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EX-32.2 - EXHIBIT 32.2 - Tallgrass Energy, LPtegp201793010qexhibit322.htm
EX-32.1 - EXHIBIT 32.1 - Tallgrass Energy, LPtegp201793010qexhibit321.htm
EX-31.2 - EXHIBIT 31.2 - Tallgrass Energy, LPtegp201793010qexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Tallgrass Energy, LPtegp201793010qexhibit311.htm
EX-10.1 - EXHIBIT 10.1 - Tallgrass Energy, LPtegp201793010qexhibit101.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 September 30, 2017
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-37365
 
 
 
 
 Tallgrass Energy GP, LP
(Exact name of registrant as specified in its charter)
 
 
 
Delaware
 
 
 
46-3159268
(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 November 2, 2017, the Registrant had 58,075,000 Class A shares and 99,154,440 Class B shares outstanding.




TALLGRASS ENERGY GP, 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 GP, LP
CONDENSED CONSOLIDATED BALANCE SHEETS 
(UNAUDITED)
 
September 30, 2017
 
December 31, 2016
 
(in thousands)
ASSETS
 
Current Assets:
 
 
 
Cash and cash equivalents
$
3,279

 
$
2,459

Accounts receivable, net
95,629

 
59,536

Gas imbalances
1,020

 
1,597

Inventories
10,173

 
13,093

Derivative assets

 
10,967

Prepayments and other current assets
3,407

 
7,628

Total Current Assets
113,508

 
95,280

Property, plant and equipment, net
2,350,830

 
2,079,232

Goodwill
404,838

 
343,288

Intangible assets, net
98,876

 
93,522

Unconsolidated investments
922,280

 
475,625

Deferred tax asset
496,472

 
521,454

Deferred financing costs, net
13,326

 
6,042

Deferred charges and other assets
3,016

 
11,037

Total Assets
$
4,403,146

 
$
3,625,480

LIABILITIES AND EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts payable
$
69,620

 
$
24,449

Accounts payable to related parties
5,955

 
5,824

Gas imbalances
1,119

 
1,239

Derivative liabilities
473

 
556

Accrued taxes
22,890

 
16,996

Accrued liabilities
11,183

 
16,755

Deferred revenue
87,979

 
60,757

Other current liabilities
6,690

 
6,446

Total Current Liabilities
205,909

 
133,022

Long-term debt, net
2,261,086

 
1,555,981

Other long-term liabilities and deferred credits
18,396

 
7,063

Total Long-term Liabilities
2,279,482

 
1,563,044

Commitments and Contingencies

 

Equity:
 
 
 
Class A Shareholders (58,075,000 shares outstanding at September 30, 2017 and December 31, 2016)
234,241

 
250,967

Class B Shareholders (99,154,440 shares outstanding at September 30, 2017 and December 31, 2016)

 

Predecessor Equity

 
82,295

Total Partners' Equity
234,241

 
333,262

Noncontrolling interests
1,683,514

 
1,596,152

Total Equity
1,917,755

 
1,929,414

Total Liabilities and Equity
$
4,403,146

 
$
3,625,480


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



TALLGRASS ENERGY GP, LP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands, except per unit amounts)
Revenues:
 
 
 
 
 
 
 
Crude oil transportation services
$
86,180

 
$
91,387

 
$
260,366

 
$
279,281

Natural gas transportation services
30,256

 
31,444

 
91,370

 
89,406

Sales of natural gas, NGLs, and crude oil
32,215

 
20,487

 
70,514

 
51,243

Processing and other revenues
27,218

 
9,950

 
58,882

 
29,521

Total Revenues
175,869


153,268


481,132


449,451

Operating Costs and Expenses:
 
 
 
 
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
26,984

 
18,319

 
58,740

 
47,845

Cost of transportation services (exclusive of depreciation and amortization shown below)
10,538

 
10,842

 
38,799

 
35,946

Operations and maintenance
17,412

 
15,146

 
45,569

 
42,374

Depreciation and amortization
23,782

 
21,177

 
67,276

 
65,074

General and administrative
16,489

 
13,981

 
46,040

 
42,863

Taxes, other than income taxes
6,661

 
6,860

 
21,799

 
20,293

Contract termination

 

 

 
8,061

(Gain) loss on disposal of assets

 

 
(1,264
)
 
1,849

Total Operating Costs and Expenses
101,866


86,325


276,959


264,305

Operating Income
74,003


66,943


204,173


185,146

Other Income (Expense):
 
 
 
 
 
 
 
Interest expense, net
(24,408
)
 
(12,157
)
 
(61,539
)
 
