 31, 2014 and December 31, 2013, TEP had outstanding borrowings of $135.0 million, had issued letters of credit totaling $0.7 million and had available borrowing capacity under the revolving credit facility of $364.3 million.

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.” In addition, TEP is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of March 31, 2014, TEP is in compliance with the covenants required under the revolving credit facility.

The unused portion of the credit facility is subject to a commitment fee, which was initially 0.375%, and after September 30, 2013, is either 0.375% or 0.500%, based on TEP’s total leverage ratio. As of March 31, 2014, the weighted average interest rate on outstanding borrowings was 2.15%.

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. 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 in connection with the IPO. As such, $400 million of the term loan, along with the corresponding discount and deferred financing costs, was allocated to TEP as of 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 IPO on May 17, 2013, TEP legally assumed the previously allocated $400 million portion of the TD term loan and used a portion of the IPO proceeds, along with borrowings under TEP’s $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 year ended December 31, 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.

Fair Value

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 March 31, 2014 and December 31, 2013, but for which fair value is disclosed:


	Fair Value
	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount
	(in thousands)
March 31, 2014	$	—	$	135,000	$	—	$	135,000	$	135,000
December 31, 2013	$	—	$	135,000	$	—	$	135,000	$	135,000

The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of March 31, 2014 and December 31, 2013, the fair value approximates the carrying amount for the borrowings under the revolving credit facility using a discounted cash flow analysis. TEP is not aware of any factors that would significantly affect the estimated fair value subsequent to March 31, 2014.

8.	Partnership Equity and Distributions

TEP’s partnership agreement requires TEP to distribute its available cash, as defined below, to unitholders of record on the applicable record date within 45 days after the end of each quarter, beginning with the quarter ended June 30, 2013. 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, holders of the subordinated units are not entitled to receive a distribution of available cash until each holder of common units has received the MQD, and if the MQD is not paid for any quarter, the cumulative amount of any arrearages in the payment of the MQD from prior quarters.

The following table shows the distributions for the year ended 2013 and three months ended March 31, 2014:


		Distributions
		LimitedPartners Common and Subordinated		General Partner						Distributions per Limited Partner Unit
Three Months Ended	Date Paid	LimitedPartners Common and Subordinated		Incentive		2%		Total		Distributions per Limited Partner Unit
		(in thousands, except per unit amounts)
March 31, 2014	May 14, 2014⁽²⁾	$	13,288	$	126	$	274	$	13,688	$	0.3250
December 31, 2013	February 12, 2014		12,757		63		262		13,082		0.3150
September 30, 2013	November 13, 2013		12,049		—		245		12,294		0.2975
June 30, 2013	August 13, 2013		5,759		—		118		5,877		0.1422	⁽¹⁾

⁽¹⁾	The distribution declared on July 18, 2013 for the second quarter of 2013 represented a prorated amount of the MQD of $0.2875 per common unit, based upon the number of days between the closing of the IPO on May 17, 2013 to June 30, 2013.

⁽²⁾	The distribution declared on April 1, 2014 for the first quarter of 2014 is expected to be paid May 14, 2014 subsequent to the date of this Quarterly Report to 40,885,140 common unitholders of record at the close of business on April 30, 2014.

Subordinated Units

All subordinated units are currently held by TD. The principal difference between the 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 (inclusive of any cumulative arrearages of previously unpaid MQD from previous quarters). Furthermore, subordinated unitholders are not entitled to receive arrearages from previous quarterly 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.

Incentive Distribution Rights

The general partner owns a 2% general partner interest in TEP which, as of March 31, 2014, was represented by 826,531 general partner units. As discussed in Note 14 – Subsequent Events, in April 2014, in connection with TEP’s acquisition of Trailblazer, the general partner contributed capital in exchange for the

issuance of an additional 7,860 general partner units in order to continue to maintain its 2% general partner interest. The general partner also owns all of the IDRs. IDRs represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the MQD and the target distribution levels have been achieved. The general partner may transfer these rights separately from its general partner interest, subject to restrictions in TEP’s 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 the payment of the MQD to common unitholders;

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

•

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

•

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

•

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

•

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

Definition of Available Cash

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

•

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

•

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

•

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

•

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

•

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

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 3 – Related Party Transactions, was recognized as equity distributions during that time period. Net distributions from TEP to TD for the three months ended March 31, 2013 were approximately $23.1 million. Excluding the cash distributions paid to TD as a common and subordinated unitholder, as discussed above, there were no net distributions from TEP to TD for the quarter ended March 31, 2014.

