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EX-31.1 - EXHIBIT 31.1 - Tallgrass Energy Partners, LPtep201633110qexhibit311.htm
EX-12.1 - EXHIBIT 12.1 - Tallgrass Energy Partners, LPtep201633110qexhibit121.htm
EX-32.2 - EXHIBIT 32.2 - Tallgrass Energy Partners, LPtep201633110qexhibit322.htm
EX-32.1 - EXHIBIT 32.1 - Tallgrass Energy Partners, LPtep201633110qexhibit321.htm
EX-31.2 - EXHIBIT 31.2 - Tallgrass Energy Partners, LPtep201633110qexhibit312.htm


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, 2016
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-35917
 
 
 
 
 Tallgrass Energy Partners, LP
(Exact name of registrant as specified in its charter)
 
 
 
Delaware
 
 
 
46-1972941
(State or other Jurisdiction of Incorporation or Organization)
 
 
 
(IRS Employer Identification Number)
 
 
 
 
 
4200 W. 115th Street, Suite 350
 
 
 
 
Leawood, Kansas
 
 
 
66211
(Address of Principal Executive Offices)
 
 
 
(Zip Code)
(913) 928-6060
(Registrant's Telephone Number, Including Area Code)
 
 
 
 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  x    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer", and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
 
x
  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
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 9, 2016, the Registrant had 72,097,211 Common Units and 834,391 General Partner Units outstanding.




TALLGRASS ENERGY PARTNERS, LP
TABLE OF CONTENTS
 




Glossary of Common Industry and Measurement Terms
Bakken oil production area: Montana and North Dakota in the United States and Saskatchewan and Manitoba in Canada.
Barrel (or bbl): forty two U.S. gallons.
Base Gas (or Cushion Gas): the volume of gas that is intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates.
BBtu: one billion British Thermal Units.
Bcf: one billion cubic feet.
British Thermal Units or Btus: the amount of heat energy needed to raise the temperature of one pound of water by one degree Fahrenheit.
Commodity sensitive contracts or arrangements: contracts or other arrangements, including tariff provisions, that directly expose our cash flows to increases and decreases in the price of commodities such as crude oil, natural gas and NGLs. Examples are Keep Whole Processing Contracts and Percent of Proceeds Processing Contracts, as well as pipeline loss allowances on our pipelines.
Condensate: a NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
Contract barrels: barrels of crude oil that our customers have contractually agreed to ship in exchange for firm service assurance of capacity and deliverability to delivery points.
Delivery point: any point at which product in a pipeline is delivered to or for the account of a customer.
Dry gas: a gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.
Dth: a dekatherm, which is a unit of energy equal to 10 therms or one million British thermal units.
End-user markets: the ultimate users and consumers of transported energy products.
EPA: the United States Environmental Protection Agency.
FERC: Federal Energy Regulatory Commission.
Firm fee contracts: firm fee contracts generally obligate our customers to pay a fixed recurring charge to reserve an agreed upon amount of capacity and/or deliverability on our assets, regardless if the contracted capacity is actually used by the customer. Such contracts are also commonly known as "take-or-pay" contracts.
Firm services: services pursuant to which customers receive firm assurances regarding the availability of capacity and/or deliverability of natural gas, crude oil or other hydrocarbons or water on our assets up to a contracted amount.
Fractionation: the process by which NGLs are further separated into individual, typically more valuable components including ethane, propane, butane, isobutane and natural gasoline.
GAAP: generally accepted accounting principles in the United States of America.
GHGs: greenhouse gases.
Header system: networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large diameter high pressure long-haul transportation pipelines.
Interruptible services: services pursuant to which customers receive limited, or no, assurances regarding the availability of capacity and deliverability in our assets.
Keep Whole Processing Contracts: natural gas processing contracts in which we are required to replace the Btu content of the NGLs extracted from inlet wet gas processed with purchased dry natural gas.
Line fill: the volume of oil, in barrels, in the pipeline from the origin to the destination.




Liquefied natural gas or LNG: natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.
Local distribution company or LDC: LDCs are involved in the delivery of natural gas to consumers within a specific geographic area.
Long-term: with respect to any contract, a contract with an initial duration greater than one year.
MMBtu: one million British Thermal Units.
Mcf: one thousand cubic feet.
MMcf: one million cubic feet.
Natural gas liquids or NGLs: those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).
Natural Gas Processing: the separation of natural gas into pipeline-quality natural gas and a mixed NGL stream.
Non-contract barrels (or walk-up barrels): barrels of crude oil that our customers ship based solely on availability of capacity and deliverability with no assurance of future capacity.
No-notice service: those services pursuant to which customers receive the right to transport or store natural gas on assets outside of the daily nomination cycle without incurring penalties.
NYMEX: New York Mercantile Exchange.
Park and loan services: those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our facilities on a seasonal basis.
Percent of Proceeds Processing Contracts: natural gas processing contracts in which we process our customer's natural gas, sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. Some percent of proceeds contracts may also require our customers to pay a monthly reservation fee for processing capacity.
PHMSA: the United States Department of Transportation's Pipeline and Hazardous Materials Safety Administration.
Play: a proven geological formation that contains commercial amounts of hydrocarbons.
Produced water: all water removed from a well as a byproduct of the production of hydrocarbons and water removed from a well in connection with operations being conducted on the well, including naturally occurring water in the recovery formation, flow back water recovered during completion and fracturing operations and water entering the recovery formation through water flooding techniques.
Receipt point: the point where a product is received by or into a gathering system, processing facility, or transportation pipeline.
Reservoir: a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (such as crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.
Residue gas: the natural gas remaining after being processed or treated.
Shale gas: natural gas produced from organic (black) shale formations.
Tailgate: the point at which processed natural gas and NGLs leave a processing facility for transportation to end-user markets.
TBtu: one trillion British Thermal Units.
Tcf: one trillion cubic feet.




Throughput: the volume of products, such as crude oil, natural gas or water, transported or passing through a pipeline, plant, terminal or other facility during a particular period.
Uncommitted shippers (or walk-up shippers): customers that have not signed long-term shipper contracts and have rights under the FERC tariff as to rates and capacity allocation that are different than long-term committed shippers.
Volumetric fee contracts: volumetric fee contracts generally obligate a customer to pay fees based upon the extent to which such customer utilizes our assets for midstream energy services. Unlike firm fee contracts, under volumetric fee contracts our customers are not generally required to pay a charge to reserve an agreed upon amount of capacity and/or deliverability.
Wellhead: the equipment at the surface of a well that is used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground.
Working gas: the volume of gas in the storage reservoir that is in addition to the cushion or base gas. It may or may not be completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be used more than once during any season.
Working gas storage capacity: the maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes base gas and non-cycling working gas.
X/d: the applicable measurement metric per day. For example, MMcf/d means one million cubic feet per day.




PART 1—FINANCIAL INFORMATION
Item 1. Financial Statements
TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED BALANCE SHEETS 
(UNAUDITED)
 
March 31, 2016
 
December 31, 2015
 
(in thousands)
ASSETS
 
Current Assets:
 
 
 
Cash and cash equivalents
$
2,885

 
$
1,611

Accounts receivable, net
53,330

 
57,757

Gas imbalances
552

 
1,227

Inventories
13,739

 
13,793

Prepayments and other current assets
2,883

 
2,835

Total Current Assets
73,389

 
77,223

Property, plant and equipment, net
2,017,138

 
2,025,018

Goodwill
343,288

 
343,288

Intangible asset, net
95,795

 
96,546

Derivative asset at fair value
37,014

 

Deferred financing costs, net
6,102

 
5,105

Deferred charges and other assets
14,046

 
14,894

Total Assets
$
2,586,772

 
$
2,562,074

LIABILITIES AND PARTNERS' EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)
$
17,794

 
$
22,218

Accounts payable to related parties
4,435

 
7,852

Gas imbalances
935

 
1,605

Derivative liabilities at fair value
44

 

Accrued taxes
19,450

 
13,844

Accrued liabilities
6,520

 
10,019

Deferred revenue
33,823

 
26,511

Other current liabilities
6,969

 
6,880

Total Current Liabilities
89,970

 
88,929

Long-term debt
1,200,000

 
753,000

Other long-term liabilities and deferred credits
4,904

 
5,143

Total Long-term Liabilities
1,204,904

 
758,143

Commitments and Contingencies

 

Equity:
 
 
 
Common unitholders (67,499,543 and 60,644,232 units issued and outstanding at March 31, 2016 and December 31, 2015, respectively)
1,882,611

 
1,618,766

General partner (834,391 units issued and outstanding at March 31, 2016 and December 31, 2015)
(624,511
)
 
(348,841
)
Total Partners' Equity
1,258,100

 
1,269,925

Noncontrolling interests
$
33,798

 
$
445,077

Total Equity
$
1,291,898

 
$
1,715,002

Total Liabilities and Equity
$
2,586,772

 
$
2,562,074


The accompanying notes are an integral part of these condensed consolidated financial statements.
1



TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
 
Three Months Ended March 31,
 
2016
 
2015
 
(in thousands, except per unit amounts)
Revenues:
 
 
 
Crude oil transportation services
$
94,572

 
$
50,381

Natural gas transportation services
29,280

 
32,148

Sales of natural gas, NGLs, and crude oil
13,926

 
21,869

Processing and other revenues
7,627

 
10,277

Total Revenues
145,405

 
114,675

Operating Costs and Expenses:
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
13,568

 
19,593

Cost of transportation services (exclusive of depreciation and amortization shown below)
16,156

