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EX-32.2 - EXHIBIT 32.2 - Tallgrass Energy Partners, LPtep201763010qexhibit322.htm
EX-32.1 - EXHIBIT 32.1 - Tallgrass Energy Partners, LPtep201763010qexhibit321.htm
EX-31.2 - EXHIBIT 31.2 - Tallgrass Energy Partners, LPtep201763010qexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Tallgrass Energy Partners, LPtep201763010qexhibit311.htm
EX-12.1 - EXHIBIT 12.1 - Tallgrass Energy Partners, LPtep201763010qexhibit121.htm
EX-10.1 - EXHIBIT 10.1 - Tallgrass Energy Partners, LPtep201763010qexhibit101.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 June 30, 2017
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, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer", "accelerated filer", "smaller reporting company," and "emerging growth 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
 
¨
 
 
 
 
 
 
 
 
Emerging growth company
 
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨
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 August 2, 2017, the Registrant had 73,157,633 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 are directly tied 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: an 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: contracts or other arrangements, including tariff provisions, that 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 end users 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.
MDth: one thousand dekatherms.
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.
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: contracts or other arrangements, including tariff provisions, that 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)
 
June 30, 2017
 
December 31, 2016
 
(in thousands)
ASSETS
 
Current Assets:
 
 
 
Cash and cash equivalents
$
240

 
$
1,873

Accounts receivable, net
58,157

 
59,536

Gas imbalances
650

 
1,597

Inventories
11,241

 
13,093

Derivative assets
220

 
10,967

Prepayments and other current assets
7,153

 
7,628

Total Current Assets
77,661

 
94,694

Property, plant and equipment, net
2,232,754

 
2,079,232

Goodwill
343,288

 
343,288

Intangible asset, net
93,258

 
93,522

Unconsolidated investments
936,939

 
475,625

Deferred financing costs, net
13,064

 
4,815

Deferred charges and other assets
11,362

 
11,037

Total Assets
$
3,708,326

 
$
3,102,213

LIABILITIES AND EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts payable
$
24,227

 
$
24,122

Accounts payable to related parties
5,895

 
5,935

Gas imbalances
1,281

 
1,239

Derivative liabilities

 
556

Accrued taxes
17,246

 
16,996

Accrued liabilities
18,647

 
16,702

Deferred revenue
85,566

 
60,757

Other current liabilities
5,292

 
6,446

Total Current Liabilities
158,154

 
132,753

Long-term debt, net
2,087,568

 
1,407,981

Other long-term liabilities and deferred credits
17,200

 
7,063

Total Long-term Liabilities
2,104,768

 
1,415,044

Commitments and Contingencies

 

Equity:
 
 
 
Predecessor Equity

 
82,295

Limited partners (73,028,843 and 72,485,954 common units issued and outstanding at June 30, 2017 and December 31, 2016, respectively)
2,040,537

 
2,070,495

General partner (834,391 units issued and outstanding at June 30, 2017 and December 31, 2016)
(628,985
)
 
(632,339
)
Total Partners' Equity
1,411,552

 
1,520,451

Noncontrolling interests
33,852

 
33,965

Total Equity
1,445,404

 
1,554,416

Total Liabilities and Equity
$
3,708,326

 
$
3,102,213


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 June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands, except per unit amounts)
Revenues:
 
 
 
 
 
 
 
Crude oil transportation services
$
89,855

 
$
93,322

 
$
174,186

 
$
187,894

Natural gas transportation services
29,429

 
28,682

 
61,114

 
57,962

Sales of natural gas, NGLs, and crude oil
22,918

 
16,830

 
38,299

 
30,756

Processing and other revenues
18,661

 
10,181

 
31,664

 
19,571

Total Revenues
160,863

 
149,015

 
305,263

 
296,183

Operating Costs and Expenses:
 
 
 
 
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
19,386

 
15,958

 
31,756

 
29,526

Cost of transportation services (exclusive of depreciation and amortization shown below)
14,758

 
11,575

 
28,261

 
25,104

Operations and maintenance
15,254

 
14,270

 
28,157

 
27,228

Depreciation and amortization
22,091

 
21,890

 
43,494

 
43,897

General and administrative
14,774

 
14,322

 
28,437

 
27,812

Taxes, other than income taxes
6,912

 
5,783

 
15,138

 
13,433

Contract termination

 
8,061

 

 
8,061

Loss (gain) on disposal of assets
184

 
1,849

 
(1,264
)
 
1,849

Total Operating Costs and Expenses
93,359

 
93,708

 
173,979

 
176,910

Operating Income
67,504

 
55,307

 
131,284

 
119,273

Other Income (Expense):
 
 
 
 
 
 
 
Interest expense, net
(19,688
)
 
(9,233
)
 
(34,377
)
 
(16,732
)
Unrealized gain on derivative instrument

 
18,953

 
1,885

 
10,007

Equity in earnings of unconsolidated investments
42,741

 
24,022

 
63,479

 
24,731

Other income, net
272

 
221

 
342

 
787

Total Other Income (Expense)
23,325

 
33,963

 
31,329

 
18,793

Net income
90,829

 
89,270

 
162,613

 
138,066

Net income attributable to noncontrolling interests
(949
)
 
(1,110
)
 
(1,828
)
 