9.	Net Income per Limited Partner Unit

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

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

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

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

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

As the IPO was completed on May 17, 2013, no income from the period from January 1, 2013 to May 16, 2013 is allocated to the limited partner units that were issued on May 17, 2013 and all income for such period was allocated to the general partner. Net income per limited partner unit is only calculated for the three months ended March 31, 2014 as no units were outstanding during the same period in 2013.

The following table illustrates the Partnership’s calculation of net income per common and subordinated unit for the three months ended March 31, 2014:


	Three Months Ended March 31, 2014
	(in thousands, except per unit amounts)
Net Income	$	12,900
General partner interest in net income		382

Net income available to common and subordinated unitholders	$	12,518

Basic net income per common and subordinated unit	$	0.31

Diluted net income per common and subordinated unit	$	0.30

Basic average number of common and subordinated units outstanding		40,500
Equity Participation Unit equivalent units		772

Diluted average number of common and subordinated units outstanding		41,272

10.

Equity-Based Compensation

Long-term Incentive Plan

Effective May 13, 2013, the 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, including TD. Vesting and forfeiture requirements are at the discretion of the board of directors of the general partner at the time of the grant.

The LTIP limits the number of units that may be delivered pursuant to vested awards to 10,000,000 common units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan is administered by the board of directors of TEP’s general partner or a committee thereof, which is referred to as the plan administrator.

The plan administrator may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the LTIP or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The LTIP will expire on the earliest of (i) the date common units are no longer available under the plan for grants, (ii) termination of the plan by the plan administrator or (iii) May 13, 2023.

Equity Participation Units

On June 26, 2013, TEP’s general partner approved the grant of up to 1.5 million equity participation units (“EPUs”) for issuance to employees and 177,500 EPUs to Section 16 officers under the LTIP. Effective the same date, an aggregate of 1.49 million EPUs were granted to employees and Section 16 officers of the general partner and its affiliates. Vesting of the EPUs granted to employees is contingent upon TD’s Pony Express Pipeline, which upon completion will consist of an approximately 690-mile oil pipeline connecting the Bakken Shale to Cushing, Oklahoma, being placed into service (the “Pony Express Project”) and will occur in two parts, with one-third vesting on the later of the Pony Express Project in-service date or May 13, 2015, and the remaining two-thirds vesting on the later of the Pony Express Project in-service date or May 13, 2017. If the Pony Express 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 granted are non-participating with respect to distributions, 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 distributions during the vesting period. Total equity-based compensation cost related to the EPU grants of approximately $2.2 million was recognized for the quarter ended March 31, 2014. Of the total compensation cost, $0.9 million was recognized as compensation expense at TEP for the quarter ended March 31, 2014 and the remainder was allocated to TD. As of March 31, 2014, $17.1 million of total compensation cost related to non-vested EPUs is expected to be recognized over a weighted average period of 2.5 years, a portion of which will be charged to TD.

The following table summarizes the changes in the EPUs outstanding for the three months ended March 31, 2014:


	Three Months Ended March 31, 2014
	Shares			Weighted Average Grant Date Fair Value
Beginning of period	$	1,474,250		$	17.54
Granted		31,500			23.68
Forfeited		(19,000	)		(17.49	)

End of period	$	1,486,750		$	17.67

11.