 
10,715

Operations and maintenance
12,477

 
9,575

Depreciation and amortization
21,692

 
20,605

General and administrative
13,016

 
12,689

Taxes, other than income taxes
7,506

 
11,297

Loss on sale of assets

 
4,483

Total Operating Costs and Expenses
84,415

 
88,957

Operating Income
60,990

 
25,718

Other (Expense) Income:
 
 
 
Interest expense, net
(7,499
)
 
(3,440
)
Unrealized loss on derivative instrument
(8,946
)
 

Other income, net
566

 
712

Total Other Expense
(15,879
)
 
(2,728
)
Net income
45,111

 
22,990

Net (income) loss attributable to noncontrolling interests
(1,041
)
 
9,329

Net income attributable to partners
$
44,070

 
$
32,319

Allocation of income to the limited partners:
 
 
 
Net income attributable to partners
$
44,070

 
$
32,319

General partner interest in net income
(20,353
)
 
(7,438
)
Common and subordinated unitholders' interest in net income
23,717

 
24,881

Basic net income per common and subordinated unit
$
0.35

 
$
0.47

Diluted net income per common and subordinated unit
$
0.35

 
$
0.46

Basic average number of common and subordinated units outstanding
66,967

 
52,727

Diluted average number of common and subordinated units outstanding
67,807

 
53,994


The accompanying notes are an integral part of these condensed consolidated financial statements.
2



TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
Three Months Ended March 31,
 
2016
 
2015
 
(in thousands)
Cash Flows from Operating Activities:
 
 
 
Net income
$
45,111

 
$
22,990

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
22,870

 
21,557

Noncash compensation expense
1,166

 
1,527

Noncash change in fair value of derivative financial instruments
8,990

 
(90
)
Loss on sale of assets

 
4,483

Changes in components of working capital:
 
 
 
Accounts receivable and other
5,800

 
(5,678
)
Gas imbalances
566

 
143

Inventories
(508
)
 
(2,754
)
Accounts payable and accrued liabilities
(2,196
)
 
6,546

Deferred revenue
7,204

 
106

Other operating, net
(246
)
 
(191
)
Net Cash Provided by Operating Activities
88,757

 
48,639

Cash Flows from Investing Activities:
 
 
 
Capital expenditures
(17,545
)
 
(13,300
)
Acquisition of Pony Express membership interest
(49,118
)
 
(700,000
)
Other investing, net
25

 
(311
)
Net Cash Used in Investing Activities
(66,638
)
 
(713,611
)
Cash Flows from Financing Activities:
 
 
 
Distributions to unitholders
(59,040
)
 
(28,294
)
Acquisition of Pony Express membership interest
(425,882
)
 

Contributions from noncontrolling interests
7,152

 
2,379

Distributions to noncontrolling interests
(1,793
)
 
(1,416
)
Borrowings under revolving credit facility, net
447,000

 
139,000

Proceeds from public offering, net of offering costs
12,636

 
551,949

Other financing, net
(918
)
 
1,363

Net Cash (Used in) Provided by Financing Activities
(20,845
)
 
664,981

Net Change in Cash and Cash Equivalents
1,274

 
9

Cash and Cash Equivalents, beginning of period
1,611

 
867

Cash and Cash Equivalents, end of period
$
2,885

 
$
876

 
 
 
 
Schedule of Noncash Investing and Financing Activities:
 
 
 
Property, plant and equipment acquired via the cash management agreement with Tallgrass Development, LP
$

 
$
72,407


The accompanying notes are an integral part of these condensed consolidated financial statements.
3



TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)
 
Limited Partners
 
General Partner
 
Total Partners’ Equity
 
Noncontrolling Interests
 
Total Equity
 
Common
 
Subordinated
 
 
 
 
 
(in thousands)
Balance at January 1, 2016
$
1,618,766

 
$

 
$
(348,841
)
 
$
1,269,925

 
$
445,077

 
$
1,715,002

Net income
23,717

 

 
20,353

 
44,070

 
1,041

 
45,111

Issuance of units to public, net of offering costs
12,636

 

 

 
12,636

 

 
12,636

Noncash compensation expense
1,869

 

 

 
1,869

 

 
1,869

Distributions to unitholders
(42,984
)
 

 
(16,056
)
 
(59,040
)
 

 
(59,040
)
Acquisition of additional 31.3% membership interest in Pony Express
268,607

 

 
(279,967
)
 
(11,360
)
 
(417,679
)
 
(429,039
)
Contributions from noncontrolling interest

 

 

 

 
7,152

 
7,152

Distributions to noncontrolling interest

 

 

 

 
(1,793
)
 
(1,793
)
Balance at March 31, 2016
$
1,882,611

 
$

 
$
(624,511
)
 
$
1,258,100

 
$
33,798

 
$
1,291,898

 
 
 
 
 
 
 
 
 
 
 
 
 
Limited Partners
 
General Partner
 
Total Partners’ Equity
 
Noncontrolling Interests
 
Total Equity
 
Common
 
Subordinated
 
 
 
 
 
(in thousands)
Balance at January 1, 2015
$
800,333

 
$
274,133

 
$
(35,743
)
 
$
1,038,723

 
$
756,428

 
$
1,795,151

Net income (loss)
19,701

 
5,180

 
7,438

 
32,319

 
(9,329
)
 
22,990

Issuance of units to public, net of offering costs
551,949

 

 

 
551,949

 

 
551,949

Noncash compensation expense
2,933

 

 

 
2,933

 

 
2,933

Distributions to unitholders
(15,925
)
 
(7,857
)
 
(4,512
)
 
(28,294
)
 

 
(28,294
)
Contributions from noncontrolling interest

 

 

 

 
2,379

 
2,379

Distributions to noncontrolling interest

 

 

 

 
(2,156
)
 
(2,156
)
Acquisition of additional 33.3% Pony Express membership interest

 

 
(324,328
)
 
(324,328
)
 
(375,672
)
 
(700,000
)
Conversion of subordinated units
271,456

 
(271,456
)
 

 

 

 

Balance at March 31, 2015
$
1,630,447

 
$

 
$
(357,145
)
 
$
1,273,302

 
$
371,650

 
$
1,644,952



The accompanying notes are an integral part of these condensed consolidated financial statements.
4



TALLGRASS ENERGY PARTNERS, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. Description of Business
Tallgrass Energy Partners, LP ("TEP" or the "Partnership") is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. "We," "us," "our" and similar terms refer to TEP together with its consolidated subsidiaries. We currently provide crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). As discussed in Note 14Subsequent Events, we recently acquired a membership interest in Rockies Express Pipeline LLC ("REX"), a Delaware limited liability company engaged in the ownership and operation of the Rockies Express Pipeline, a FERC-regulated natural gas pipeline transportation system, traversing an area from the Rocky Mountain Region to the Appalachian Mountain Region. We also provide services for customers in Wyoming at the Casper and Douglas natural gas processing facilities and the West Frenchie Draw natural gas treating facility (collectively, the "Midstream Facilities"), and NGL transportation services in Northeast Colorado. We perform water business services in Colorado and Texas through BNN Water Solutions, LLC ("Water Solutions"). Our operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations.
Our reportable business segments are:
Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system;
Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and
Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, the provision of water business services primarily to the oil and gas exploration and production industry and the transportation of NGLs.
The table below summarizes our equity ownership as of March 31, 2016:
Unit Holder
 
Limited Partner Common Units 
 
General Partner Units
 
Percentage of Outstanding Limited Partner Common Units
 
Percentage of Outstanding Common and General Partner Units
Public Unitholders
 
34,626,063

 

 
51.30
%
 
50.67
%
Tallgrass Equity, LLC
 
20,000,000

 

 
29.63
%
 
29.27
%
Tallgrass Development, LP
 
12,873,480

 

 
19.07
%
 
18.84
%
Tallgrass MLP GP, LLC (1)
 

 
834,391

 

 
1.22
%
Total
 
67,499,543

 
834,391

 
100.00
%
 
100.00
%
(1) 
Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.

5



2. Summary of Significant Accounting Policies
Basis of Presentation
These condensed consolidated financial statements and related notes for the three months ended March 31, 2016 and 2015 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America ("GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three months ended March 31, 2016 and 2015 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.
Our financial results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2016. The accompanying condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015 ("2015 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 17, 2016.
The condensed consolidated financial statements include the accounts of TEP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Prior to January 1, 2016, Pony Express participated in a cash management agreement with Tallgrass Development, LP ("TD"), which currently holds a 2.0% common membership interest in Pony Express, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. Effective January 1, 2016, Pony Express entered into a cash management agreement with TEP.
Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Pony Express effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million (prorated to approximately $5.4 million for the quarter ended September 30, 2014) through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ending December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 are attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests.
A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the assets of our consolidated VIE that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of our consolidated VIE for which creditors do not have recourse to our general credit. Pony Express was considered to be a VIE under the applicable authoritative guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express.

6



Use of Estimates
Certain amounts included in or affecting these condensed consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets, liabilities, revenues, and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
New Accounting Pronouncements
Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers (Topic 606)"
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.
The amendments in ASU 2014-09 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact of ASU 2014-09.
ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period"
In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved.
ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2014-12 did not have a material impact on our financial position and results of operations.
ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis"
In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis. ASU 2015-02 will change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 will modify the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminate the presumption that a general partner should consolidate a limited partnership, and change certain aspects of the consolidation analysis for reporting entities that are involved with VIEs, particularly for those with fee arrangements and related party relationships.
The amendments in ASU 2015-02 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2015-02 did not have a material impact on our financial position and results of operations.