(31,275
)
Unrealized (loss) gain on derivative instrument

 
(4,419
)
 
1,885

 
5,588

Equity in earnings of unconsolidated investments
123,642

 
12,764

 
187,121

 
37,495

Gain on remeasurement of unconsolidated investment
9,728

 

 
9,728

 

Other income, net
454

 
480

 
796

 
1,267

Total Other Income (Expense)
109,416


(3,332
)

137,991


13,075

Net income before tax
183,419


63,611


342,164


198,221

Deferred income tax expense
(12,642
)
 
(3,209
)
 
(24,982
)
 
(12,792
)
Net income
170,777


60,402


317,182


185,429

Net income attributable to noncontrolling interests
(154,911
)
 
(49,750
)
 
(280,534
)
 
(163,943
)
Net income attributable to TEGP
$
15,866


$
10,652


$
36,648


$
21,486

Allocation of income:
 
 
 
 
 
 
 
Net income attributable to TEGP
$
15,866


$
10,652


$
36,648


$
21,486

Predecessor operations interest in net income

 
(3,611
)
 

 
(3,408
)
Net income attributable to TEGP, excluding predecessor operations interest
15,866


7,041


36,648


18,078

Basic net income per Class A share
$
0.27

 
$
0.15

 
$
0.63

 
$
0.38

Diluted net income per Class A share
$
0.27

 
$
0.15

 
$
0.63

 
$
0.38

Basic average number of Class A shares outstanding
58,075

 
47,725

 
58,075

 
47,725

Diluted average number of Class A shares outstanding
58,192

 
47,775

 
58,193

 
47,740




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



TALLGRASS ENERGY GP, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
Nine Months Ended September 30,
 
2017
 
2016
 
(in thousands)
Cash Flows from Operating Activities:
 
 
 
Net income
$
317,182

 
$
185,429

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
73,087

 
70,583

Equity in earnings of unconsolidated investments
(187,121
)
 
(37,495
)
Distributions from unconsolidated investments
187,624

 
37,361

Deferred income tax expense
24,982

 
12,792

Gain on remeasurement of unconsolidated investment
(9,728
)
 

Changes in components of working capital:
 
 
 
Accounts receivable and other
(34,189
)
 
8,220

Accounts payable and accrued liabilities
42,680

 
4,916

Deferred revenue
26,898

 
25,303

Other current assets and liabilities
5,032

 
(1,032
)
Other operating, net
3,930

 
(14
)
Net Cash Provided by Operating Activities
450,377


306,063

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
(88,050
)
 
(55,397
)
Acquisition of Deeprock Development
(57,202
)
 

Distributions from unconsolidated investments in excess of cumulative earnings
41,886

 
16,073

Acquisition of PRB Crude System
(36,030
)
 

Contributions to unconsolidated investments
(31,570
)
 
(35,515
)
Acquisition of Pony Express membership interest

 
(49,118
)
Other investing, net
(13,449
)
 
205

Net Cash Used in Investing Activities
(852,941
)

(559,774
)
Cash Flows from Financing Activities:
 
 
 
Proceeds from issuance of long-term debt
850,000

 
400,000

Distributions to noncontrolling interests
(229,710
)
 
(177,449
)
(Repayments) borrowings under revolving credit facilities, net
(136,000
)
 
252,000

Proceeds from public offering of TEP common units, net of offering costs
112,393

 
290,474

Partial exercise of call option
(72,381
)
 
(151,434
)
TEGP distributions to Class A shareholders
(52,704
)
 
(29,971
)
Repurchase of TEP common units from TD
(35,335
)
 

Acquisition of Pony Express membership interest

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

 
90,009

Other financing, net
(32,879
)
 
5,089

Net Cash Provided by Financing Activities
403,384


252,836

Net Change in Cash and Cash Equivalents
820

 
(875
)
Cash and Cash Equivalents, beginning of period
2,459

 
2,234

Cash and Cash Equivalents, end of period
$
3,279

 
$
1,359

 
 
 
 
Schedule of Noncash Investing and Financing Activities:
 
 
 
TEP common units issued as partial consideration to acquire additional 9% membership interest in Deeprock Development
$
6,617

 
$

Increase in accrual for payment of property, plant and equipment
$
1,342

 
$


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



TALLGRASS ENERGY GP, LP
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)
 
Predecessor Equity
 
Partners' Capital
 
Noncontrolling Interests
 
Total Equity
 
 
Class A Shares
 
Class B Shares
 
 
 
(in thousands)
Balance at January 1, 2017
$
82,295

 
$
250,967

 
$

 
$
1,596,152

 
$
1,929,414

Acquisition of Terminals and NatGas
(82,295
)
 