Regulatory Matters

TIGT

Pony Express Abandonment – FERC Docket CP12-495

On August 6, 2012, TIGT filed an application to: (1) abandon for FERC purposes the Pony Express Assets, and the natural gas service therefrom, by transferring those assets to PXP, which will convert the Pony Express Assets into crude oil pipeline facilities; and (2) construct and operate the Replacement Gas Facilities in order to continue service to existing natural gas firm transportation customers following the proposed conversion. This project is referred to as the “Pony Express Abandonment.” The FERC abandonment does not constitute an abandonment for accounting purposes. Pursuant to the terms of the Purchase and Sale Agreement filed with the FERC and cited by the FERC in approving the Pony Express Abandonment, PXP is required to reimburse TIGT for the net book value of the Pony Express Assets plus other TIGT incurred costs required to construct the Replacement Gas Facilities and to arrange substitute gas transportation services to certain TIGT shippers.

The Pony Express Abandonment and completion of the Pony Express Project by PXP 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. By a FERC order issued September 12, 2013, TIGT was granted authorization to abandon the Pony Express Assets and construct the Replacement Gas Facilities. On October 7, 2013 TIGT commenced the mobilization of personnel and equipment for the construction of the Replacement Gas Facilities necessary to complete the Pony Express Abandonment to continue service to existing TIGT customers. In December 2013, TIGT removed the Pony Express Assets from gas service and sold those assets to PXP. Additional phases of the Pony Express Abandonment are expected to be completed during the third quarter of 2014. TIGT’s estimated commencement date to start commercial service of the Replacement Gas Facilities is projected to be in the second quarter of 2014.

12.

Legal and Environmental Matters

Legal

In addition to 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 has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and, accordingly, has aggregate reserves for all claims of approximately $0.6 million and $0.3 million as of March 31, 2014 and December 31, 2013, respectively.

TIGT

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. Both failures resulted in the release of natural gas. Both lines were promptly brought back into service and neither failure caused any known injuries, fatalities, fires or evacuations. The costs to repair or replace the damaged section in Kimball County, Nebraska were not material. In February 2014, TEP communicated to PHMSA that TEP’s investigation of the pipeline involved in the Kimball County failure is complete and TEP intends to restore pressure to full maximum allowable operating pressure. TEP is currently scheduled to start hydrostatic testing the pipeline related to the Goshen County failure in the third quarter of 2014 as required by the Corrective Action Order received from PHMSA. TEP expects the cost of remaining remediation activities related to the Goshen County failure to approximate $0.5 million.

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 its 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 has environmental accruals of $4.9 million and $5.0 million at March 31, 2014 and December 31, 2013, respectively.

TMID

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.

13.

Reporting Segments

TEP’s 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 FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers.

Processing

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

Corporate and Other

Corporate and Other includes corporate overhead costs incurred subsequent to the IPO on May 17, 2013 that are not directly associated with the operations of TEP’s reportable segments, such as interest and fees associated with TEP’s revolving credit facility, public company costs reimbursed to TD, and equity-based compensation expense.

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

Beginning in the second quarter of 2013, TEP considers Adjusted EBITDA as its primary segment performance measure as TEP believes 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 excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset disposals, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments.

The following tables set forth TEP’s segment information for the periods indicated:


	Three Months Ended March 31, 2014						Three Months Ended March 31, 2013
	Total Revenue		Inter- Segment		External Revenue		Total Revenue		Inter- Segment			External Revenue
			(in thousands)						(in thousands)
Gas transportation and storage	$	28,559	$	—	$	28,559	$	23,597	$	(171	)	$	23,426
Processing		56,403		—		56,403		36,832		—			36,832
Corporate and other		—		—		—		—		—			—

Total revenue	$	84,962	$	—	$	84,962	$	60,429	$	(171	)	$	60,258


	Three Months Ended March 31, 2014								Three Months Ended March 31, 2013
	Total					External			Total					External
	Adjusted			Inter-		Adjusted			Adjusted		Inter-			Adjusted
	EBITDA			Segment		EBITDA			EBITDA		Segment			EBITDA
				(in thousands)							(in thousands)
Gas transportation and storage	$	13,123		$	—	$	13,123		$	12,266	$	(171	)	$	12,095
Processing		9,596			—		9,596			6,834		171			7,005
Corporate and other		(625	)		—		(625	)		—		—			—
Reconciliation to Net Income:
Interest expense (income), net							1,324								5,564
Depreciation and amortization expense							6,514								7,546
Non-cash loss (gain) related to derivative instruments							351								919
Non-cash compensation expense							941								—
Distributions from unconsolidated investment							508								—
Equity in earnings of unconsolidated investment							(444	)							—