7



ASU No. 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory"
In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory. ASU 2015-11 establishes a "lower of cost and net realizable value" model for the measurement of most inventory balances. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.
The amendments in ASU 2015-11 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We are currently evaluating the impact of ASU 2015-11.
ASU No. 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments"
In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. ASU 2015-16 simplifies the accounting for measurement-period adjustments for provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the provisional amounts must be calculated as if the accounting had been completed at the acquisition date.
The amendments in ASU 2015-16 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2015-16 did not have a material impact on our financial position and results of operations.
ASU No. 2016-02, "Leases (Topic 842)"
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.
The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the impact of ASU 2016-02.
ASU No. 2016-08, "Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)"
In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). ASU 2016-08 provides further clarification of the guidance in ASU 2014-09 with respect to principal versus agent considerations and are intended to improve the operability and understandability of the implementation guidance provided in ASU 2014-09.
The amendments in ASU 2016-08 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact of ASU 2016-08.
ASU No. 2016-09, "Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting"
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Among other changes, ASU 2016-09 allows an entity to make an entity-wide accounting policy election to either estimate the number of awards expected to vest (consistent with current GAAP) or account for forfeitures when they occur.
The amendments in ASU 2016-09 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We are currently evaluating the impact of ASU 2016-09.

8



3. Acquisitions
Acquisition of Additional 31.3% Membership Interest in Pony Express
Effective January 1, 2016, TEP acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of our common units) issued to TD, for total consideration of approximately $743.6 million. The transaction increased our aggregate membership interest in Pony Express to 98.0%. As part of the transaction, TD granted us an 18 month call option to repurchase the newly issued 6,518,000 common units at a price of $42.50. On the effective date of the acquisition, the call option was valued at $46.0 million. The acquisition of the additional 31.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction have not been recast to reflect the additional 31.3% membership interest. The transaction resulted in a deemed distribution to our general partner as discussed further in Note 9Partnership Equity and Distributions.
Cash outflows to acquire an additional noncontrolling interest in Pony Express are classified as an investing activity in the accompanying condensed consolidated statements of cash flows to the extent the consideration paid was used to directly fund the construction of the underlying assets by the noncontrolling member. Cash outflows to acquire an additional noncontrolling interest in excess of the cost to construct the underlying assets are classified as financing activities. For the three months ended March 31, 2016, $49.1 million of the $475 million paid to acquire the additional 31.3% membership interest in Pony Express was classified as an investing activity and $425.9 million was classified as a financing activity.
TEP Acquisition of BNN Western, LLC
On December 16, 2015, Whiting Oil and Gas Corporation ("Whiting"), BNN Redtail, LLC ("Redtail"), and BNN Western, LLC ("Western"), a newly formed Delaware limited liability company, entered into a definitive Transfer, Purchase and Sale Agreement, pursuant to which Redtail acquired 100% of the outstanding membership interests of Western from Whiting in exchange for total cash consideration of $75 million. Western's assets consist of a fresh water delivery and storage system and produced water gathering and produced water disposal system, which together comprise 62 miles of pipeline along with associated fresh water ponds and disposal wells. As part of the transaction with Whiting, Whiting also executed a five-year fresh water service contract and a nine-year gathering and disposal contract.
At December 31, 2015, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. The $75 million purchase price of the assets was allocated entirely to property, plant and equipment. TEP is in the process of obtaining additional information to identify and measure all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts.
TEP's unaudited pro forma revenue and net income attributable to partners for the three months ended March 31, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015:
 
Three Months Ended March 31, 2015
 
(in thousands)
Revenue
$
115,147

Net income attributable to partners
$
32,483

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

9



4. Related Party Transactions
We have no employees. TD, through its wholly-owned subsidiary Tallgrass Operations, LLC ("Tallgrass Operations"), provided and charged us for direct and indirect costs of services provided to us or incurred on our behalf including employee labor costs, information technology services, employee health and retirement benefits, and all other expenses necessary or appropriate to the conduct of our business. We recorded these costs on the accrual basis in the period in which TD incurred them. On May 17, 2013, in connection with the closing of TEP's initial public offering, TEP and its general partner entered into an Omnibus Agreement with TD and certain of its affiliates, including Tallgrass Operations (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse TD and its affiliates for all expenses they incur and payments they make on TEP's behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by TD, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP.
There was no interest income from TD recognized for the three months ended March 31, 2016. During the three months ended March 31, 2015 we recognized interest income from TD of $0.4 million on the receivable balance under the Pony Express cash management agreement in effect through December 31, 2015.
Totals of transactions with affiliated companies are as follows:
 
Three Months Ended March 31,
 
2016
 
2015
 
(in thousands)
Cost of transportation services
$
7,256

 
$
4,358

Charges to TEP: (1)
 
 
 
Property, plant and equipment, net
$
899

 
$
1,307

Operation and maintenance
$
6,138

 
$
5,423

General and administrative
$
8,966

 
$
9,256

(1) 
Charges to TEP, inclusive of Pony Express, include directly charged wages and salaries, other compensation and benefits, and shared services.
Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows: 
 
March 31, 2016
 
December 31, 2015
 
(in thousands)
Receivable from related parties:
 
 
 
Rockies Express Pipeline LLC
$
31

 
$
15

Total receivable from related parties
$
31

 
$
15

Accounts payable to related parties:
 
 
 
Tallgrass Operations, LLC
$
4,385

 
$
7,792

Tallgrass Equity, LLC
41

 
36

Deeprock Development, LLC

 
17

Rockies Express Pipeline LLC
9

 
7

Total accounts payable to related parties
$
4,435

 
$
7,852

Balances of gas imbalances with affiliated shippers are as follows:
 
March 31, 2016
 
December 31, 2015
 
(in thousands)
Affiliate gas balance receivables
$
7

 
$
92

Affiliate gas balance payables
$
102

 
$
227


10



5. Inventory
The components of inventory at March 31, 2016 and December 31, 2015 consisted of the following:
 
March 31, 2016
 
December 31, 2015
 
(in thousands)
Crude oil
$
4,194

 
$
2,661

Materials and supplies
6,741

 
8,581

Natural gas liquids
303

 
395

Gas in underground storage
2,501

 
2,156

Total inventory
$
13,739

 
$
13,793

6. Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
 
March 31, 2016
 
December 31, 2015
 
(in thousands)
Crude oil pipelines
$
1,177,790

 
$
1,172,684

Natural gas pipelines
551,983

 
550,710

Processing and treating assets
255,663

 
254,073

Water business assets
82,608

 
81,098

General and other
80,660

 
69,181

Construction work in progress
21,255

 
30,699

Accumulated depreciation and amortization
(152,821
)
 
(133,427
)
Total property, plant and equipment, net
$
2,017,138

 
$
2,025,018

7. Risk Management
We occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of 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.
As discussed in Note 3Acquisitions, in conjunction with our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option to repurchase the newly issued 6,518,000 common units at a price of $42.50. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets:
 
Balance Sheet
Location
 
March 31, 2016
 
December 31, 2015
 
 
 
(in thousands)
Call option derivative
Noncurrent assets
 
$
37,014

 
$

Energy commodity derivative contracts
Current liabilities
 
$
44

 
$

As of March 31, 2016, the fair value shown for commodity contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.4 Bcf. As of December 31, 2015 there were no derivative contracts outstanding.

11



Effect of Derivative Contracts in the Statements of Income
The following table summarizes the impact of derivative contracts for the three months ended March 31, 2016 and 2015:
 
Location of gain (loss) recognized
in income on derivatives
 
Amount of gain (loss) recognized in income on derivatives
 
 
 
 
Three Months Ended March 31,
 
 
2016
 
2015
 
 
 
(in thousands)
Derivatives not designated as hedging contracts:
 
 
 
 
 
Call option derivative
Unrealized loss on derivative instrument
 
$
(8,946
)
 
$

Energy commodity derivative contracts
Sales of natural gas, NGLs, and crude oil
 
$
(44
)
 
$
90

Credit Risk
We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our energy commodity derivatives consist of major financial institutions. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. The counterparty to our call option derivative is TD. Settlement of the call option derivative, if exercised, will require TEP to make a cash payment to TD in exchange for return of the common units.
Our over-the-counter swaps are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with financial institutions with investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. As of March 31, 2016, the fair value of our commodity derivative contracts was a liability, resulting in no credit exposure from TEP's counterparties as of that date.
As of March 31, 2016 and December 31, 2015, we did not have any outstanding letters of credit or cash in margin accounts in support of our hedging of commodity price risks associated with the sale of natural gas nor did we have any margin deposits with counterparties associated with energy commodity contract positions.
Fair Value
Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We value exchange-traded derivative contracts using quoted market prices for identical securities.
OTC derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.
Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management's best estimate is used.
The call option granted by TD is valued using a Black-Scholes option pricing model. Key inputs to the valuation model include the term of the option, risk free rate, the exercise price and current market price, expected volatility and expected distribution yield of the underlying units. The call option valuation is classified within Level 2 of the fair value hierarchy as the value is based on significant observable inputs.