(21,314
)
 

 
(36,391
)
 
(140,000
)
Net income

 
36,648

 

 
280,534

 
317,182

Issuance of TEP units to the public, net of offering costs

 
11,350

 

 
101,043

 
112,393

TEGP distributions to Class A shareholders

 
(52,704
)
 

 

 
(52,704
)
Noncash compensation expense

 
1,186

 

 
6,169

 
7,355

TEP LTIP units tendered by employees to satisfy tax withholding obligations

 
(1,263
)
 

 
(11,139
)
 
(12,402
)
Partial exercise of call option

 
(12,052
)
 

 
(72,890
)
 
(84,942
)
Repurchase of TEP common units from TD

 
(3,618
)
 

 
(31,717
)
 
(35,335
)
Acquisition of additional 24.99% membership interest in Rockies Express

 
23,522

 

 
40,159

 
63,681

Acquisition of additional 40% membership interest in Deeprock Development

 

 

 
45,869

 
45,869

Acquisition of noncontrolling interests

 
669

 

 
(7,109
)
 
(6,440
)
Contributions from TD

 
850

 

 
1,451

 
2,301

Contributions from noncontrolling interest

 

 

 
1,093

 
1,093

Distributions to noncontrolling interest

 

 

 
(229,710
)
 
(229,710
)
Balance at September 30, 2017
$

 
$
234,241

 
$

 
$
1,683,514

 
$
1,917,755

 
 
 
 
 
 
 
 
 
 
 
Predecessor Equity
 
Partners' Capital
 
Noncontrolling Interests
 
Total Equity
 
 
Class A Shares
 
Class B Shares
 
 
 
(in thousands)
Balance at January 1, 2016
$
71,564

 
$
422,310

 
$

 
$
1,599,188

 
$
2,093,062

Net income
3,408

 
18,078

 

 
163,943

 
185,429

Issuance of TEP units to the public, net of offering costs

 
24,543

 

 
265,931

 
290,474

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

 
7,592

 

 
82,417

 
90,009

TEGP distributions to Class A Shareholders

 
(29,971
)
 

 

 
(29,971
)
Noncash compensation expense

 
1,060

 

 
5,931

 
6,991

Acquisition of additional 31.3% Pony Express membership interest

 
(255,617
)
 

 
(173,422
)
 
(429,039
)
Partial exercise of call option

 
(20,427
)
 

 
(156,865
)
 
(177,292
)
Contributions from TD

 
1,611

 

 
3,697

 
5,308

Contributions from noncontrolling interest

 

 

 
8,700

 
8,700

Distributions to noncontrolling interest

 

 

 
(177,449
)
 
(177,449
)
Contribution from Predecessor Entities, net
5,116

 

 

 

 
5,116

Acquisition of noncontrolling interests

 
(464
)
 

 
(5,536
)
 
(6,000
)
Cost associated with equity issuance

 
(657
)
 

 

 
(657
)
Balance at September 30, 2016
$
80,088


$
168,058


$


$
1,616,535


$
1,864,681


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



TALLGRASS ENERGY GP, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. Description of Business
Tallgrass Energy GP, LP ("TEGP" or the "Partnership") is a limited partnership that has elected to be treated as a corporation for U.S. federal income tax purposes. "We," "us," "our" and similar terms refer to TEGP together with its consolidated subsidiaries. TEGP's sole cash-generating asset as of September 30, 2017 is an approximate 36.94% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of direct and indirect partnership interests in Tallgrass Energy Partners, LP ("TEP"), as described below, that were historically owned by entities controlled by Tallgrass Equity, including Tallgrass Development, LP ("TD"):
100% of the outstanding membership interests in Tallgrass MLP GP, LLC ("TEP GP"), which owns the general partner interest in TEP as well as all of the TEP incentive distribution rights ("IDRs"). The general partner interest in TEP is represented by 834,391 general partner units, representing an approximate 1.13% general partner interest in TEP at September 30, 2017.
20,000,000 TEP common units, representing an approximate 27.02% limited partner interest in TEP at September 30, 2017.
TEP is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. TEP's 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:
Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities;
Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and
Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering, processing, treating and fractionation facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; and the transportation of NGLs.
Natural Gas Transportation. TEP provides natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) its 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 TD effective March 31, 2017 as discussed in  Note 4 – Acquisitions, and TEP's 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").
Crude Oil Transportation. TEP currently provides 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, and includes a lateral in Northeast Colorado commencing in Weld County, Colorado that interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System").
Gathering, Processing & Terminalling. TEP provides natural gas gathering and processing services for customers in Wyoming through: (1) 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 4 – Acquisitions, (2) the Casper and Douglas natural gas processing facilities, and (3) the West Frenchie Draw natural gas treating facility. TEP also provides crude oil gathering services for customers in Wyoming through a crude oil gathering system in the Powder River Basin (the "PRB Crude System") that was acquired on August 3, 2017, as discussed in Note 4 – Acquisitions; and NGL transportation services in Northeast Colorado and Wyoming. TEP performs water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, and Wyoming through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through TEP's 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