(2,151
)
Net income attributable to partners
$
89,880

 
$
88,160

 
$
160,785

 
$
135,915

Allocation of income to the limited partners:
 
 
 
 
 
 
 
Net income attributable to partners
$
89,880

 
$
88,160

 
$
160,785

 
$
135,915

Predecessor operations interest in net loss

 
3,888

 

 
203

General partner interest in net income
(37,301
)
 
(25,320
)
 
(67,884
)
 
(45,673
)
Net income available to common unitholders
52,579

 
66,728

 
92,901

 
90,445

Basic net income per common unit
$
0.72

 
$
0.93

 
$
1.28

 
$
1.30

Diluted net income per common unit
$
0.72

$
0.92

$
0.92

 
$
1.27

 
$
1.29

Basic average number of common units outstanding
72,618

 
71,975

 
72,581

 
69,471

Diluted average number of common units outstanding
73,062

 
72,925

 
72,972

 
70,360


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)
 
Six Months Ended June 30,
 
2017
 
2016
 
(in thousands)
Cash Flows from Operating Activities:
 
 
 
Net income
$
162,613

 
$
138,066

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
47,702

 
47,106

Equity in earnings of unconsolidated investments
(63,479
)
 
(24,731
)
Distributions from unconsolidated investments
63,374

 
24,636

Changes in components of working capital:
 
 
 
Accounts receivable and other
2,060

 
6,356

Accounts payable and accrued liabilities
3,520

 
6,155

Deferred revenue
24,593

 
16,174

Other current assets and liabilities
2,241

 
(1,837
)
Other operating, net
(773
)
 
(6,418
)
Net Cash Provided by Operating Activities
241,851

 
205,507

Cash Flows from Investing Activities:
 
 
 
Acquisition of Rockies Express membership interest
(400,000
)
 
(436,022
)
Acquisition of Terminals and NatGas
(140,000
)
 

Acquisition of Douglas Gathering System
(128,526
)
 

Capital expenditures
(53,995
)
 
(34,860
)
Distributions from unconsolidated investments in excess of cumulative earnings
27,308

 
6,335

Contributions to unconsolidated investments
(17,835
)
 
(14,450
)
Acquisition of Pony Express membership interest

 
(49,118
)
Other investing, net
(13,986
)
 
411

Net Cash Used in Investing Activities
(727,034
)
 
(527,704
)
Cash Flows from Financing Activities:
 
 
 
Proceeds from issuance of long-term debt
350,000

 

Borrowings under revolving credit facility, net
333,000

 
525,000

Distributions to unitholders
(179,525
)
 
(127,924
)
Proceeds from public offering, net of offering costs
112,762

 
261,770

Partial exercise of call option
(72,381
)
 

Repurchase of common units from TD
(35,335
)
 

Acquisition of Pony Express membership interest

 
(425,882
)
Proceeds from private placement, net of offering costs

 
90,009

Other financing, net
(24,971
)
 
(444
)
Net Cash Provided by Financing Activities
483,550

 
322,529

Net Change in Cash and Cash Equivalents
(1,633
)
 
332

Cash and Cash Equivalents, beginning of period
1,873

 
1,611

Cash and Cash Equivalents, end of period
$
240

 
$
1,943


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




TALLGRASS ENERGY PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)
 
Predecessor Equity
 
Limited Partners
 
General Partner
 
Total Partners’ Equity
 
Noncontrolling Interests
 
Total Equity
 
(in thousands)
Balance at January 1, 2017
$
82,295

 
$
2,070,495

 
$
(632,339
)
 
$
1,520,451

 
$
33,965

 
$
1,554,416

Net income

 
92,901

 
67,884

 
160,785

 
1,828

 
162,613

Issuance of units to public, net of offering costs

 
112,762

 

 
112,762

 

 
112,762

Distributions to unitholders

 
(119,279
)
 
(60,246
)
 
(179,525
)
 

 
(179,525
)
Noncash compensation expense

 
3,647

 

 
3,647

 

 
3,647

LTIP units tendered by employees to satisfy tax withholding obligations

 
(12,273
)
 

 
(12,273
)
 

 
(12,273
)
Partial exercise of call option

 
(72,381
)
 
(12,561
)
 
(84,942
)
 

 
(84,942
)
Repurchase of common units from TD

 
(35,335
)
 

 
(35,335
)
 

 
(35,335
)
Acquisition of Terminals and NatGas
(82,295
)
 

 
(57,705
)
 
(140,000
)
 

 
(140,000
)
Acquisition of additional 24.99% membership interest in Rockies Express

 

 
63,681

 
63,681

 

 
63,681

Contributions from TD

 

 
2,301

 
2,301

 

 
2,301

Contributions from noncontrolling interest

 

 

 

 
867

 
867

Distributions to noncontrolling interest

 

 

 

 
(2,808
)
 
(2,808
)
Balance at June 30, 2017
$

 
$
2,040,537

 
$
(628,985
)
 
$
1,411,552

 
$
33,852

 
$
1,445,404

 
 
 
 
 
 
 
 
 
 
 
 
 
Predecessor Equity
 
Limited Partners
 
General Partner
 
Total Partners’ Equity
 
Noncontrolling Interests
 
Total Equity
 
(in thousands)
Balance at January 1, 2016
$
71,564

 
$
1,618,766

 
$
(348,841
)
 