Net Income						$	12,900							$	5,071


	Total Assets
	March 31, 2014		December 31, 2013
	(in thousands)
Gas transportation and storage	$	627,894	$	636,686
Processing		326,886		326,599
Corporate and other		4,297		4,513

Total assets	$	959,077	$	967,798

14.

Subsequent Events

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

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 (“TIGT”) and Tallgrass Midstream, LLC (“TMID”), 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 the Predecessor as being “our” financial results during historic periods, although our Predecessor was owned 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,” “TEP” 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. Additionally, the following discussion should be read in conjunction with the audited financial statements and notes thereto, the related “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the discussion of “Risk Factors” and the discussion of TEP’s “Business” in our Annual Report on Form 10-K for the year ended December 31, 2013 (our “2013 Form 10-K”).

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 Tallgrass Development’s infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report and our 2013 Form 10-K. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

•

changes in general economic conditions;

•

competitive conditions in our industry;

•

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

•

the demand for natural gas processing, storage and transportation services;

•

our ability to successfully implement our business plan;

•

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

•

the price and availability of debt and equity financing;

•

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

•

competition from the same and alternative energy sources;

•

energy efficiency and technology trends;

•

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

•

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

•

interest rates;

•

labor relations;

•

large customer defaults;

•

changes in tax status;

•

the effects of existing and future laws and governmental regulations;

•

the effects of future litigation; and

•

certain factors discussed elsewhere in this Quarterly Report.

Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.

Overview

We are a growth-oriented publicly traded Delaware limited partnership that owns, operates, acquires and develops midstream energy assets in North America. We provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through our TIGT System and the Trailblazer Pipeline, acquired on April 1, 2014, and provide processing services for customers in Wyoming through our Casper and Douglas natural gas processing and West Frenchie Draw natural gas treating facilities, which we refer to as the Midstream Facilities.

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:

•

Gas Transportation and Storage—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and

•

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

Recent Developments

On April 1, 2014, we closed the acquisition of Trailblazer from a wholly owned subsidiary of TD for total consideration valued at approximately $164 million, consisting of $150 million in cash and the issuance of

385,140 common units (valued at approximately $14 million based on the March 31, 2014 closing price of our common units). On that same date, the general partner contributed additional capital in the amount of approximately $263,000 in exchange for the issuance of 7,860 general partner units in order to maintain its 2% general partner interest. The acquisition of Trailblazer represents a change in reporting entity and a transaction between entities under common control.

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

Adjusted EBITDA and Distributable Cash Flow

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

•

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

•

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

•

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

•

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

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

Non-GAAP Financial Measures

We define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation

expense, impairment losses, gains or losses on asset disposals, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments. We did not quantify distributable cash flow on a historical basis, however subsequent to the closing of the IPO 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.

The following table presents a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities and a reconciliation of distributable cash flow to net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated:


	Three Months Ended March 31, 2014			Three Months Ended March 31, 2013
	(in thousands)			(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
Net income	$	12,900		$	5,071
Add:
Interest expense (income), net		1,324			5,564
Depreciation and amortization expense		6,514			7,546
Non-cash loss related to derivative instruments		351			919
Non-cash compensation expense		941			—
Distributions from unconsolidated investment		508			—
Less:
Equity in earnings of unconsolidated investment		(444	)		—

Adjusted EBITDA	$	22,094		$	19,100

Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	19,607		$	32,021
Add:
Interest expense (income), net		1,324			5,564
Other, including changes in operating working capital		1,163			(18,485	)

Adjusted EBITDA	$	22,094		$	19,100

Less:
Maintenance capital expenditures		(839	)
Cash interest cost		(1,173	)