5



("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 4 – Acquisitions. The Gathering, Processing & Terminalling segment also includes newly formed Stanchion Energy, LLC ("Stanchion"), which transacts in crude oil.
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 4 – Acquisitions.
2. Summary of Significant Accounting Policies
Basis of Presentation
These condensed consolidated financial statements and related notes for the three and nine months ended September 30, 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 nine months ended September 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 nine months ended September 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 TEGP 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 TEGP is attributed to TEGP and noncontrolling interests in accordance with the respective ownership interests.
As further discussed in Note 4 – 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 TEGP 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. TEGP, 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 TEGP at historical cost.

6



A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Our consolidated VIEs do not have material assets that can only be used to settle specific obligations of the consolidated VIEs. Tallgrass Equity is considered to be a VIE under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we are the primary beneficiary as we have the right to receive benefits of Tallgrass Equity that could potentially be significant to Tallgrass Equity. TEP is also considered to be a VIE under the applicable authoritative guidance. Based on a qualitative analysis, we have determined that TEP GP is the primary beneficiary of TEP and we continue to consolidate TEP accordingly.
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.
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 applied the new guidance to our annual goodwill impairment tests performed as of August 31, 2017.

7



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.
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 have reviewed contracts for each revenue stream identified within each of our business segments and we are currently determining and documenting expected changes in revenue recognition upon adoption of the revised guidance.
We are evaluating 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 and Gathering, Processing & Terminalling segments, and the timing of revenue recognition with respect to deficiency payments received in our Crude Oil Transportation segment. We are currently working

8



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.
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. Variable Interest Entities
TEP is a VIE of which TEP GP, our consolidated subsidiary, is the primary beneficiary. We continue to consolidate TEP accordingly. We have not provided any additional financial support other than TEP GP's initial capital contribution to acquire the general partner interest in TEP and have no contractual commitments or obligations to provide additional financial support to TEP.
TEGP, as the managing member of Tallgrass Equity, has voting rights disproportionate to its ownership interest. As a result, we have determined that Tallgrass Equity is a VIE of which we are the primary beneficiary and we consolidate Tallgrass Equity accordingly. We have not provided any additional financial support to Tallgrass Equity other than our initial capital contribution to acquire a portion of our controlling interest in Tallgrass Equity and have no contractual commitments or obligations to provide additional financial support to Tallgrass Equity.
Other than TEGP's deferred tax asset of approximately $496.5 million and $521.5 million at September 30, 2017 and December 31, 2016, respectively, the assets and liabilities included in our condensed consolidated balance sheets at September 30, 2017 and December 31, 2016 represent the consolidated assets and liabilities of Tallgrass Equity, including the assets and liabilities of TEP.
4. Acquisitions
TEP Acquisition of Outrigger Powder River Operating, LLC
On August 3, 2017, TEP acquired 100% of the membership interests of Outrigger Powder River Operating, LLC (subsequently renamed as Tallgrass Crude Gathering, LLC, "TCG"), which owns the PRB Crude System, a crude oil gathering system in the Powder River Basin with approximately 34 miles of gathering lines and approximately 150,000 acres dedicated on a long-term fee-based contract, for approximately $36 million, subject to working capital adjustments. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.

9



The following represents the fair value of assets acquired and liabilities assumed at August 3, 2017 (in thousands):
Accounts receivable
$
117

 
Property, plant and equipment
29,306

 
Intangible asset
6,694

(1) 
Accounts payable and accrued liabilities
(87
)
 