$
1,341,489

 
$
445,077

 
$
1,786,566

Net (loss) income
(203
)
 
90,445

 
45,673

 
135,915

 
2,151

 
138,066

Issuance of units to public, net of offering costs

 
261,770

 

 
261,770

 

 
261,770

Issuance of units in a private placement, net of offering costs

 
90,009

 

 
90,009

 

 
90,009

Distributions to unitholders

 
(91,222
)
 
(36,702
)
 
(127,924
)
 

 
(127,924
)
Noncash compensation expense

 
3,820

 

 
3,820

 

 
3,820

Contributions from noncontrolling interest

 

 

 

 
7,273

 
7,273

Distributions to noncontrolling interest

 

 

 

 
(3,290
)
 
(3,290
)
Acquisition of additional 31.3% membership interest in Pony Express

 
268,607

 
(279,967
)
 
(11,360
)
 
(417,679
)
 
(429,039
)
Distributions to Predecessor Entities, net
(2,530
)
 

 

 
(2,530
)
 

 
(2,530
)
Balance at June 30, 2016
$
68,831

 
$
2,242,195

 
$
(619,837
)
 
$
1,691,189

 
$
33,532

 
$
1,724,721



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. Our operations are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations. Our reportable business segments are:
Crude Oil Transportation & Logistics—the ownership and operation of a FERC-regulated crude oil pipeline system and crude oil storage and terminalling facilities;
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 gathering, 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.
Crude Oil Transportation & Logistics. 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 FERC-regulated crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma, which includes a lateral in Northeast Colorado commencing in Weld County, Colorado, and interconnecting with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We also provide crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals") acquired effective January 1, 2017, which owns and operates crude oil terminals near Sterling, Colorado (the "Sterling Terminal") and in Weld County, Colorado (the "Buckingham Terminal"). Terminals also owns a 69% membership interest in Deeprock Development, LLC ("Deeprock Development"), which owns a crude oil terminal in Cushing, Oklahoma (the "Cushing Terminal"), inclusive of an additional 49% membership interest in Deeprock Development acquired in July 2017 as discussed in Note 15 – Subsequent Events.
Natural Gas Transportation & Logistics. We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 49.99% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio (the "Rockies Express Pipeline"), inclusive of the additional 24.99% membership interest acquired from Tallgrass Development, LP ("TD") effective March 31, 2017 as discussed in Note 3 – Acquisitions, and our 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas") acquired effective January 1, 2017, which operates the Rockies Express Pipeline, (2) the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline").
Processing & Logistics. We provide services for customers in Wyoming through a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System") that was acquired on June 5, 2017, as discussed in Note 3 – Acquisitions, and 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 and Wyoming. We perform water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, and Wyoming through BNN Water Solutions, LLC ("Water Solutions").

5



The table below summarizes our equity ownership as of June 30, 2017:
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
 
47,409,625

 

 
64.92
%
 
64.18
%
Tallgrass Equity, LLC
 
20,000,000

 

 
27.39
%
 
27.08
%
Tallgrass Development, LP
 
5,619,218

 

 
7.69
%
 
7.61
%
Tallgrass MLP GP, LLC (1)
 

 
834,391

 
%
 
1.13
%
Total
 
73,028,843

 
834,391

 
100.00
%
 
100.00
%
(1) 
Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.
The term "Terminals Predecessor" refers to Terminals and the term "NatGas Predecessor" refers to NatGas prior to their acquisition by TEP on January 1, 2017. Terminals Predecessor and NatGas Predecessor are collectively referred to as the Predecessor Entities, as further discussed in Note 2 – Summary of Significant Accounting Policies. Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entities. Predecessor Equity as presented in the condensed consolidated financial statements represents the capital account activity of Terminals Predecessor and NatGas Predecessor prior to January 1, 2017. For additional information regarding these acquisitions, see Note 3 – Acquisitions.
2. Summary of Significant Accounting Policies
Basis of Presentation
These condensed consolidated financial statements and related notes for the three and six months ended June 30, 2017 and 2016 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America ("GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three and six months ended June 30, 2017 and 2016 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.
Our financial results for the three and six months ended June 30, 2017 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2017. 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, 2016 ("2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 15, 2017.
The condensed consolidated financial statements include the accounts of TEP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and noncontrolling interests in accordance with the respective ownership interests.
As further discussed in Note 3 – Acquisitions, TEP closed the acquisition of Terminals and NatGas effective January 1, 2017. As the acquisitions of Terminals and NatGas are considered transactions between entities under common control, and a change in reporting entity, the financial information presented has been recast to include Terminals and NatGas for all periods presented. Net equity distributions of the Predecessor Entities included in the condensed consolidated financial statements represent transfers of cash as a result of TD's centralized cash management system prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries of TD. These loans were then periodically recorded as equity distributions.
The accompanying condensed consolidated financial statements of TEP include historical cost-basis accounts of the assets and liabilities of the Predecessor Entities for the periods prior to January 1, 2017, the date TEP acquired Terminals and NatGas from TD, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. TEP and the Predecessor Entities are all considered "entities under common control" as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities have been recorded by TEP at historical cost.