12



The following table summarizes the fair value measurements of our derivative contracts as of March 31, 2016 based on the fair value hierarchy established by the Codification:
 
 
 
Asset Fair Value Measurements Using
 
Total
 
Quoted prices in
active markets
for identical
assets
(Level 1)
 
Significant
other observable
inputs
(Level 2)
 
Significant
unobservable
inputs
(Level 3)
 
(in thousands)
As of March 31, 2016
 
 
 
 
 
 
 
Call option derivative
$
37,014

 
$

 
$
37,014

 
$

 
 
 
 
 
 
 
 
 
 
 
Liability Fair Value Measurements Using
 
Total
 
Quoted prices in
active markets
for identical
assets
(Level 1)
 
Significant
other observable
inputs
(Level 2)
 
Significant
unobservable
inputs
(Level 3)
 
(in thousands)
As of March 31, 2016
 
 
 
 
 
 
 
Energy commodity derivative contracts
$
44

 
$

 
$
44

 
$

8. Long-term Debt
Revolving Credit Facility
Effective January 4, 2016, in connection with the acquisition of an additional 31.3% membership interest in Pony Express, TEP exercised the committed accordion feature to increase the total capacity of the revolving credit facility from $1.1 billion to $1.5 billion. As discussed in Note 14Subsequent Events, effective May 6, 2016 we amended the revolving credit facility to increase the total capacity to $1.75 billion.
The following table sets forth the available borrowing capacity under our revolving credit facility as of March 31, 2016 and December 31, 2015:
 
March 31, 2016
 
December 31, 2015
 
(in thousands)
Total capacity under the revolving credit facility
$
1,500,000

 
$
1,100,000

Less: Outstanding borrowings under the revolving credit facility
(1,200,000
)
 
(753,000
)
Available capacity under the revolving credit facility
$
300,000

 
$
347,000

The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict our ability (as well as the ability of our restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of our business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, we are required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of March 31, 2016, we are in compliance with the covenants required under the revolving credit facility.
The unused portion of the revolving credit facility is subject to a commitment fee, which ranges from 0.300% to 0.500%, based on our total leverage ratio. As of March 31, 2016, the weighted average interest rate on outstanding borrowings was 2.20%. During the three months ended March 31, 2016, our weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 2.48%.

13



Fair Value
The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015, but for which fair value is disclosed:
 
Fair Value
 
 
 
Quoted prices
in active markets
for identical assets
(Level 1)
 
Significant
other observable
inputs
(Level 2)
 
Significant
unobservable
inputs
(Level 3)
 
Total
 
Carrying
Amount
 
(in thousands)
 
 
March 31, 2016
$

 
$
1,200,000

 
$

 
$
1,200,000

 
$
1,200,000

December 31, 2015
$

 
$
753,000

 
$

 
$
753,000

 
$
753,000

The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of March 31, 2016 and December 31, 2015, the fair value approximates the carrying amount for the borrowings under the revolving credit facility using a discounted cash flow analysis. We are not aware of any factors that would significantly affect the estimated fair value subsequent to March 31, 2016.
9. Partnership Equity and Distributions
Equity Distribution Agreement
On October 31, 2014, we entered into an equity distribution agreement pursuant to which we may sell from time to time through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering price of up to $200 million. On May 13, 2015 the amount was subsequently amended to $100.2 million in order to account for follow-on equity offerings under our S-3 shelf registration statement. Sales of the common units, if any, will be made by means of ordinary brokers' transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by the Partnership and one or more of the managers. We intend to use the net cash proceeds from any sale of the units for general partnership purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
During the three months ended March 31, 2016, we issued and sold 337,311 common units with a weighted average sales price of $38.17 per unit under our equity distribution agreement for net cash proceeds of approximately $12.6 million (net of approximately $240,000 in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes. At March 31, 2016, approximately $83.1 million in aggregate offering price remained available to be issued and sold under the equity distribution agreement. Subsequent to March 31, 2016, we issued and sold an additional 2,180,681 common units with a weighted average sales price of $37.93 per unit under our equity distribution agreement for net cash proceeds of approximately $81.9 million (net of approximately $830,000 in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes.
Tallgrass Development Purchase Program
On February 17, 2016, TEP and Tallgrass Energy GP, LP ("TEGP") announced that the Board of Directors of Tallgrass Energy Holdings, LLC, the sole member of TEGP's general partner and the general partner of TD, has authorized an equity purchase program under which TD may initially purchase up to an aggregate of $100 million of the outstanding Class A shares of TEGP or the outstanding common units of TEP. TD may purchase Class A shares or Common Units from time to time on the open market or in negotiated purchases. The timing and amounts of any such purchases will be subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The purchase plan does not obligate TD to acquire any specific number of Class A shares or Common Units and may be discontinued at any time. No purchases were made under this program during the three months ended March 31, 2016.

14



Distributions to Holders of Common Units, Subordinated Units, General Partner Units and Incentive Distribution Rights
Our partnership agreement requires us to distribute our available cash, as defined in the partnership agreement, to unitholders of record on the applicable record date within 45 days after the end of each quarter. The following table shows the distributions for the periods indicated:
 
 
 
 
Distributions
 
 
  
 
 
 
Limited Partners
Common and
Subordinated Units
 
General Partner
 
 
 
Distributions
per Limited
Partner Unit
Three Months Ended
 
Date Paid
 
Incentive Distribution Rights
 
General Partner Units
 
Total
 
 
 
 
 
(in thousands, except per unit amounts)
 
 
March 31, 2016
 
May 13, 2016 (1)
 
$
48,238

 
$
19,816

 
$
830

 
$
68,884

 
$
0.7050

December 31, 2015
 
February 12, 2016
 
42,984

 
15,332

 
724

 
59,040

 
0.6400

September 30, 2015
 
November 13, 2015
 
36,347

 
11,567

 
660

 
48,574

 
0.6000

June 30, 2015
 
August 14, 2015
 
35,135

 
10,418

 
627

 
46,180

 
0.5800

March 31, 2015
 
May 14, 2015
 
31,322

 
6,934

 
530

 
38,786

 
0.5200

(1) 
The distribution announced on April 12, 2016 for the first quarter of 2016 will be paid on May 13, 2016 to unitholders of record at the close of business on April 21, 2016.
Other Contributions and Distributions
During the three months ended March 31, 2016, TEP was deemed to have made a noncash capital distribution of $280.0 million to the general partner, which represents the excess purchase price over the carrying value of the additional 31.3% membership interest in Pony Express acquired effective January 1, 2016. See Note 3 - Acquisitions for additional information regarding the transaction.
During the three months ended March 31, 2015, TEP was deemed to have made a noncash capital distribution of $324.3 million to the general partner, which represents the excess purchase price over the carrying value of the additional 33.3% membership interest in Pony Express acquired effective March 1, 2015.
10. Net Income per Limited Partner Unit
The Partnership's net income is allocated to the general partner and the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners' interest in net income, less general partner incentive distributions, by the weighted average number of outstanding limited partner units during the period.
We compute earnings per unit using the two-class method for Master Limited Partnerships as prescribed in the FASB guidance. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.
We calculate net income available to limited partners based on the distributions pertaining to the current period's net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement and as further prescribed in the FASB guidance under the two-class method.
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights (which are currently held by our general partner), even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.
Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units.
The following table illustrates the Partnership's calculation of net income per common and subordinated unit for the three months ended March 31, 2016 and 2015:
 
Three Months Ended March 31,
 
2016
 
2015
 
(in thousands, except per unit amounts)
Net income
$
45,111

 
$
22,990

Net (income) loss attributable to noncontrolling interests
(1,041
)
 
9,329

Net income attributable to partners
44,070

 
32,319

General partner interest in net income
(20,353
)
 
(7,438
)
Net income available to common and subordinated unitholders
$
23,717

 
$
24,881

Basic net income per common and subordinated unit
$
0.35

 
$
0.47

Diluted net income per common and subordinated unit
$
0.35

 
$
0.46

Basic average number of common and subordinated units outstanding
66,967

 
52,727

Equity Participation Unit equivalent units
840

 
1,267

Diluted average number of common and subordinated units outstanding
67,807

 
53,994

11. Regulatory Matters
There are currently no proceedings challenging the currently effective rates of Pony Express or Trailblazer Pipeline Company LLC ("Trailblazer"). On October 30, 2015, Tallgrass Interstate Gas Transmission, LLC ("TIGT") filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), discussed in more detail below. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable law, to challenge the rates that we charge at our regulated entities. Further, applicable law governing service by Pony Express allows parties having standing to file complaints in regard to existing tariff rates and provisions. If the complaint is not resolved, the FERC may conduct a hearing and order a crude oil pipeline like the Pony Express System to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. We can provide no assurance that current rates will remain unchallenged. Any successful challenge could have a material, adverse effect on our future earnings and cash flows.
TIGT
General Rate Case Filing – FERC Docket RP16-137
On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA. The rate case proposed a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT. In addition, TIGT proposed certain changes to the transportation rate design of its system to replace the current rate zone structure with a single "postage stamp" rate. TIGT also proposed new incremental charges, including (i) a charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a Cost Recovery Mechanism ("CRM") charge to completely or partially reimburse TIGT for certain costs it incurred to maintain system safety, environmental compliance and reliability. TIGT also proposed to replace its fixed fuel and lost and unaccounted for ("FL&U") charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period's under/over collection and the forecasted FL&U expense for the upcoming period. TIGT also proposed to implement a power cost tracker to recover the actual power costs incurred by TIGT to power its compressors. Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under the NGA and the FERC's regulations, TIGT's shippers and other interested parties, including the FERC's Trial Staff, have a right to challenge any aspect of TIGT's rate case filing. Accordingly, numerous TIGT customers have protested aspects of TIGT's NGA Section 4 rate filing.