Net identifiable assets acquired
$
36,030

 
(1) 
The $6.7 million intangible asset acquired represents a major customer contract. This intangible asset is amortized on a straight-line basis over a period of 8 years, the remaining term of the contract at the time of acquisition.
At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. 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. Actual revenue and net loss attributable to TEP from TCG of less than $1 million was recognized in the accompanying condensed consolidated statements of income for the period from August 3, 2017 to September 30, 2017.
Acquisitions of Additional Interests in Deeprock Development
On July 20, 2017, TEP acquired an additional 40% membership interest in Deeprock Development from Kinder Morgan Cushing, LLC for cash consideration of approximately $57.2 million, net of cash acquired. TEP subsequently acquired an additional 9% membership interest in Deeprock Development from Deeprock Energy Resources LLC ("DER") on July 21, 2017, as discussed further below.
Upon closing of the acquisition of the 40% membership interest on July 20, 2017, TEP obtained a controlling financial interest in Deeprock Development and accordingly has accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously held 20% equity interest in Deeprock Development to its fair value of $22.9 million, recognized a gain of $9.7 million in "Gain on remeasurement of unconsolidated investment" in the condensed consolidated statements of income, and consolidated Deeprock Development in its condensed consolidated financial statements. The 40% equity interest in Deeprock Development held by noncontrolling interests was recorded at its acquisition date fair value of $45.9 million. The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis and adjusted for lack of control. These fair value measurements are based on significant inputs, such as forecasted cash flows and discount rates, that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.
The following represents the fair value of assets acquired and liabilities assumed at July 20, 2017 (in thousands):
Accounts receivable
$
968

Other current assets
598

Property, plant and equipment
70,148

Accounts payable
(712
)
Deferred revenue
(6,546
)
Net identifiable assets acquired
64,456

Goodwill
61,550

Net assets acquired (excluding cash)
$
126,006

At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. 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. The goodwill recognized of $61.6 million is primarily attributed to synergies expected from combining the operations of TEP and Deeprock Development. All of the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TEP from Deeprock Development of $2.4 million and $1.1 million, respectively, was recognized in the accompanying condensed consolidated statements of income for the period from July 20, 2017 to September 30, 2017.

10



On July 21, 2017, subsequent to the acquisition of an additional 40% membership interest discussed above, TEP acquired an additional 9% membership interest in Deeprock Development from DER for total consideration valued at approximately $13.1 million, consisting of approximately $6.4 million in cash and the issuance of 128,790 TEP common units (valued at approximately $6.7 million based on the July 20, 2017 closing price of TEP's common units), which was accounted for as an acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate membership interest in Deeprock Development is 69%.
Pro Forma Financial Information
Unaudited pro forma revenue and net income attributable to TEGP for the three and nine months ended September 30, 2017 and 2016 is presented below as if the acquisitions of TCG and Deeprock Development had been completed on January 1, 2016.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Revenue
$
177,022

 
$
158,642

 
$
492,625

 
$
465,232

Net income attributable to partners
$
6,083

 
$
10,787

 
$
25,951

 
$
21,896

The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TEGP 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 TEGP 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 the estimated results of operations of TCG and Deeprock Development for the periods presented, as well as to eliminate the equity in earnings and gain on remeasurement of unconsolidated investment associated with our previously held 20% membership interest in Deeprock Development.
TEP Acquisition of DCP Douglas, LLC
On June 5, 2017, TEP acquired 100% of the membership interests in DCP Douglas, LLC (subsequently renamed as Tallgrass Midstream Gathering, 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 the Douglas processing plant, for approximately $128.5 million, subject to working capital adjustments. The acquisition 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.
TEP 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 TEP is considered a transaction between entities under common control, but does not represent a change in reporting entity. TEP's 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 TEP 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 8 – 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 September 30, 2017 was allocated as follows:

11



 
Basis Difference
 
Amortization Period
 
(in thousands)
 
 
Long-term debt
$
19,078

 
2 - 25 years
Property, plant and equipment
(399,667
)
 
35 years
Total basis difference
$
(380,589
)
 
 
TEP Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC    
Effective January 1, 2017, TEP 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.
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 69% interest in the Deeprock Development Terminal in Cushing, Oklahoma following the acquisition of an aggregate additional 49% membership interest in Deeprock Development in July 2017 discussed above. 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.

12



Historical Financial Information
The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated balance sheets as of September 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
 
TEGP (As previously reported)
 
Consolidate Terminals
 
Consolidate NatGas
 
TEGP (As currently reported)
 
(in thousands)
ASSETS
 
 
 
 
 
Current Assets:
 
 
 
 
 
 
 
Cash and cash equivalents
$
2,459

 
$

 
$

 
$
2,459

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
94,117

 
1,134

 
29

 
95,280

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

 
66,969

 

 
2,079,232

Goodwill
343,288

 

 

 
343,288

Intangible assets, net
93,522

 

 

 
93,522

Unconsolidated investments
461,915

 
13,710

 

 
475,625

Deferred tax asset
521,454

 

 

 
521,454

Deferred financing costs, net
6,042

 

 

 
6,042

Deferred charges and other assets
9,637

 
1,400

 

 
11,037

Total Assets
$
3,542,238

 
$
83,213

 
$
29

 
$
3,625,480

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current Liabilities:
 
 
 
 
 
 
 