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.
Accounting Pronouncement Recently Adopted
ASU No. 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business"
In January 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. The ASU also narrows the definition of the term "output" so that the term is consistent with how outputs are described under the revenue recognition guidance in Topic 606.
The amendments in ASU 2017-01 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2017. Early adoption is permitted in certain circumstances. We elected to adopt the guidance in ASU 2017-01 effective April 1, 2017, and as a result applied the new guidance to transactions completed during the three months ended June 30, 2017.
ASU No. 2017-04, "Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment"
In January 2017, the FASB issued ASU No. 2017-04, which simplifies the subsequent measurement of goodwill by eliminating "Step 2" from the goodwill impairment test, which involved calculating the implied fair value of goodwill by determining the fair value at the impairment testing date of a reporting unit's assets and liabilities. Instead, under the simplified test approach, an entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.
The amendments in ASU 2017-04 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We elected to adopt the guidance in ASU 2017-04 effective April 1, 2017, and as a result will apply the new guidance to our annual goodwill impairment tests to be performed as of August 31, 2017.
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 adopted the guidance in ASU 2016-09 effective January 1, 2017 and made a policy election to account for forfeitures when they occur. The adoption of ASU 2016-09 did not have a material impact on our consolidated financial statements.

7



Accounting Pronouncements Not Yet Adopted
Revenue Recognition
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.
Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers.
The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 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 our pending adoption of the revised guidance. The status of our implementation is as follows:
We have formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain revenue contract types, and project status.
We are currently reviewing contracts for each revenue stream identified within each of our business segments. Through this process, we are determining and documenting expected changes in revenue recognition upon adoption of the revised guidance.
We plan to evaluate the potential information technology and internal control changes that will be required for adoption based on the findings from our contract review process.
We plan to provide internal training and awareness related to the revised guidance to the key stakeholders throughout our organization.
While we have tentatively concluded that the implementation of ASU 2014-09 will not have a material impact on our revenue recognition policies for a substantial number of our contracts, management has identified several areas of potential impact through the contract review process currently underway, including the accounting for non-cash consideration, particularly in our Crude Oil Transportation & Logistics and Processing & Logistics segments, and the timing of revenue recognition with respect to deficiency payments received in our Crude Oil Transportation & Logistics segment. We are currently working with an industry group to develop positions regarding these outstanding items. We are in the process of quantifying the impact of adoption, but we cannot reasonably estimate the full impact of the standard until the industry reaches consensus on these issues. We do anticipate significant changes to our disclosures based on the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities. Additionally, we are currently evaluating our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance.
We will continue to conduct our contract review process throughout 2017 and, as a result, additional areas of impact may be identified. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to equity. Consolidated revenues presented in our comparative financial statements for periods prior to January 1, 2018 would not be revised.

8



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.
3. Acquisitions
Acquisition of DCP Douglas, LLC
On May 17, 2017, TEP, through its wholly-owned subsidiary Tallgrass Midstream, LLC (“TMID”), entered into a Membership Interest Purchase Agreement with DCP Assets Holding, LP to acquire 100% of the membership interests in DCP Douglas, LLC, which owns the Douglas Gathering System, a natural gas gathering system in the Powder River Basin with approximately 1,500 miles of gathering pipeline connected to TMID's Douglas processing plant, for approximately $128.5 million, subject to working capital adjustments. The acquisition closed on June 5, 2017 and has been accounted for as an asset acquisition, with substantially all of the fair value allocated to the long-lived assets acquired based on their relative fair values.
Acquisition of an Additional 24.99% Membership Interest in Rockies Express
On March 31, 2017, TEP, TD, and Rockies Express Holdings, LLC, entered into a definitive Purchase and Sale Agreement, pursuant to which TEP acquired an additional 24.99% membership interest in Rockies Express from TD in exchange for cash consideration of $400 million. Together with the 25% membership interest in Rockies Express that TEP acquired from a unit of Sempra U.S. Gas and Power on May 6, 2016, this transaction increases TEP’s aggregate membership interest in Rockies Express to 49.99%.
The transfer of the Rockies Express membership interest between TD and the Partnership is considered a transaction between entities under common control, but does not represent a change in reporting entity. Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our condensed consolidated balance sheets. As a result of the common control nature of the transaction, the 24.99% membership interest in Rockies Express was transferred to the Partnership at TD's historical carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the investment and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD. For additional information, see Note 7 – Investments in Unconsolidated Affiliates.
As of March 31, 2017, the negative basis difference carried over from TD was approximately $386.8 million. The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years, which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. The basis difference associated with the recently acquired 24.99% membership interest in Rockies Express at June 30, 2017 was allocated as follows:
 
Basis Difference
 
Amortization Period
 
(in thousands)
 
 
Long-term debt
$
19,291

 
2 - 25 years
Property, plant and equipment
(402,984
)
 
35 years
Total basis difference
$
(383,693
)
 
 
Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC    
Effective January 1, 2017, we acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $140 million. These acquisitions are considered transactions between entities under common control, and a change in reporting entity.