15



On November 30, 2015, the FERC issued an order accepting and suspending the proposed rates and a majority of the proposed tariff records to be effective upon motion May 1, 2016, subject to refund, certain modifications to TIGT's proposed CRM charge, and the outcome of an evidentiary hearing before a FERC Administrative Law Judge (the "Suspension Order"). In the Suspension Order, the FERC also accepted two tariff records related to force majeure events and reservation charge crediting to be effective December 1, 2015, subject to certain modifications. On December 21, 2015, TIGT made a compliance filing with the FERC to modify TIGT's proposed CRM charge and update the tariff records related to force majeure events and reservation charge crediting as directed by the FERC in the Suspension Order. No comments or protests were filed in response to the compliance filing and FERC accepted the compliance filing on February 1, 2016. The FERC Administrative Law Judge assigned to the proceeding has issued an order establishing the procedural schedule and TIGT, the FERC's Trial Staff, and other participants that successfully intervened are actively participating in the litigated proceeding to address those rate and tariff matters set for hearing by the FERC in its Suspension Order. On March 22, 2016, a Settlement Judge was appointed in the case to assist the participants explore the possibility of settlement. On March 31, 2016, the FERC issued an order denying a request for rehearing with respect to its challenge of TIGT's proposed CRM. The FERC granted in part and denied in part a motion for technical conference, and denied a rehearing request made in the alternative on this issue, and retained for resolution through hearing the pro forma tariff records related to TIGT's proposed charge at delivery points lacking electronic flow measurement and removed from hearing the other issues related to the pro forma tariff records. Whether such issues will be resolved through technical conference is pending. The FERC also directed TIGT to provide additional information related to certain pro forma tariff records, which TIGT filed on April 14, 2016. TIGT has reached an agreement in principle with customers representing a majority of firm fee revenue on the TIGT System for the year ended December 31, 2015 to settle all rate related issues set for hearing in its existing FERC rate case, including the issues of a cost recovery mechanism and a non-Electronic Flow Measurement charge. The settlement remains subject to the final approval of the FERC.
Trailblazer
2016 Annual Fuel Tracker Filing – FERC Docket RP16-814-000
On April 1, 2016, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2016 in Docket No. RP16-814-000. The FERC accepted this filing on April 18, 2016.
12. Legal and Environmental Matters
Legal
In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on our business, financial position, results of operations or cash flows. We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, had no reserve for legal claims as of March 31, 2016 or December 31, 2015.
Environmental, Health and Safety
We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $4.6 million and $4.8 million at March 31, 2016 and December 31, 2015, respectively.
TMID
Casper Plant, EPA Notice of Violation
In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC ("TMID") received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including the expected inclusion of TIGT as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant site.

16



Casper Mystery Bridge Superfund Site
The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and we have requested that the portion of the site attributable to us be delisted from the National Priorities List.
Casper Gas Plant
On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing.
Trailblazer
Pipeline Integrity Management Program
In 2014 and 2015, Trailblazer conducted smart tool surveys and preliminary analysis on segments of its natural gas pipeline to evaluate the growth rate of corrosion downstream of compressor stations. Trailblazer currently believes that approximately 25 - 35 miles of pipe will likely need to be repaired or replaced in order for the pipeline to operate at its maximum allowable operating pressure of 1,000 pounds per square inch. Such repair or replacement will likely occur over a period of years, depending upon final assessment of corrosion growth rates and the remediation and repair plan implemented by Trailblazer. Trailblazer is currently operating at less than its current maximum allowable operating pressure, public notice of which was first provided in June 2014. The current pressure reduction is not expected to prevent Trailblazer from fulfilling its firm service obligations at existing subscription levels and to date it has not had a material adverse financial impact on TEP.
During 2015, Trailblazer completed 32 excavation digs at an aggregate cost of approximately $1.3 million based on preliminary analysis of the smart tool surveys performed in 2014. Segments of the Trailblazer Pipeline that require full replacement are currently expected to cost in the range of approximately $2.2 million to $2.7 million per mile. Repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. Trailblazer is continuing to develop a remediation and repair plan, which involves, among other things, finalizing cost recovery options, establishing project scope and timing and setting an overall project budget. In 2016, Trailblazer intends to continue assessment and remediation activities, including the replacement of approximately 8 miles of pipe at an estimated cost of $21.5 million. Trailblazer is currently exploring all possible cost recovery options. It may not ultimately be able to recover any or all of such out of pocket costs unless and until Trailblazer recovers them through a general rate increase or other FERC-approved recovery mechanism, or through negotiated rate agreements with its customers.
In connection with TEP's acquisition of the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for any out of pocket costs incurred between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline's disbonded Hi-Melt CTE coating. The contractual indemnity provided to TEP by TD is currently capped at $20 million and is subject to an annual $1.5 million deductible.
13. Reporting Segments
Our operations are located in the United States. We are organized into three reporting segments: (1) Crude Oil Transportation & Logistics, (2) Natural Gas Transportation & Logistics, and (3) Processing & Logistics.
Crude Oil Transportation & Logistics
The Crude Oil Transportation & Logistics segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in the second quarter of 2015.
Natural Gas Transportation & Logistics
The Natural Gas Transportation & Logistics segment is engaged in the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers.

17



Processing & Logistics
The Processing & Logistics segment is engaged in the ownership and operation of natural gas processing, treating and fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, as well as water business services provided primarily to the oil and gas exploration and production industry and the transportation of NGLs.
Corporate and Other
Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit facility, public company costs, and equity-based compensation expense.
These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations.
We consider Adjusted EBITDA our primary segment performance measure as we believe it is the most meaningful measure to assess our financial condition and results of operations as a public entity. We define Adjusted EBITDA, a non-GAAP measure, as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments.
The following tables set forth our segment information for the periods indicated:
 
Three Months Ended March 31, 2016
 
Three Months Ended March 31, 2015
Revenue:
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
(in thousands)
Crude Oil Transportation & Logistics
$
94,572

 
$

 
$
94,572

 
$
50,381

 
$

 
$
50,381

Natural Gas Transportation & Logistics
30,987

 
(1,355
)
 
29,632

 
33,610

 
(1,346
)
 
32,264

Processing & Logistics
21,201

 

 
21,201

 
32,030

 

 
32,030

Corporate and Other

 

 

 

 

 

Total Revenue
$
146,760

 
$
(1,355
)
 
$
145,405

 
$
116,021

 
$
(1,346
)
 
$
114,675


18



 
Three Months Ended March 31, 2016
 
Three Months Ended March 31, 2015
Adjusted EBITDA:
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
(in thousands)
Crude Oil Transportation & Logistics
$
64,541

 
$
1,345

 
$
65,886

 
$
25,506

 
$
1,346

 
$
26,852

Natural Gas Transportation & Logistics
17,152

 
(1,355
)
 
15,797

 
19,246

 
(1,346
)
 
17,900

Processing & Logistics
3,351

 
10

 
3,361

 
8,718

 

 
8,718

Corporate and Other
(1,352
)
 

 
(1,352
)
 
(635
)
 

 
(635
)
Reconciliation to Net Income:
 
 
 
 
 
 
 
 
 
 
 
Add:
 
 
 
 
 
 
 
 
 
 
 
Non-cash loss allocated to noncontrolling interest
 
 
 
 

 
 
 
 
 
9,377

Less:
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net of noncontrolling interest
 
 
 
 
(7,499
)
 
 
 
 
 
(3,440
)
Depreciation and amortization expense, net of noncontrolling interest
 
 
 
 
(21,967
)
 
 
 
 
 
(20,533
)
Non-cash (loss) gain related to derivative instruments
 
 
 
 
(8,990
)
 
 
 
 
 
90

Non-cash compensation expense
 
 
 
 
(1,166
)
 
 
 
 
 
(1,527
)
Non-cash loss from asset sales
 
 
 
 

 
 
 
 
 
(4,483
)
Net income attributable to partners


 


 
$
44,070

 


 


 
$
32,319

 
Three Months Ended March 31,
Capital Expenditures:
2016
 
2015
 
(in thousands)
Crude Oil Transportation & Logistics
$
12,311

 
$
6,480

Natural Gas Transportation & Logistics
2,133

 
3,865

Processing & Logistics
3,101

 
2,955

Corporate and Other

 

Total capital expenditures
$
17,545

 
$
13,300

Assets:
March 31, 2016
 
December 31, 2015
 
(in thousands)
Crude Oil Transportation & Logistics
$
1,433,153

 
$
1,439,418

Natural Gas Transportation & Logistics
698,745

 
706,576

Processing & Logistics
411,509

 
409,795

Corporate and Other
43,365

 
6,285

Total assets
$
2,586,772

 
$
2,562,074


19



14. Subsequent Events
Acquisition of a Membership Interest in Rockies Express Pipeline LLC
On March 29, 2016, TD's indirect wholly owned subsidiary Rockies Express Holdings, LLC ("REX Holdings") signed a purchase agreement (the "Purchase Agreement") with a unit of Sempra U.S. Gas and Power ("Sempra") to acquire Sempra's 25% membership interest in Rockies Express Pipeline LLC ("REX") for cash consideration of $440 million, subject to adjustment under the Purchase Agreement. A subsidiary of Phillips 66, which owns a 25% membership interest in REX, has waived its right to purchase its proportionate share of Sempra's 25% membership interest being sold to REX Holdings (the "Right of First Refusal") in exchange for Sempra and REX Holdings agreeing to certain modifications to the REX Limited Liability Company Agreement.
On April 28, 2016, we announced that TD offered us the right to assume the rights and obligations of REX Holdings under the Purchase Agreement. On May 6, 2016, TEP REX Holdings, LLC ("TEP REX"), an indirect wholly-owned subsidiary of the Partnership, and REX Holdings entered into an Assignment and Assumption Agreement pursuant to which REX Holdings assigned to TEP REX all of its rights under the Purchase Agreement and, in exchange, TEP REX assumed all of the rights and obligations of REX Holdings under the Purchase Agreement. Subsequently on May 6, 2016, TEP REX closed the purchase of a 25% membership interest in REX from Sempra pursuant to the Purchase Agreement for cash consideration of approximately $436.0 million, after making the adjustments to the purchase price required by the Purchase Agreement.
Revolving Credit Facility Increase
In connection with our acquisition of an interest in REX, we have amended our revolving credit facility to, among other things, increase the lender commitments from $1.5 billion to $1.75 billion effective May 6, 2016. As of May 6, 2016, TEP had approximately $1.4 billion of outstanding borrowings under its revolving credit facility.
Unregistered Sale of Equity Securities
On April 28, 2016, we issued an aggregate of 2,416,987 common units representing limited partnership interests in the Partnership for net cash proceeds of $90.0 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C.