Accounts payable
$
24,403

 
$
46

 
$

 
$
24,449

Accounts payable to related parties
5,768

 
56

 

 
5,824

Gas imbalances
1,239

 

 

 
1,239

Derivative liabilities
556

 

 

 
556

Accrued taxes
16,328

 
668

 

 
16,996

Accrued liabilities
16,578

 
177

 

 
16,755

Deferred revenue
60,757

 

 

 
60,757

Other current liabilities
6,446

 

 

 
6,446

Total Current Liabilities
132,075

 
947

 

 
133,022

Long-term debt, net
1,555,981

 

 

 
1,555,981

Other long-term liabilities and deferred credits
7,063

 

 

 
7,063

Total Long-term Liabilities
1,563,044

 

 

 
1,563,044

Equity:
 
 
 
 
 
 
 
Net Equity
1,847,119

 
82,266

 
29

 
1,929,414

Total Equity
1,847,119

 
82,266

 
29

 
1,929,414

Total Liabilities and Equity
$
3,542,238

 
$
83,213

 
$
29

 
$
3,625,480


13



The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated statements of income for the three and nine months ended September 30, 2017 and 2016. The following tables present the previously reported condensed consolidated statements of income for the three and nine months ended September 30, 2016, adjusted for the acquisitions of Terminals and NatGas:
 
Three Months Ended September 30, 2016
 
TEGP (As previously reported)
 
Consolidate Terminals
 
Consolidate NatGas
 
Elimination
 
TEGP (As currently reported)
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
Crude oil transportation services
$
91,387

 
$

 
$

 
$

 
$
91,387

Natural gas transportation services
31,444

 

 

 

 
31,444

Sales of natural gas, NGLs, and crude oil
20,758

 

 

 
(271
)
(1) 
20,487

Processing and other revenues
8,536

 
3,116

 
1,182

 
(2,884
)
(2) 
9,950

Total Revenues
152,125

 
3,116

 
1,182

 
(3,155
)
 
153,268

Operating Costs and Expenses:
 
 
 
 
 
 
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
18,590

 

 

 
(271
)
(1) 
18,319

Cost of transportation services (exclusive of depreciation and amortization shown below)
13,528

 
198

 

 
(2,884
)
(2) 
10,842

Operations and maintenance
14,714

 
432

 

 

 
15,146

Depreciation and amortization
20,831

 
346

 

 

 
21,177

General and administrative
13,715

 
266

 

 

 
13,981

Taxes, other than income taxes
6,717

 
143

 

 

 
6,860

Total Operating Costs and Expenses
88,095

 
1,385

 

 
(3,155
)
 
86,325

Operating Income (Loss)
64,030

 
1,731

 
1,182

 

 
66,943

Other Income (Expense):
 
 
 
 
 
 
 
 
 
Interest expense, net
(12,157
)
 

 

 

 
(12,157
)
Unrealized loss on derivative instrument
(4,419
)
 

 

 

 
(4,419
)
Equity in earnings of unconsolidated investments
12,066

 
698

 

 

 
12,764

Other income, net
480

 

 

 

 
480

Total Other (Expense) Income
(4,030
)
 
698

 

 

 
(3,332
)
Net income before tax
60,000

 
2,429

 
1,182

 

 
63,611

Deferred income tax expense
(3,209
)
 

 

 

 
(3,209
)
Net income
56,791

 
2,429

 
1,182

 

 
60,402

Net income attributable to noncontrolling interests
(49,750
)
 

 

 

 
(49,750
)
Net income attributable to TEGP
$
7,041

 
$
2,429

 
$
1,182

 
$

 
$
10,652








14



 
Nine Months Ended September 30, 2016
 
TEGP (As previously reported)
 
Consolidate Terminals
 
Consolidate NatGas
 
Elimination
 
TEGP (As currently reported)
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
Crude oil transportation services
$
279,281

 
$

 
$

 
$

 
$
279,281

Natural gas transportation services
89,406

 

 

 

 
89,406

Sales of natural gas, NGLs, and crude oil
51,514

 

 

 
(271
)
(1) 
51,243

Processing and other revenues
24,260

 
8,982

 
4,855

 
(8,576
)
(2) 
29,521

Total Revenues
444,461


8,982


4,855


(8,847
)

449,451

Operating Costs and Expenses:
 
 
 
 
 
 
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
48,116

 

 

 
(271
)
(1) 
47,845

Cost of transportation services (exclusive of depreciation and amortization shown below)
43,924

 
598

 

 
(8,576
)
(2) 
35,946

Operations and maintenance
41,055

 
1,319

 

 

 
42,374

Depreciation and amortization
64,099

 
975

 