9



Terminals owns several fully operational assets providing storage capacity and additional injection points for the Pony Express System, including the Sterling Terminal near Sterling, Colorado, the Buckingham Terminal in northeast Colorado, and a 20% interest in the Deeprock Development Terminal in Cushing, Oklahoma. Our 20% membership interest in Deeprock Development as of June 30, 2017 and December 31, 2016 is recorded under the equity method of accounting and reported as "Unconsolidated investments" on our condensed consolidated balance sheets. As discussed in Note 15 – Subsequent Events, Terminals acquired an additional 49% membership interest in Deeprock Development in July 2017. Terminals also owns acreage in Cushing, Oklahoma and Guernsey, Wyoming, which is under development to provide additional storage capacity, and other potential opportunities.
NatGas is the operator of the Rockies Express Pipeline and receives a fee from Rockies Express as compensation for its services.

10



Historical Financial Information
The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016. The following table presents our previously reported December 31, 2016 condensed consolidated balance sheet, adjusted for the acquisitions of Terminals and NatGas:
 
December 31, 2016
 
TEP (As previously reported)
 
Consolidate Terminals
 
Consolidate NatGas
 
TEP (As currently reported)
 
(in thousands)
ASSETS
 
 
 
 
 
Current Assets:
 
 
 
 
 
 
 
Cash and cash equivalents
$
1,873

 
$

 
$

 
$
1,873

Accounts receivable, net
59,469

 
38

 
29

 
59,536

Gas imbalances
1,597

 

 

 
1,597

Inventories
12,805

 
288

 

 
13,093

Derivative assets
10,967

 

 

 
10,967

Prepayments and other current assets
6,820

 
808

 

 
7,628

Total Current Assets
93,531

 
1,134

 
29

 
94,694

Property, plant and equipment, net
2,012,263

 
66,969

 

 
2,079,232

Goodwill
343,288

 

 

 
343,288

Intangible asset, net
93,522

 

 

 
93,522

Unconsolidated investments
461,915

 
13,710

 

 
475,625

Deferred financing costs, net
4,815

 

 

 
4,815

Deferred charges and other assets
9,637

 
1,400

 

 
11,037

Total Assets
$
3,018,971

 
$
83,213

 
$
29

 
$
3,102,213

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current Liabilities:
 
 
 
 
 
 
 
Accounts payable
$
24,076

 
$
46

 
$

 
$
24,122

Accounts payable to related parties
5,879

 
56

 

 
5,935

Gas imbalances
1,239

 

 

 
1,239

Derivative liabilities
556

 

 

 
556

Accrued taxes
16,328

 
668

 

 
16,996

Accrued liabilities
16,525

 
177

 

 
16,702

Deferred revenue
60,757

 

 

 
60,757

Other current liabilities
6,446

 

 

 
6,446

Total Current Liabilities
131,806

 
947

 

 
132,753

Long-term debt, net
1,407,981

 

 

 
1,407,981

Other long-term liabilities and deferred credits
7,063

 

 

 
7,063

Total Long-term Liabilities
1,415,044

 

 

 
1,415,044

Equity:
 
 
 
 
 
 
 
Net Equity
1,472,121

 
82,266

 
29

 
1,554,416

Total Equity
1,472,121

 
82,266

 
29

 
1,554,416

Total Liabilities and Equity
$
3,018,971

 
$
83,213

 
$
29

 
$
3,102,213


11



The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated statements of income for the three and six months ended June 30, 2017 and 2016. The following tables present the previously reported condensed consolidated statements of income for the three and six months ended June 30, 2016, adjusted for the acquisitions of Terminals and NatGas:
 
Three Months Ended June 30, 2016
 
TEP (As previously reported)
 
Consolidate Terminals
 
Consolidate NatGas
 
Elimination (1)
 
TEP (As currently reported)
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
Crude oil transportation services
$
93,322

 
$

 
$

 
$

 
$
93,322

Natural gas transportation services
28,682

 

 

 

 
28,682

Sales of natural gas, NGLs, and crude oil
16,830

 

 

 

 
16,830

Processing and other revenues
8,097

 
2,957

 
1,992

 
(2,865
)
 
10,181

Total Revenues
146,931

 
2,957

 
1,992

 
(2,865
)
 
149,015

Operating Costs and Expenses:
 
 
 
 
 
 
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
15,958

 

 

 

 
15,958

Cost of transportation services (exclusive of depreciation and amortization shown below)
14,240

 
200

 

 
(2,865
)
 
11,575

Operations and maintenance
13,864

 
406

 

 

 
14,270

Depreciation and amortization
21,576

 
314

 

 

 
21,890

General and administrative
13,909

 
413

 

 

 
14,322

Taxes, other than income taxes
5,639

 
144

 

 

 
5,783

Contract termination

 
8,061

(2) 

 

 
8,061

Loss on disposal of assets
1,849

 

 

 

 
1,849

Total Operating Costs and Expenses
87,035

 
9,538

 

 
(2,865
)
 
93,708

Operating Income (Loss)
59,896

 
(6,581
)
 
1,992

 

 
55,307

Other Income (Expense):
 
 
 
 
 
 
 
 
 
Interest expense, net
(9,233
)
 

 

 

 
(9,233
)
Unrealized gain on derivative instrument
18,953

 

 

 

 
18,953

Equity in earnings of unconsolidated investments
23,321

 
701

 

 

 
24,022

Other income, net
221

 

 

 

 
221

Total Other Income
33,262

 
701

 

 

 
33,963

Net income (loss)
93,158

 
(5,880
)
 
1,992

 

 
89,270

Net income attributable to noncontrolling interests
(1,110
)
 

 