20



Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
As used in this Quarterly Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEP" and similar terms refer to Tallgrass Energy Partners, LP, together with its consolidated subsidiaries. The term our "general partner" refers to Tallgrass MLP GP, LLC. References to "TD" refer to Tallgrass Development, LP. The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report. Additionally, the following discussion and analysis should be read in conjunction with our audited financial statements and notes thereto, the related "Management's Discussion and Analysis of Financial Condition and Results of Operations," the discussion of "Risk Factors" and the discussion of TEP's "Business" in our Annual Report on Form 10-K for the year ended December 31, 2015 (our "2015 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 17, 2016.
A reference to a "Note" herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1.Financial Statements. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.
Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report and the documents incorporated by reference herein contain forward-looking statements concerning our operations, economic performance and financial condition. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "could," "will," "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this Quarterly Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our and TD's infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
our ability to complete and integrate acquisitions from TD or from third parties, including our acquisition of a 25% membership interest in Rockies Express Pipeline LLC ("REX") that was completed in May 2016, our acquisition of water business assets in Weld County, Colorado that was completed in December 2015 and our purchase of an additional 31.3% membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express") that was completed in January 2016;
large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;
changes in general economic conditions;
competitive conditions in our industry;
actions taken by third-party operators, processors and transporters;
the demand for our services, including crude oil transportation services, natural gas transportation, storage and processing services and water business services;
our ability to successfully implement our business plan;
our ability to complete internal growth projects on time and on budget;
the price and availability of debt and equity financing;
the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil, natural gas, NGLs, and other hydrocarbons;
the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the price of alternative and competing fuels;

21



competition from the same and alternative energy sources;
energy efficiency and technology trends;
operating hazards and other risks incidental to transporting crude oil, transporting, storing and processing natural gas, and transporting, gathering and disposing of water produced in connection with hydrocarbon exploration and production activities;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
interest rates;
labor relations;
changes in tax status;
the effects of existing and future laws and governmental regulations;
the effects of future litigation; and
certain factors discussed elsewhere in this Quarterly Report.
Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.
Overview
We are a publicly traded, growth-oriented limited partnership formed in 2013 to own, operate, acquire and develop midstream energy assets in North America. We currently provide crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Pony Express, which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). We recently acquired a membership interest in Rockies Express Pipeline LLC ("REX"), a Delaware limited liability company engaged in the ownership and operation of the Rockies Express Pipeline, a FERC-regulated natural gas pipeline transportation system, traversing an area from the Rocky Mountain Region to the Appalachian Mountain Region. We also provide services for customers at our Midstream Facilities located in Wyoming, and NGL transportation services in Northeast Colorado. We perform water business services in Colorado and Texas through Water Solutions. Our operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations.
We intend to continue to leverage our relationship with TD and utilize the significant experience of our management team to execute our growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of our existing assets and expanding our systems through construction of additional assets. Our reportable business segments are:
Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system;
Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and
Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, the provision of water business services primarily to the oil and gas exploration and production industry and the transportation of NGLs.
Recent Developments
Distribution Announced
On April 12, 2016, we announced a cash distribution for the quarter ended March 31, 2016 of $0.705 per common unit. The distribution will be paid on May 13, 2016, to unitholders of record on April 21, 2016.

22



Acquisition of a Membership Interest in Rockies Express Pipeline LLC
On March 29, 2016, TD's indirect wholly owned subsidiary Rockies Express Holdings, LLC ("REX Holdings") signed a purchase agreement (the "Purchase Agreement") with a unit of Sempra U.S. Gas and Power ("Sempra") to acquire Sempra's 25% membership interest in REX for cash consideration of $440 million, subject to adjustment under the Purchase Agreement. A subsidiary of Phillips 66, which owns a 25% membership interest in REX, has waived its right to purchase its proportionate share of Sempra's 25% membership interest being sold to REX Holdings (the "Right of First Refusal") in exchange for Sempra and REX Holdings agreeing to certain modifications to the REX Limited Liability Company Agreement.
On April 28, 2016, we announced that TD offered us the right to assume the rights and obligations of REX Holdings under the Purchase Agreement. On May 6, 2016, TEP REX Holdings, LLC ("TEP REX"), an indirect wholly-owned subsidiary of the Partnership, and REX Holdings entered into an Assignment and Assumption Agreement pursuant to which REX Holdings assigned to TEP REX all of its rights under the Purchase Agreement and, in exchange, TEP REX assumed all of the rights and obligations of REX Holdings under the Purchase Agreement. Subsequently on May 6, 2016, TEP REX closed the purchase of a 25% membership interest in REX from Sempra pursuant to the Purchase Agreement for cash consideration of approximately $436.0 million, after making the adjustments to the purchase price required by the Purchase Agreement.
Revolving Credit Facility Increase
In connection with our acquisition of an interest in REX, we have amended our revolving credit facility to, among other things, increase the lender commitments from $1.5 billion to $1.75 billion effective May 6, 2016. As of May 6, 2016, TEP had approximately $1.4 billion of outstanding borrowings under its revolving credit facility.
Unregistered Sale of Equity Securities
On April 28, 2016, we issued an aggregate of 2,416,987 common units representing limited partnership interests in the Partnership for net cash proceeds of $90.0 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C.
U.S. Crude Oil and Natural Gas Supply and Demand Dynamics
We expect to continue to be affected by certain key factors and trends described below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. See also Item 1A.Risk Factors.
Current Commodity Environment
Starting in 2014, the prices of crude oil, natural gas, and NGLs were extremely volatile and declined significantly. Downward pressure on commodity prices continued in 2015 and the early part of 2016 and may continue for the foreseeable future. This could impact our business in several ways.
Demand for our services depends, in part, on the development of additional natural gas and crude oil reserves by third parties. This requires significant capital expenditures by others to install facilities that extract natural gas and crude oil. However, low commodity prices could result in a lack of available capital for these types of expenditures. To the extent our customers cannot finance these activities, we also expect they will be less likely to enter into demand based, long-term firm fee contracts until commodity prices recover and pricing stability returns to the commodity markets. The recent commodity price declines may also negatively impact the financial condition of our customers and could impact their ability to meet their financial obligations to us. As a result of the current environment, we have seen a number of bankruptcies and credit downgrades within the industry. As a result of credit downgrades, the percent of our revenue from customers with investment grade credit ratings fell to slightly below 50% during the three months ended March 31, 2016, as discussed further in Item 3.—Quantitative and Qualitative Disclosures About Market Risk. Additionally, lower commodity prices generally lead to reduced utilization of our assets. For example, reduced utilization could result in increased deficiency balances held by customers of our Pony Express System. A prolonged period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future impairment of our goodwill or long-lived assets due to the potential impact on our operations and cash flows.
How We Evaluate Our Operations
We evaluate our results using, among other measures, contract profile and volumes, operating costs and expenses, Adjusted EBITDA and Distributable Cash Flow. Adjusted EBITDA and Distributable Cash Flow are non-GAAP measures and are defined below.

23



Contract Profile and Volumes
Our results are driven primarily by the volume of crude oil transportation capacity, natural gas transportation and storage capacity, NGL transportation capacity, and water transportation, gathering and disposal capacity under firm fee contracts, as well as the volume of natural gas that we process and the fees assessed for such services.
Operating Costs and Expenses
The primary components of our operating costs and expenses that we evaluate include cost of sales, cost of transportation services, operations and maintenance and general and administrative costs. Our operating expenses are driven primarily by expenses related to the operation, maintenance and growth of our asset base.
Adjusted EBITDA and Distributable Cash Flow
Adjusted EBITDA and Distributable Cash Flow are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;
the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the returns on investment of various expansion and growth opportunities.
We believe that the presentation of Adjusted EBITDA and Distributable Cash Flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, nor should Adjusted EBITDA and Distributable Cash Flow be considered alternatives to available cash, operating surplus, distributions of available cash from operating surplus or other definitions in our partnership agreement. Adjusted EBITDA and Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and Distributable Cash Flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Non-GAAP Financial Measures
We generally define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments. We also use Distributable Cash Flow, which we generally define as Adjusted EBITDA, plus preferred distributions received from Pony Express in excess of its distributable cash flow attributable to our net interest and adjusted for deficiency payments received from or utilized by Pony Express shippers, less cash interest expense, maintenance capital expenditures, distributions to noncontrolling interests in excess of earnings allocated to noncontrolling interests, and certain cash reserves permitted by our partnership agreement, to analyze our performance. Maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements. As discussed in Note 2Summary of Significant Accounting Policies, prior to December 31, 2015, we received preferred distributions from Pony Express. Effective January 1, 2016 with our acquisition of an additional 31.3% membership interest in Pony Express, distributable cash flow from Pony Express is distributed pro rata based on ownership.
Pony Express collects deficiency payments for barrels committed by the customer to be transported in a month but not physically received for transport or delivered to the customers' agreed upon destination point. These deficiency payments are recorded as a deferred liability until the barrels are physically transported and delivered by TEP. Earnings at Pony Express prior to December 31, 2015 were allocated between TEP and noncontrolling interests in accordance with a substantive profit sharing arrangement rather than pro rata by ownership. Distributions made by Pony Express to its noncontrolling interests reduce the Distributable Cash Flow available to TEP.
Distributable Cash Flow and Adjusted EBITDA are not presentations made in accordance with GAAP. The following table presents a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities and a reconciliation of Distributable Cash Flow to net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated:
 