 

 
65,074

General and administrative
41,710

 
1,153

 

 

 
42,863

Taxes, other than income taxes
19,862

 
431

 

 

 
20,293

Contract termination

 
8,061

(3) 

 

 
8,061

Loss on disposal of assets
1,849

 

 

 

 
1,849

Total Operating Costs and Expenses
260,615


12,537




(8,847
)

264,305

Operating Income
183,846


(3,555
)

4,855




185,146

Other Income (Expense):
 
 
 
 
 
 
 
 
 
Interest expense, net
(31,275
)
 

 

 

 
(31,275
)
Unrealized gain on derivative instrument
5,588

 

 

 

 
5,588

Equity in earnings of unconsolidated investments
35,387

 
2,108

 

 

 
37,495

Other income, net
1,267

 

 

 

 
1,267

Total Other Income
10,967


2,108






13,075

Net income (loss) before tax
194,813


(1,447
)

4,855




198,221

Deferred income tax expense
(12,792
)
 

 

 

 
(12,792
)
Net income (loss)
182,021


(1,447
)

4,855




185,429

Net income attributable to noncontrolling interests
(163,943
)
 

 

 

 
(163,943
)
Net income (loss) attributable to TEGP
$
18,078


$
(1,447
)

$
4,855


$


$
21,486

(1) 
Represents the elimination of revenue and cost of sales associated with the purchase of crude oil from Pony Express by Terminals.
(2) 
Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal facilities by Pony Express.
(3) 
Represents a one-time charge related to the termination of an operating agreement at the Sterling Terminal.

15



5. 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.
We have no employees. In connection with the closing of the TEP 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. In addition, in connection with the closing of our initial public offering on May 12, 2015 (the "TEGP IPO"), TEGP entered into an Omnibus Agreement (the "TEGP Omnibus Agreement") with TEGP Management, LLC, Tallgrass Equity and Tallgrass Energy Holdings, LLC (which is the general partner of TD).
Pursuant to the TEGP Omnibus Agreement, Tallgrass Equity pays a reimbursement to TD for costs associated with TEGP being a public company beginning in the second quarter of 2015, which was $500,000 for the third quarter of 2017. This amount is periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEGP.
Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Processing and other revenues (1)
$
3,338

 
$
1,182

 
$
6,662

 
$
4,855

Cost of transportation services (2)
$
1,062

 
$
4,630

 
$
10,476

 
$
13,888

Charges to TEGP: (3)
 
 
 
 
 
 
 
Property, plant and equipment, net
$
765

 
$
688

 
$
1,568

 
$
2,255

Operations and maintenance
$
7,973

 
$
6,560

 
$
21,680

 
$
19,117

General and administrative
$
11,960

 
$
10,423

 
$
32,628

 
$
30,066

(1) 
Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline.
(2) 
Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017, as discussed in Note 4 – Acquisitions.
(3) 
Charges to TEGP, inclusive of Tallgrass Equity and 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:
 
September 30, 2017
 
December 31, 2016
 
(in thousands)
Receivable from related parties:
 
 
 
Rockies Express Pipeline LLC
$
1,052

 
$
590

Total receivable from related parties
$
1,052

 
$
590

Accounts payable to related parties:
 
 
 
Tallgrass Operations, LLC
$
5,955

 
$
5,811

Deeprock Development, LLC

 
13

Total accounts payable to related parties
$
5,955

 
$
5,824


16



Gas imbalances with affiliated shippers are as follows:
 
September 30, 2017
 
December 31, 2016
 
(in thousands)
Affiliate gas imbalance receivables
$
17

 
$
177

Affiliate gas imbalance payables
$
43

 
$

6. Inventory
The components of inventory at September 30, 2017 and December 31, 2016 consisted of the following:
 
September 30, 2017
 
December 31, 2016
 
(in thousands)
Crude oil
$
2,115

 
$
5,462

Materials and supplies
5,993

 
6,383

Natural gas liquids
543

 
265

Gas in underground storage
1,522

 
983

Total inventory
$
10,173

 
$
13,093

7. Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
 
September 30, 2017
 
December 31, 2016
 
(in thousands)
Crude oil pipelines
$
1,219,913

 
$
1,202,125

Gathering, processing and terminalling assets (1)
667,379

 
397,701

Natural gas pipelines
577,343

 
572,150

General and other
98,860

 
82,510

Construction work in progress
45,223

 
20,606

Accumulated depreciation and amortization
(257,888
)
 
(195,860
)
Total property, plant and equipment, net
$
2,350,830

 
$
2,079,232

(1) 
Includes approximately $138.2 million of assets associated with the Douglas Gathering System acquired in June 2017, approximately $68.4 million of assets associated with the acquisition of the aggregate additional 49% membership interest in Deeprock Development in July 2017, and approximately $29.3 million of assets associated with the PRB Crude System acquired in August 2017.
8. 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 nine months ended September 30, 2017, we recognized equity in earnings associated with our 49.99% membership interest in Rockies Express of $185.7 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $227.5 million and $29.5 million, respectively. As discussed in Note 4 – Acquisitions, we acquired an additional 24.99% membership interest in Rockies Express from TD on March 31, 2017.