 

 
(1,110
)
Net income (loss) attributable to partners
$
92,048

 
$
(5,880
)
 
$
1,992

 
$

 
$
88,160


12



 
Six Months Ended June 30, 2016
 
TEP (As previously reported)
 
Consolidate Terminals
 
Consolidate NatGas
 
Elimination (1)
 
TEP (As currently reported)
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
Crude oil transportation services
$
187,894

 
$

 
$

 
$

 
$
187,894

Natural gas transportation services
57,962

 

 

 

 
57,962

Sales of natural gas, NGLs, and crude oil
30,756

 

 

 

 
30,756

Processing and other revenues
15,724

 
5,866

 
3,673

 
(5,692
)
 
19,571

Total Revenues
292,336

 
5,866

 
3,673

 
(5,692
)
 
296,183

Operating Costs and Expenses:
 
 
 
 
 
 
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
29,526

 

 

 

 
29,526

Cost of transportation services (exclusive of depreciation and amortization shown below)
30,396

 
400

 

 
(5,692
)
 
25,104

Operations and maintenance
26,341

 
887

 

 

 
27,228

Depreciation and amortization
43,268

 
629

 

 

 
43,897

General and administrative
26,925

 
887

 

 

 
27,812

Taxes, other than income taxes
13,145

 
288

 

 

 
13,433

Contract termination

 
8,061

(2) 

 

 
8,061

Loss on disposal of assets
1,849

 

 

 

 
1,849

Total Operating Costs and Expenses
171,450

 
11,152

 

 
(5,692
)
 
176,910

Operating Income (Loss)
120,886

 
(5,286
)
 
3,673

 

 
119,273

Other Income (Expense):
 
 
 
 
 
 
 
 
 
Interest expense, net
(16,732
)
 

 

 

 
(16,732
)
Unrealized gain on derivative instrument
10,007

 

 

 

 
10,007

Equity in earnings of unconsolidated investments
23,321

 
1,410

 

 

 
24,731

Other income, net
787

 

 

 

 
787

Total Other Income
17,383

 
1,410

 

 

 
18,793

Net income (loss)
138,269

 
(3,876
)
 
3,673

 

 
138,066

Net income attributable to noncontrolling interests
(2,151
)
 

 

 

 
(2,151
)
Net income (loss) attributable to partners
$
136,118

 
$
(3,876
)
 
$
3,673

 
$

 
$
135,915

(1) 
Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal facilities by Pony Express.
(2) 
Represents a one-time charge related to the termination of an operating agreement at the Sterling Terminal.
4. Related Party Transactions
As a result of our relationship with TD and its affiliates, we have entered into a number of related party transactions. The following disclosure includes those related party transactions which are not otherwise disclosed in these notes to our condensed consolidated financial statements.

13



We have no employees. In connection with the closing of our initial public offering on May 17, 2013, TEP and its general partner entered into an Omnibus Agreement with TD and certain of its affiliates, including Tallgrass Operations, LLC (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.
Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Cost of transportation services (1)
$
4,907

 
$
4,829

 
$
9,414

 
$
9,258

Charges to TEP: (2)
 
 
 
 
 
 
 
Property, plant and equipment, net
$
510

 
$
649

 
$
803

 
$
1,567

Operations and maintenance
$
7,430

 
$
6,373

 
$
13,707

 
$
12,557

General and administrative
$
10,935

 
$
10,439

 
$
20,312

 
$
19,651

(1) 
Reflects rent expense for the crude oil storage at the Deeprock Terminal.
(2) 
Charges to TEP 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:
 
June 30, 2017
 
December 31, 2016
 
(in thousands)
Receivable from related parties:
 
 
 
Rockies Express Pipeline LLC
$
1,029

 
$
590

Total receivable from related parties
$
1,029

 
$
590

Accounts payable to related parties:
 
 
 
Tallgrass Operations, LLC
$
5,817

 
$
5,854

Tallgrass Equity, LLC
78

 
68

Deeprock Development, LLC

 
13

Total accounts payable to related parties
$
5,895

 
$
5,935

Gas imbalances with affiliated shippers are as follows:
 
June 30, 2017
 
December 31, 2016
 
(in thousands)
Affiliate gas imbalance receivables
$

 
$
177

Affiliate gas imbalance payables
$
205

 
$


14



5. Inventory
The components of inventory at June 30, 2017 and December 31, 2016 consisted of the following:
 
June 30, 2017
 
December 31, 2016
 
(in thousands)
Crude oil
$
2,909

 
$
5,462

Materials and supplies
6,366

 
6,383

Natural gas liquids
413

 
265

Gas in underground storage
1,553

 
983

Total inventory
$
11,241

 
$
13,093

6. Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
 
June 30, 2017
 
December 31, 2016
 
(in thousands)
Crude oil pipelines
$
1,218,337

 
$
1,202,125

Natural gas pipelines
572,749

 
572,150

Gathering, processing and treating assets (1)
401,186

 
256,901

General and other
253,508

 
223,310

Construction work in progress
22,513

 
20,606

Accumulated depreciation and amortization
(235,539
)
 