Distributable Cash Flow	$	20,082

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


	Three Months Ended March 31, 2014		Three Months Ended March 31, 2013
	(in thousands)		(in thousands)
Reconciliation of Adjusted EBITDA to Operating Income in the Gas Transportation and Storage Segment ⁽¹⁾
Operating income	$	7,484	$	5,081
Add:
Depreciation and amortization expense		4,567		5,927
Non-cash loss related to derivative instruments		351		919
Other income		721		339

Segment Adjusted EBITDA	$	13,123	$	12,266

Reconciliation of Adjusted EBITDA to Operating Income in the Processing Segment⁽¹⁾
Operating income	$	7,141	$	5,215
Add:
Depreciation and amortization expense		1,947		1,619
Distributions from unconsolidated investment		508		—

Segment Adjusted EBITDA	$	9,596	$	6,834

⁽¹⁾

Segment results as presented represent total operating income 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 13 – Reporting Segments to the accompanying consolidated financial statements.

Results of Operations

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


	Three Months Ended March 31, 2014			Three Months Ended March 31, 2013
	(in thousands, except operating data)
Statements of Operations Data
Revenues:
Natural gas liquids sales	$	48,907		$	33,401
Natural gas sales		2,196			301
Transportation services		27,051			24,337
Processing and other revenues		6,808			2,219

Total revenues		84,962			60,258

Operating costs and expenses:
Cost of sales and transportation services		50,446			29,470
Operations and maintenance		7,286			6,535
Depreciation and amortization		6,514			7,546
General and administrative		6,201			4,634
Taxes, other than income taxes		1,456			1,777

Total operating costs and expenses		71,903			49,962

Operating income		13,059			10,296
Interest income (expense), net		(1,324	)		(5,564	)
Equity in earnings of unconsolidated investment		444			—
Other income (expense), net		721			339

Net Income	$	12,900		$	5,071

Other Financial Data ⁽¹⁾
Adjusted EBITDA	$	22,094		$	19,100
Operating Data
Operating Data (Mmcf/d):
Transportation firm contracted capacity		636			667
Natural gas processing inlet volumes		151			127

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


	Three Months Ended March 31, 2014		Three Months Ended March 31, 2013
	(in thousands)
Segment Financial Data - Gas Transportation and Storage⁽¹⁾
Revenues:
Natural gas sales	$	1,504	$	(919	)
Transportation services		27,051		24,508
Processing and other revenues		4		8

Total revenues		28,559		23,597

Operating costs and expenses:
Cost of sales and transportation services		6,067		2,197
Operations and maintenance		5,322		4,983
Depreciation and amortization		4,567		5,927
General and administrative		3,744		3,743
Taxes, other than income taxes		1,375		1,666

Total operating costs and expenses		21,075		18,516

Operating income	$	7,484	$	5,081

Segment Adjusted EBITDA	$	13,123	$	12,266
Segment Financial Data - Processing⁽¹⁾
Revenues:
Natural gas liquids sales	$	48,907	$	33,401
Natural gas sales		692		1,220
Processing and other revenues		6,804		2,211

Total revenues		56,403		36,832

Operating costs and expenses:
Cost of sales and transportation services		44,379		27,444
Operations and maintenance		1,964		1,552
Depreciation and amortization		1,947		1,619
General and administrative		891		891
Taxes, other than income taxes		81		111

Total operating costs and expenses		49,262		31,617

Operating income	$	7,141	$	5,215

Segment Adjusted EBITDA	$	9,596	$	6,834

(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 13 – Reporting Segments to the accompanying consolidated financial statements.

Three Months Ended March 31, 2014 Compared to the Three Months Ended March 31, 2013

Revenues. Total revenues were $85.0 million for the three months ended March 31, 2014, compared to $60.3 million for the three months ended March 31, 2013, which represents a 41% increase in total revenues. The increase in revenues in the Gas Transportation and Storage segment and the Processing segment was 21% and 53%, respectively.