Three Months Ended March 31,
 
2016
 
2015
 
(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
 
 
 
Net income attributable to partners
$
44,070

 
$
32,319

Add:
 
 
 
Interest expense, net of noncontrolling interest
7,499

 
3,440

Depreciation and amortization expense, net of noncontrolling interest
21,967

 
20,533

Non-cash loss (gain) related to derivative instruments
8,990

 
(90
)
Non-cash compensation expense
1,166

 
1,527

Non-cash loss from asset sales

 
4,483

Less:
 
 
 
Non-cash loss allocated to noncontrolling interest

 
(9,377
)
Adjusted EBITDA
$
83,692

 
$
52,835

Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Cash Provided by Operating Activities
 
 
 
Net cash provided by operating activities
$
88,757

 
$
48,639

Add:
 
 
 
Interest expense, net of noncontrolling interest
7,499

 
3,440

Other, including changes in operating working capital
(12,564
)
 
756

Adjusted EBITDA
$
83,692

 
$
52,835

Add:
 
 
 
Pony Express deficiency payments received, net
7,157

 
292

Less:
 
 
 
Cash interest cost
(6,821
)
 
(3,031
)
Maintenance capital expenditures
(2,168
)
 
(1,511
)
Distributions to noncontrolling interest in excess of earnings

 
(2,103
)
Distributable Cash Flow
$
81,860

 
$
46,482

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,
 
2016
 
2015
 
(in thousands)
Reconciliation of Adjusted EBITDA to Operating Income in the Crude Oil Transportation & Logistics Segment (1)
 
 
 
Operating income
$
52,666

 
$
14,273

Add:
 
 
 
Depreciation and amortization expense, net of noncontrolling interest
12,918

 
11,233

Adjusted EBITDA attributable to noncontrolling interests
(1,043
)
 
9,377

Less:
 
 
 
Non-cash loss allocated to noncontrolling interest

 
(9,377
)
Segment Adjusted EBITDA
$
64,541

 
$
25,506

Reconciliation of Adjusted EBITDA to Operating Income in the Natural Gas Transportation & Logistics Segment (1)
 
 
 
Operating income
$
10,664

 
$
12,553

Add:
 
 
 
Depreciation and amortization expense
5,878

 
6,071

Non-cash loss (gain) related to derivative instruments
44

 
(90
)
Other income, net
566

 
712

Segment Adjusted EBITDA
$
17,152

 
$
19,246

Reconciliation of Adjusted EBITDA to Operating Income in the Processing & Logistics Segment (1)
 
 
 
Operating income
$
178

 
$
1,054

Add:
 
 
 
Depreciation and amortization expense, net of noncontrolling interest
3,171

 
3,229

Non-cash loss from asset sales

 
4,483

Adjusted EBITDA attributable to noncontrolling interests
2

 
(48
)
Segment Adjusted EBITDA
$
3,351

 
$
8,718

Total Segment Adjusted EBITDA
$
85,044

 
$
53,470

Corporate general and administrative costs
(1,352
)
 
(635
)
Total Adjusted EBITDA
$
83,692

 
$
52,835

(1) 
Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for the Crude Oil Transportation & Logistics, Natural Gas Transportation & Logistics, and Processing & Logistics segments. For reconciliations to the consolidated financial data, see Note 13Reporting Segments to the accompanying consolidated financial statements.

24



Results of Operations
The following provides a summary of our consolidated results of operations for the periods indicated:
 
Three Months Ended March 31,
 
2016
 
2015
 
(in thousands, except operating data)
Revenues:
 
 
 
Crude oil transportation services
$
94,572

 
$
50,381

Natural gas transportation services
29,280

 
32,148

Sales of natural gas, NGLs, and crude oil
13,926

 
21,869

Processing and other revenues
7,627

 
10,277

Total Revenues
145,405

 
114,675

Operating Costs and Expenses:
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
13,568

 
19,593

Cost of transportation services (exclusive of depreciation and amortization shown below)
16,156

 
10,715

Operations and maintenance
12,477

 
9,575

Depreciation and amortization
21,692

 
20,605

General and administrative
13,016

 
12,689

Taxes, other than income taxes
7,506

 
11,297

Loss on sale of assets

 
4,483

Total Operating Costs and Expenses
84,415

 
88,957

Operating Income
60,990

 
25,718

Other (Expense) Income:
 
 
 
Interest expense, net
(7,499
)
 
(3,440
)
Unrealized loss on derivative instrument
(8,946
)
 

Other income, net
566

 
712

Total Other Expense
(15,879
)
 
(2,728
)
Net income
45,111

 
22,990

Net (income) loss attributable to noncontrolling interests
(1,041
)
 
9,329

Net income attributable to partners
$
44,070

 
$
32,319

Other Financial Data: (1)
 
 
 
Adjusted EBITDA
$
83,692

 
$
52,835

Operating Data:
 
 
 
Crude oil transportation average throughput (Bbls/d) (2)
291,274

 
165,409

Gas transportation firm contracted capacity (MMcf/d)
1,485

 
1,609

Natural gas processing inlet volumes (MMcf/d)
98

 
145

(1) 
For more information regarding Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable GAAP measure, please see "Non-GAAP Financial Measures" above.
(2) 
Approximate average daily throughput for the three months ended March 31, 2015 is reflective of the volumetric ramp up due to commercial in-service of the Pony Express System beginning in October 2014 and delays in the construction and expansion efforts of third-party pipelines with which Pony Express shares joint tariffs.
Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015
Revenues. Total revenues were $145.4 million for the three months ended March 31, 2016, compared to $114.7 million for the three months ended March 31, 2015, which represents an increase of $30.7 million, or 27%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $44.2 million in the Crude Oil Transportation & Logistics segment, partially offset by decreased revenues of $10.8 million and $2.6 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, as discussed further below.

25



Operating costs and expenses. Operating costs and expenses were $84.4 million for the three months ended March 31, 2016 compared to $89.0 million for the three months ended March 31, 2015, which represents a decrease of $4.5 million, or 5%. The overall decrease in operating costs and expenses is primarily driven by decreased operating costs and expenses of $10.0 million and $0.7 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, partially offset by increased operating costs and expenses of $5.8 million in the Crude Oil Transportation & Logistics segment, as discussed further below.
Interest expense, net. Interest expense of $7.5 million for the three months ended March 31, 2016 was primarily composed of interest and fees associated with TEP's revolving credit facility. Interest expense of $3.4 million for the three months ended March 31, 2015 was primarily composed of interest and fees associated with TEP's revolving credit facility, partially offset by interest income of $0.4 million on the cash balance swept to TD under the Pony Express cash management agreement. The increase in interest and fees associated with TEP's revolving credit facility is primarily due to increased borrowings to fund a portion of our 2015 acquisitions and our recent acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016.
Unrealized loss on derivative instrument. Unrealized loss on derivative instrument of $8.9 million represents the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016. The call option grants TEP the right to repurchase the 6,518,000 common units issued to TD as a portion of the consideration for the acquisition at a price of $42.50.
Other income, net. Other income, net typically includes rental income, income earned from certain customers related to the capital costs we incurred to connect these customers to our system, and the allowance for funds used during construction at our regulated entities. Other income for the three months ended March 31, 2016 was $0.6 million compared to $0.7 million for the three months ended March 31, 2015.
Net (income) loss attributable to noncontrolling interests. Net income attributable to noncontrolling interests of $1.0 million for the three months ended March 31, 2016 primarily reflects the net income allocated to TD's 2% noncontrolling interest in Pony Express. Net loss attributable to noncontrolling interest of $9.3 million for the three months ended March 31, 2015 primarily reflects losses allocated to TD's 33.3% noncontrolling interest of Pony Express as a result of the income allocated to TEP as a result of the minimum quarterly preference payment received for the first quarter of 2015.
The following provides a summary of our Crude Oil Transportation & Logistics segment results of operations for the periods indicated:
Segment Financial Data - Crude Oil Transportation & Logistics (1)
Three Months Ended March 31,
2016
 
2015
 
(in thousands)
Revenues:
 
 
 
Crude Oil transportation services
$
94,572

 
$
50,381

Total revenues
94,572

 
50,381

Operating costs and expenses:
 
 
 
Cost of transportation services
14,495

 
8,709

Operations and maintenance
3,831

 
1,415

Depreciation and amortization
12,639

 
11,233

General and administrative
5,034

 
5,155

Taxes, other than income taxes
5,907

 
9,596

Total operating costs and expenses
41,906

 
36,108

Operating income
$
52,666

 
$
14,273

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

26



Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015
Revenues. Crude Oil Transportation & Logistics segment revenues were $94.6 million for the three months ended March 31, 2016, compared to $50.4 million for the three months ended March 31, 2015, which represents an increase of $44.2 million, or 88%, in segment revenues primarily due to $27.8 million of revenue from a full quarter of operations on the lateral in Northeast Colorado, which began commercial operations during the second quarter of 2015, and approximately $10.6 million related to the activation of one of our joint tariffs in the second quarter of 2015.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were $41.9 million for the three months ended March 31, 2016 compared to $36.1 million for the three months ended March 31, 2015, which represents an increase of $5.8 million, or 16%. The overall increase in operating costs and expenses was primarily driven by a $5.8 million increase in cost of transportation services, a $2.4 million increase in operations and maintenance costs, and a $1.4 million increase in depreciation and amortization, all primarily driven by the costs associated with a full quarter of operations on the lateral in Northeast Colorado, which began commercial operations during the second quarter of 2015. These increases were partially offset by a $3.7 million decrease in taxes, other than income taxes, due to lower property tax estimates for 2015 as a result of successful appeals with state taxing authorities on the assessed value of property, which lowered 2015 tax accruals beginning in the second quarter of 2015, partially offset by increased estimates for 2016 resulting from the lateral in Northeast Colorado that was placed into service during the second quarter of 2015.
The following provides a summary of our Natural Gas Transportation & Logistics segment results of operations for the periods indicated:
Segment Financial Data - Natural Gas Transportation & Logistics (1)
Three Months Ended March 31,
2016
 