(195,860
)
Total property, plant and equipment, net
$
2,232,754

 
$
2,079,232

(1) 
Includes approximately $138.2 million of assets associated with the Douglas Gathering System acquired in June 2017.
7. Investments in Unconsolidated Affiliates
Rockies Express
Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our condensed consolidated balance sheets. During the six months ended June 30, 2017, we recognized equity in earnings associated with our 49.99% membership interest in Rockies Express of $62.1 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $89.4 million and $17.8 million, respectively. As discussed in Note 3 – Acquisitions, we acquired an additional 24.99% membership interest in Rockies Express from TD on March 31, 2017.
Summarized financial information for Rockies Express is as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Revenue
$
207,149

 
$
175,350

 
$
408,487

 
$
391,902

Operating income
$
112,703

 
$
85,352

 
$
220,072

 
$
201,411

Net income to Members
$
70,945

 
$
112,728

 
$
137,195

 
$
192,663

8. Risk Management
We occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.

15



Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets:
 
Balance Sheet
Location
 
June 30, 2017
 
December 31, 2016
 
 
 
(in thousands)
Crude oil derivative contracts (1)
Current assets
 
$
207

 
$

Natural gas derivative contracts (2)
Current assets
 
$
13

 
$
291

Call option derivative (3)
Current assets
 
$

 
$
10,676

Crude oil derivative contracts (1)
Current liabilities
 
$

 
$
440

Natural gas derivative contracts (2)
Current liabilities
 
$

 
$
116

(1) 
The fair value shown for crude oil derivative contracts represents the sale of 30,000 barrels and 125,000 barrels of crude oil as of June 30, 2017 and December 31, 2016, respectively, which will settle throughout 2017.
(2) 
As of June 30, 2017, the fair value shown for natural gas derivative contracts was comprised of derivative volumes for long natural gas fixed-price swaps totaling 0.2 Bcf. As of December 31, 2016, the fair value shown for natural gas derivative contracts was comprised of derivative volumes for short and long natural gas fixed-price swaps totaling 0.3 Bcf and 0.4 Bcf, respectively.
(3) 
As discussed below, in conjunction with our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option covering the 6,518,000 common units issued to TD. As of February 1, 2017, no common units remained subject to the call option.
Effect of Derivative Contracts in the Statements of Income
The following table summarizes the impact of derivative contracts not designated as hedging contracts for the three and six months ended June 30, 2017 and 2016:
Contract Type
 
Location of gain (loss) recognized
in income on derivatives
 
Amount of gain (loss) recognized in income on derivatives
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
 
 
 
(in thousands)
Crude oil derivative contracts
 
Sales of natural gas, NGLs, and crude oil
 
$
227

 
$
148

 
$
890

 
$
148

Natural gas derivative contracts
 
Sales of natural gas, NGLs, and crude oil
 
$
(67
)
 
$
(307
)
 
$
106

 
$
(351
)
Call option derivative
 
Unrealized gain on derivative instrument
 
$

 
$
18,953

 
$
1,885

 
$
10,007

Call Option Derivative
As part of our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option at an exercise price of $42.50 per common unit covering the 6,518,000 common units issued to TD as a portion of the consideration. In July 2016 and October 2016, we partially exercised the call option covering 3,563,146 and 1,251,760 common units, respectively, for cash payments of $151.4 million and $53.2 million, respectively. On February 1, 2017, we exercised the remainder of the call option covering an additional 1,703,094 common units for a cash payment of $72.4 million. These common units were deemed canceled upon the exercise of the call option and as of the applicable exercise date were no longer issued and outstanding.
Credit Risk
We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our crude oil and natural gas derivatives consist of major financial institutions. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. The counterparty to our call option derivative was TD.

16



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. The maximum potential exposure to credit losses on our crude oil and natural gas derivative contracts at June 30, 2017 was:
 
Asset Position
 
(in thousands)
Gross
$
220

Netting agreement impact

Cash collateral held

Net exposure
$
220

As of June 30, 2017 and December 31, 2016, 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 our commodity derivative contracts nor did we have any margin deposits with counterparties associated with our commodity derivative contracts.
Fair Value
Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). OTC commodity derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. The call option granted by TD was 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 was classified within Level 2 of the fair value hierarchy as the value was based on significant observable inputs.

17



The following table summarizes the fair value measurements of our derivative contracts as of June 30, 2017 and December 31, 2016 based on the fair value hierarchy:
 
 
 
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 June 30, 2017:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
207

 
$

 
$
207

 
$

Natural gas derivative contracts
$
13

 
$

 
$
13

 
$

As of December 31, 2016:
 
 
 
 
 
 
 
Call option derivative
$
10,676

 
$

 
$
10,676

 
$

Natural gas derivative contracts
$
291

 
$

 
$
291

 
$

 
 
 
 
 
 
 
 
 
 
 
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 December 31, 2016:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
440

 
$

 
$
440

 
$

Natural gas derivative contracts
$
116

 
$

 
$
116

 
$

9. Long-term Debt
Long-term debt consisted of the following at June 30, 2017 and December 31, 2016:
 
June 30, 2017
 
December 31, 2016
 
(in thousands)
Revolving credit facility
$
1,348,000

 
$
1,015,000

5.50% senior notes due September 15, 2024
750,000

 
400,000

Less: Deferred financing costs, net (1)
(10,432
)
 
(7,019
)
Total long-term debt, net
$
2,087,568

 
$
1,407,981

(1) 
Deferred financing costs, net as presented above relate solely to the 2024 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our condensed consolidated balance sheets.
Senior Unsecured Notes
On September 1, 2016, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the "Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). On May 16, 2017, the Issuers issued an additional $350 million in aggregate principal amount of the 2024 Notes which are also governed by the Indenture. The notes issued on September 1, 2016 and May 16, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date, offering price and first interest payment date. 