In the Gas Transportation and Storage segment an increase of $2.4 million in natural gas sales revenue was primarily attributable to increased gas sales and higher prices in the first quarter of 2014. The $0.9 million loss in natural gas sales during the three months ended March 31, 2013 represents a noncash mark-to-market loss on

derivatives that were used to hedge future sales of natural gas held in our storage facility. The $2.5 million, or 10%, increase in transportation services revenue is primarily related to increased prices in the three months ended March 31, 2014 as compared to the three months ended March 31, 2013.

In the Processing segment, natural gas liquids sales represent 87% and 91% of total segment revenue during the three months ended March 31, 2014 and 2013, respectively. The $15.5 million, or 46%, increase in natural gas liquids sales for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 is primarily attributable to higher volumes processed and a 20% increase in average NGL prices during the three months ended March 31, 2014 partially offset by the conversion of percent of proceeds contracts to fee-based contracts in February 2014, as discussed in Item 3.—Quantitative and Qualitative Disclosures About Market Risk. The $4.6 million increase in processing and other revenues was primarily due to the conversion of percent of proceeds contracts to fee-based contracts in February 2014 and increased volumes processed.

Operating costs and expenses. Operating costs and expenses were $71.9 million for the three months ended March 31, 2014 compared to $50.0 million for the three months ended March 31, 2013, which represents a 44% increase.

Cost of sales and transportation services increased by $21.0 million, or 71%, in the three months ended March 31, 2014 when compared to the same period in the prior year. In the Transportation and Storage segment, there was an overall increase in costs of sales and transportation services of $3.9 million caused primarily by higher compression costs and increased gas prices in the first quarter of 2014 as well as $1.6 million related to gas purchases for routine operational purposes. In the Processing segment, costs of sales and transportation services increased by $16.9 million, or 62%, in the three months ended March 31, 2014 when compared to the prior year period due to an increase of approximately $15.3 million in NGL producer settlements as a result of increased volumes processed and an increase in average NGL prices.

Operations and maintenance costs increased $0.8 million, or 11%, in the three months ended March 31, 2014 when compared to the same period in the prior year, primarily driven by an increase of approximately $0.4 million in the Processing segment related to increased operating costs associated with the expanded capacity at the Douglas plant.

Depreciation and amortization was $6.5 million for the three months ended March 31, 2014 compared to $7.5 million for the three months ended March 31, 2013 primarily due to the reduction in property, plant and equipment resulting from the sale of the Pony Express Assets to TD in December 2013 partially offset by the additional depreciation on the completed expansion projects.

General and administrative costs for the three months ended March 31, 2014 increased $1.6 million, or 34%, from the comparable period in 2013. This increase is due to public company costs and stock compensation expense recognized in the first quarter of 2014 which were not applicable in the first quarter of 2013.

Taxes, other than income taxes, were $1.5 million for the three months ended March 31, 2014 compared to $1.8 million for the three months ended March 31, 2013. The decrease was primarily due to lower property taxes in the Gas Transportation and Storage segment as a result of the abandonment of the PXP assets.

Interest (expense) income. Interest expense of $1.3 million for the three months ended March 31, 2014 was primarily composed of interest and fees of $1.4 million associated with TEP’s revolving credit facility. Interest expense of $5.6 million for the three months ended March 31, 2013 primarily represents the interest expense related to the $400 million term loan allocated from TD, which was legally assumed by TEP and repaid upon closing of the IPO on May 17, 2013.

Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.4 million for the three months ended March 31, 2014 was related to our investment in Grasslands Water Services I, LLC (“GWSI”).

Other income (expense), net. Other income for the three months ended March 31, 2014 was $0.7 million compared to $0.3 million for the three months ended March 31, 2013. Other income for the three months ended March 31, 2014 primarily relates to rental income and payments received from certain customers for reimbursement of the capital costs we incurred to connect these customers to our system which are decreasing over time as the balances due to us are being repaid.

Liquidity and Capital Resources Overview

Our primary source of liquidity for the three months ended March 31, 2014 was cash generated from operations. We expect our sources of liquidity in the future to include:

•

cash generated from our operations;

•

borrowing capacity available under our revolving credit facility; and

•

future issuances of additional partnership units and debt securities.