2015
 
(in thousands)
Revenues:
 
 
 
Natural gas transportation services
$
30,635

 
$
33,494

Sales of natural gas, NGLs, and crude oil
348

 
105

Processing and other revenues
4

 
11

Total revenues
30,987

 
33,610

Operating costs and expenses:
 
 
 
Cost of sales
1,146

 
74

Cost of transportation services
2,455

 
3,316

Operations and maintenance
5,880

 
5,740

Depreciation and amortization
5,878

 
6,071

General and administrative
3,788

 
4,261

Taxes, other than income taxes
1,176

 
1,595

Total operating costs and expenses
20,323

 
21,057

Operating income
$
10,664

 
$
12,553

(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 13Reporting Segments to the accompanying condensed consolidated financial statements.
Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015
Revenues. Natural Gas Transportation & Logistics segment revenues were $31.0 million for the three months ended March 31, 2016, compared to $33.6 million for the three months ended March 31, 2015, which represents a decrease of $2.6 million, or 8%, in segment revenues as a result of a $2.9 million decrease in natural gas transportation services primarily driven by decreased prices on fuel reimbursements and warmer weather conditions that created less demand for short-term transportation capacity during the three months ended March 31, 2016 compared to the three months ended March 31, 2015.

27



Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $20.3 million for the three months ended March 31, 2016 compared to $21.1 million for the three months ended March 31, 2015, which represents a decrease of $0.7 million, or 3%. The overall decrease in operating costs and expenses was primarily driven by a $0.9 million decrease in cost of transportation services due to lower costs associated with fuel reimbursements as a result of decreased prices, a $0.5 million decrease in general and administrative costs due to a reduction in costs allocated to the segment, a $0.4 million decrease in taxes, other than income taxes, due to lower property tax estimates as a result of successful appeals with state taxing authorities on the assessed value of property, which lowered 2015 and 2016 tax accruals beginning in the second quarter of 2015. These decreases were partially offset by a $1.1 million increase in cost of sales due to increased volumes of natural gas sold, partially offset by a 31% decrease in natural gas prices.
The following provides a summary of our Processing & Logistics segment results of operations for the periods indicated:
Segment Financial Data - Processing & Logistics (1)
Three Months Ended March 31,
2016
 
2015
 
(in thousands)
Revenues:
 
 
 
Sales of natural gas, NGLs, and crude oil
$
13,578

 
$
21,764

Processing and other revenues
7,623

 
10,266

Total revenues
21,201

 
32,030

Operating costs and expenses:
 
 
 
Cost of sales
12,432

 
19,519

Cost of transportation services
551

 
36

Operations and maintenance
2,766

 
2,420

Depreciation and amortization
3,175

 
3,301

General and administrative
1,676

 
1,111

Taxes, other than income taxes
423

 
106

Loss on sale of assets

 
4,483

Total operating costs and expenses
21,023

 
30,976

Operating income
$
178

 
$
1,054

(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 13Reporting Segments to the accompanying condensed consolidated financial statements.
Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015
Revenues. Processing & Logistics segment revenues were $21.2 million for the three months ended March 31, 2016, compared to $32.0 million for the three months ended March 31, 2015, which represents a $10.8 million, or 34%, decrease in segment revenues. The decrease in segment revenues was primarily due to a $8.2 million decrease in the sales of natural gas, NGLs, and crude oil driven by lower NGL sales of $7.5 million due to a 27% decrease in NGL prices and lower volumes processed and lower natural gas sales of $0.7 million, a $2.6 million decrease in processing and other revenues driven by lower processing fees at TMID due to decreased volumes processed, and a $2.0 million decrease in fresh water transportation revenue at Water Solutions, partially offset by $1.4 million of salt water disposal revenue from BNN Western, LLC ("Western"), which was acquired on December 16, 2015.
Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $21.0 million for the three months ended March 31, 2016 compared to $31.0 million for the three months ended March 31, 2015, which represents a decrease of $10.0 million, or 32%. The decrease in operating costs and expenses was driven by a decrease of $7.1 million in cost of sales, primarily due to decreased NGL prices and volumes processed as discussed above, and a $4.5 million noncash loss recognized on the sale of compressor assets in 2015. These decreases were partially offset by a $0.6 million increase in general and administrative costs due to increased costs allocated to Water Solutions as a result of increased operating income, and a $0.5 million increase in cost of transportation services due to costs associated with Western.

28



Liquidity and Capital Resources Overview
Our primary sources of liquidity for the three months ended March 31, 2016 were borrowings under our revolving credit facility, cash generated from operations, and proceeds from the issuance of common units. We expect our sources of liquidity in the future to include:
cash generated from our operations;
borrowing capacity available under our revolving credit facility; and
future issuances of additional partnership units and/or debt securities.
We believe that cash on hand, cash generated from operations and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements and our planned cash distributions to unitholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of borrowings under our revolving credit facility and issuances of debt and/or equity securities.
Our total liquidity as of March 31, 2016 and December 31, 2015 was as follows:
 
March 31, 2016
 
December 31, 2015
 
(in thousands)
Cash on hand
$
2,885

 
$
1,611

 
 
 
 
Total capacity under the TEP revolving credit facility
1,500,000

 
1,100,000

Less: Outstanding borrowings under the TEP revolving credit facility
(1,200,000
)
 
(753,000
)
Available capacity under the TEP revolving credit facility
300,000

 
347,000

Total liquidity
$
302,885

 
$
348,611

Revolving Credit Facility
Effective January 4, 2016, in connection with the acquisition of an additional 31.3% membership interest in Pony Express, TEP exercised the committed accordion feature to increase the total capacity of the revolving credit facility from $1.1 billion to $1.5 billion. As discussed in "Recent Developments," effective May 6, 2016 we amended the revolving credit facility to increase the total capacity to $1.75 billion.
The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict our ability (as well as the ability of our restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of our business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, we are required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of March 31, 2016, we are in compliance with the covenants required under the revolving credit facility.
The unused portion of the revolving credit facility is subject to a commitment fee, which ranges from 0.300% to 0.500%, based on our total leverage ratio. As of March 31, 2016, the weighted average interest rate on outstanding borrowings was 2.20%. During the three months ended March 31, 2016, our weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 2.48%.
Equity Distribution Agreement
On October 31, 2014, we entered into an equity distribution agreement pursuant to which we may sell from time to time through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering price of up to $200 million. On May 13, 2015 the amount was subsequently amended to $100.2 million in order to account for follow-on equity offerings under our S-3 shelf registration statement. Sales of the common units, if any, will be made by means of ordinary brokers' transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by the Partnership and one or more of the managers. We intend to use the net cash proceeds from any sale of the units for general partnership purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
During the three months ended March 31, 2016, we issued and sold 337,311 common units with a weighted average sales price of $38.17 per unit under our equity distribution agreement for net cash proceeds of approximately $12.6 million (net of approximately $240,000 in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes. At March 31, 2016, approximately $83.1 million in aggregate offering price remained available to be issued and sold under the equity distribution agreement. Subsequent to March 31, 2016, we issued and sold an additional 2,180,681 common units with a weighted average sales price of $37.93 per unit under our equity distribution agreement for net cash proceeds of approximately $81.9 million (net of approximately $830,000 in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. While various other factors may impact our working capital requirements from period to period, our working capital requirements have typically been, and we expect will continue to be, driven by changes in accounts receivable and accounts payable. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, and the level of spending for capital expenditures. Changes in the market prices of energy commodities, primarily NGLs, that we buy and sell in the normal course of business can also impact the timing of changes in accounts receivable and accounts payable.
As of March 31, 2016, we had a working capital deficit of $16.6 million compared to a working capital deficit of $11.7 million at December 31, 2015, which represents a decrease in working capital of $4.9 million. The overall decrease in working capital was primarily attributable to the following:
an increase in deferred revenue of $7.3 million from deficiency payments collected by Pony Express;
an increase in accrued taxes of $5.6 million due to higher estimated property taxes for 2016 as a result of the Pony Express lateral in Northeast Colorado placed into service during the second quarter of 2015 and the Western assets acquired in December 2015; and
a decrease of $4.4 million in accounts receivable, due to a decrease in incremental barrels shipped at Pony Express in March 2016 compared to December 2015.
These working capital decreases were partially offset by:
a decrease of $4.4 million in accounts payable, primarily driven by the timing of project invoices and payment of contractor retainages related to the construction of the Pony Express lateral in Northeast Colorado;
a decrease of $3.5 million in accrued liabilities, primarily driven by employee short-term incentive payments during the three months ended March 31, 2016; and
a decrease of $3.4 million in accounts payable to related parties driven by the payment of balances due to TD as of December 31, 2015 to fund TEP's portion of expansion capital projects at Pony Express.
A material adverse change in operations, available financing under our revolving credit facility, or available financing from the equity or debt capital markets could impact our ability to fund our requirements for liquidity and capital resources in the future.
Cash Flows
The following table and discussion presents a summary of our cash flow for the periods indicated:
 
Three Months Ended March 31,
 
2016
 
2015
 
(in thousands)
Net cash provided by (used in):
 
 
 
Operating activities
$
88,757

 
$
48,639

Investing activities
$
(66,638
)
 
$
(713,611
)
Financing activities
$
(20,845
)
 
$
664,981


29



Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015
Operating Activities. Cash flows provided by operating activities were