18



The Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. As of June 30, 2017, we are in compliance with the covenants required under the 2024 Notes.
Revolving Credit Facility
On June 2, 2017, TEP entered into a $1.75 billion Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent and collateral agent, and a syndicate of lenders (the "Amended Credit Agreement"). The Amended Credit Agreement amends and restates TEP's existing revolving credit facility. The Amended Credit Agreement, among other things, extends the maturity date of TEP's existing revolving credit facility from May 13, 2018 to June 2, 2022, and provides for an uncommitted accordion in an amount up to an additional $250 million, subject to the satisfaction of certain other conditions. In addition, the revolving credit facility includes a $60 million sublimit for swing line loans and a $75 million sublimit for letters of credit.
The following table sets forth the available borrowing capacity under the revolving credit facility as of June 30, 2017 and December 31, 2016:
 
June 30, 2017
 
December 31, 2016
 
(in thousands)
Total capacity under the revolving credit facility
$
1,750,000

 
$
1,750,000

Less: Outstanding borrowings under the revolving credit facility
(1,348,000
)
 
(1,015,000
)
Less: Letters of credit issued under the revolving credit facility
(60
)
 

Available capacity under the revolving credit facility
$
401,940

 
$
735,000

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 therefrom, 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 5.00 to 1.00 (which will be increased to 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions), a consolidated senior secured leverage ratio of not more than 3.75 to 1.00 and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of June 30, 2017, 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 0.250% to 0.500%, based on our total leverage ratio. As of June 30, 2017, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 2.92%. During the six months ended June 30, 2017, our weighted average effective interest rate, including the interest on outstanding borrowings under the revolving credit facility, commitment fees, and amortization of deferred financing costs, was 3.17%.

19



Fair Value
The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016, but for which fair value is disclosed:
 
Fair Value
 
 
 
Quoted prices
in active markets
for identical assets
(Level 1)
 
Significant
other observable
inputs
(Level 2)
 
Significant
unobservable
inputs
(Level 3)
 
Total
 
Carrying
Amount
 
(in thousands)
As of June 30, 2017:
 
 
 
 
 
 
 
 
 
Revolving credit facility
$

 
$
1,348,000

 
$

 
$
1,348,000

 
$
1,348,000

2024 Notes
$

 
$
763,695

 
$

 
$
763,695

 
$
739,568

As of December 31, 2016:
 
 
 
 
 
 
 
 
 
Revolving credit facility
$

 
$
1,015,000

 
$

 
$
1,015,000

 
$
1,015,000

2024 Notes
$

 
$
398,000

 
$

 
$
398,000

 
$
392,981

The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of June 30, 2017 and December 31, 2016, the fair value of borrowings under the revolving credit facility approximates the carrying amount of the borrowings using a discounted cash flow analysis. The 2024 Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 Notes is based upon quoted market prices adjusted for illiquid markets. We are not aware of any factors that would significantly affect the estimated fair value subsequent to June 30, 2017.
10. Partnership Equity and Distributions
Equity Distribution Agreements
As of June 30, 2017, we had active equity distribution agreements 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 $100.2 million and $657.5 million. Net cash proceeds from any sale of the common units may be used for general partnership purposes, which includes, among other things, the Partnership's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with the Partnership's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital.
During the six months ended June 30, 2017, we issued and sold 2,341,061 common units with a weighted average sales price of $48.82 per unit under our equity distribution agreements for net cash proceeds of approximately $112.8 million (net of approximately $1.5 million in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as described above.
Repurchase of Common Units Owned by TD
Following an offer received from TD with respect to common units owned by TD not subject to the call option, we repurchased 736,262 common units from TD at an aggregate price of approximately $35.3 million, or $47.99 per common unit, on February 1, 2017, which was approved by the conflicts committee of the board of directors of our general partner. These common units were deemed canceled upon our purchase and as of such transaction date were no longer issued and outstanding.

20



Distributions to Holders of Common Units, General Partner Units and Incentive Distribution Rights
The following table shows the distributions for the periods indicated:
 
 
 
 
Distributions
 
 
 
 
 
 
Limited Partner
Common Units
 
General Partner
 
 
 
Distributions
per Limited
Partner Common Unit
Three Months Ended
 
Date Paid
 
Incentive Distribution Rights
 
General Partner Units
 
Total
 
 
 
 
 
(in thousands, except per unit amounts)
 
 
June 30, 2017
 
August 14, 2017 (1)
 
$
67,671

 
$
36,342

 
$
1,186

 
$
105,199

 
$
0.9250

March 31, 2017
 
May 15, 2017
 
60,486

 
29,840

 
1,040

 
91,366

 
0.8350

December 31, 2016
 
February 14, 2017
 
58,793

 
28,358

 
1,008

 
88,159

 
0.8150

September 30, 2016
 
November 14, 2016
 
57,332

 
26,987

 
976

 
85,295

 
0.7950

June 30, 2016
 
August 12, 2016
 
54,442