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

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


	March 31, 2014
	(in thousands)
Cash on hand	$	—
Total capacity under the revolving credit facility		500,000
Less: Outstanding borrowings under the revolving credit facility		(135,000	)
Less: Letters of credit issued under the revolving credit facility		(654	)

Available capacity under the revolving credit facility		364,346

Total liquidity	$	364,346

Revolving Credit Facility

We have 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. As of March 31, 2014 and December 31, 2013, TEP had outstanding borrowings of $135.0 million, had issued letters of credit totaling $0.7 million and had available borrowing capacity under the revolving credit facility of $364.3 million.

The credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict our ability (as well as the ability of our restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions, including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from taking such action, change the nature of our business, engage in certain mergers or make certain investments and acquisitions, enter into non arms-length transactions with affiliates and designate certain subsidiaries as “Unrestricted Subsidiaries.” Currently, no subsidiaries have been designated as “Unrestricted Subsidiaries.” The credit facility requires us to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00.

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 our total leverage ratio. As of March 31, 2014, the weighted average interest rate on outstanding borrowings was 2.15%.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of March 31, 2014, we had a working capital deficit of $29.6 million compared to a working capital deficit of $31.9 million at December 31, 2013 which represents a decrease in the working capital deficit of $2.3 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, 2013 to March 31, 2014 was primarily attributable to (i) a decrease of $12.7 million of other current assets related to reimbursements from TD for costs incurred by TIGT to construct the Replacement Gas Facilities in connection with the Pony Express Abandonment; (ii) a decrease in trade receivables of $2.0 million; (iii) a net increase in gas imbalance payables of $5.9 million (iv) partially offset by a decrease in net related party payable balances of $3.5 million; (v) an overall decrease in accounts payable and accrued liabilities of $13.6 million, primarily driven by a decrease in accruals for capital expenditures; and (vi) increased inventory balances of $6.2 million.

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:


	Three Months			Three Months
	Ended			Ended
	March 31, 2014			March 31, 2013
	(in thousands)
Net cash provided by (used in):
Operating activities	$	19,607		$	32,021
Investing activities	$	(7,726	)	$	(8,937	)
Financing activities	$	(11,881	)	$	(23,084	)

Operating Activities. Cash flows provided by operating activities were $19.6 million and $32.0 million for the three months ended March 31, 2014 and 2013, respectively. The overall decrease in net cash flows provided by operating activities of $12.4 million was primarily driven by the significant changes in working capital balances due to an increase in cash outflows related to accounts payable and accrued liabilities resulting from timing differences and an increase in cash outflows from related party balances partially offset by an increase in operating results of $7.8 million and cash inflows related to the Replacement Gas Facilities.

Investing Activities. Cash flows used in investing activities were $7.7 million and $8.9 million for the three months ended March 31, 2014 and 2013, respectively. Investing cash flows are primarily attributable to capital expenditures. During the three months ended March 31, 2014, net cash used in investing activities was driven by $5.9 million in capital expenditures primarily related to the Douglas expansion at TMID and the West End expansion project at TIGT and $1.8 million in cash contributions made to GWSI. In the three months ended March 31, 2013, net cash used in investing activities was driven by $8.9 million in expansion capital expenditures.

Financing Activities. Cash flows used in financing activities were $11.9 million and $23.1 million for the three months ended March 31, 2014 and 2013, respectively. Financing cash flows for the three months ended March 31, 2014 primarily consisted of distributions to unitholders.

Between November 13, 2012 and May 17, 2013, TEP Predecessor participated in a centralized cash management system with TD, and upon the completion of our IPO on May 17, 2013, TIGT and TMID entered into one with TEP. Under the cash management system, all cash balances of the Predecessor Entity were swept on a daily basis and the balances were periodically settled and recorded as equity distributions. Therefore, the Predecessor Entity did not have cash balances at the end of any period and cash flows from financing activities is equal to the total of cash flows from operating activities and cash flows from investing activities in all periods presented.

Distributions

We intend to pay quarterly distributions at or above the amount of the MQD, which is $0.2875 per unit. As of May 2, 2014, we had a total of 41,719,531 common, subordinated and general partner units outstanding, which equates to an aggregate MQD of approximately $12.0 million per quarter and $48.0 million per year. We do not have a legal obligation to pay distributions except as provided in our partnership agreement. A distribution of $0.3250 per unit for the three months ended March 31, 2014 was declared on April 1, 2014 and will be paid on May 14, 2014 to unitholders of record on April 30, 2014. No distribution was made for the three months ended March 31, 2013.

Capital Requirements

Our business is capital-intensive, requiring significant investment to maintain and improve existing assets. We have budgeted approximately $16 million for capital expenditures for TIGT and TMID for the remainder of 2014 with approximately $4 million being related to the Gas Replacement Facilities and other costs associated with the Pony Express Abandonment, for which we will receive reimbursement from TD. The remaining approximately $12 million is related to maintenance and expansion capital expenditures, with $9 million to $12 million currently being estimated for maintenance capital expenditures.

Contractual Obligations

There have been no material changes in our contractual obligations as reported in our 2013 Form 10-K.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our 2013 Form 10-K for the year ended December 31, 2013 and have not changed.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

The profitability of our processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. As of March 31, 2014 approximately 87% of our reserved capacity was subject to fee-based contracts, with the remaining 13% subject to percent of proceeds or keep whole contracts, a notable recent shift toward fee-based contracts as compared to approximately 66% fee-based contracts and approximately 34% of percent of proceeds or keep whole contracts as of December 31, 2013.

We do not currently hedge the commodity exposure in our processing contracts and we do not expect to in the foreseeable future. Our Processing segment comprised approximately 43% of our Adjusted EBITDA for the three months ended March 31, 2014.

We also have a limited amount of direct commodity price exposure related to natural gas collected related to electrical compression costs and lost and unaccounted for gas on the TIGT System. Historically, we have entered into derivative contracts with third parties for a substantial majority of the gas we expect to collect during the current year for the purpose of hedging our commodity price exposures. We expect to continue these hedging activities for the foreseeable future. As of March 31, 2014, we had natural gas swaps outstanding with a notional volume of approximately 0.9 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 2014. The fair value of these swaps was a liability of approximately $0.5 million at March 31, 2014.

We measure the risk of price changes in our natural gas swaps utilizing a sensitivity analysis model. The sensitivity analysis measures the potential income or loss (i.e., the change in fair value of the derivative instruments) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. We enter into derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, both the sensitivity analysis model and the change in the market value of our outstanding derivative contracts are offset largely by changes in the value of the underlying physical natural gas sales. The aggregate effect of a hypothetical 10% increase in the natural gas price forward curve would be a decrease of approximately $0.4 million in the net fair value of our derivative instruments for the three months ended March 31, 2014. For the purpose of determining the change in fair value associated with the hypothetical natural gas price increase scenario, we have assumed a parallel shift in the forward curve through the end of 2014.

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.

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

Interest Rate Risk

As described in “Liquidity and Capital Resources Overview” above, at the closing of the IPO, 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 was initially 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar

rate, the applicable margin was initially 2.00%. After September 30, 2013, the applicable margin ranges 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 do not currently hedge the interest rate risk on our borrowings under the credit facility. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the debt by $0.1 million based on the debt obligations as of March 31, 2014.

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 March 31, 2014.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

During the first quarter of 2014, TEP completed the conversion to a new contract and volume management system as well as the conversion to a new measurement system, both being used by TIGT. Both systems were utilized to produce financial information contained in this Quarterly Report. There have not been any other changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2014 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. Accordingly, our first Annual Report on Form 10-K did 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 and, accordingly, a testing program is being executed.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

See Note 12 – 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

Item 1A of our 2013 Form 10-K for the year ended December 31, 2013 sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended March 31, 2014. There have been no material changes to the risk factors contained in our 2013 Form 10-K for the year ended December 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: May 7, 2014	By:	/s/ Gary J. Brauchle
		Name:	Gary J. Brauchle
		Title:	Executive Vice President, Chief Financial Officer and Treasurer

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