17



Summarized financial information for Rockies Express is as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Revenue
$
216,756

 
$
159,421

 
$
625,243

 
$
551,323

Operating income
$
123,965

 
$
66,436

 
$
344,037

 
$
267,847

Net income to Members
$
233,990

 
$
34,184

 
$
371,185

 
$
226,847

Deeprock Development
As discussed in Note 4 – Acquisitions, on July 20, 2017, TEP acquired an additional 40% membership interest in Deeprock Development. As a result of the acquisition, TEP consolidated Deeprock Development and effective July 20, 2017 will no longer account for its investment in Deeprock Development under the equity method of accounting.
9. Goodwill
Reconciliation of Goodwill
The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the reporting period:
 
Three and Nine Months Ended September 30,
 
2017
 
2016
 
Natural Gas Transportation
 
Gathering, Processing & Terminalling
 
Total
 
Natural Gas Transportation
 
Gathering, Processing & Terminalling
 
Total
 
(in thousands)
Balance at beginning of period
$
255,558

 
$
87,730

 
$
343,288

 
$
255,558

 
$
87,730

 
$
343,288

Goodwill acquired

 
61,550

(1) 
61,550

 

 

 

Balance at end of period
$
255,558

 
$
149,280

 
$
404,838

 
$
255,558

 
$
87,730

 
$
343,288

(1) 
The $61.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Deeprock Development on July 20, 2017 as discussed further in Note 4 – Acquisitions.
Annual Goodwill Impairment Analysis
We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is the same as, or one level below, an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or proceeding directly to the quantitative impairment test depending on facts and circumstances of the reporting unit. If we, after performing the qualitative assessment, determine it is “more likely than not” that the fair value of a reporting unit is greater than its carrying amount, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit 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.
We did not elect to apply the qualitative assessment option during our 2017 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. We compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of

18



which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the quantitative impairment test indicated no impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, we did not record a goodwill impairment during the nine months ended September 30, 2017. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.
10. Risk Management
We enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets:
 
Balance Sheet
Location
 
September 30, 2017
 
December 31, 2016
 
 
 
(in thousands)
Natural gas derivative contracts (1)
Current assets
 
$

 
$
291

Call option derivative (2)
Current assets
 
$

 
$
10,676

Crude oil derivative contracts (3)
Current liabilities
 
$
472

 
$
440

Natural gas derivative contracts (1)
Current liabilities
 
$
1

 
$
116

(1) 
As of September 30, 2017, the fair value shown for natural gas derivative contracts was comprised of derivative volumes for long natural gas fixed-price swaps totaling 0.1 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.
(2) 
As discussed below, in conjunction with TEP's acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted TEP an 18 month call option covering the 6,518,000 TEP common units issued to TD. As of February 1, 2017, no common units remained subject to the call option.
(3) 
As of September 30, 2017, the fair value shown for crude oil derivative contracts represents the purchase and sale of 323,620 barrels which will settle throughout 2017 and the first quarter of 2018. As of December 31, 2016, the fair value shown for crude oil derivative contracts represents the sale of 125,000 barrels of crude oil which settled throughout 2017.

19



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 nine months ended September 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 September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
 
 
 
(in thousands)
Crude oil derivative contracts
 
Sales of natural gas, NGLs, and crude oil
 
$
175

 
$
318

 
$
1,065

 
$
466

Natural gas derivative contracts
 
Sales of natural gas, NGLs, and crude oil
 
$
(22
)
 
$
161

 
$
84

 
$
(190
)
Call option derivative
 
Unrealized (loss) gain on derivative instrument
 
$

 
$
(4,419
)
 
$
1,885

 
$
5,588

Call Option Derivative
As part of TEP's acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted TEP an 18 month call option at an exercise price of $42.50 per TEP common unit covering the 6,518,000 TEP common units issued to TD as a portion of the consideration. In July 2016 and October 2016, TEP 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, TEP 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.
Our over-the-counter swaps are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with financial institutions with investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. As of September 30, 2017, the fair value of our crude oil and natural gas derivative contracts were a liability position, resulting in no credit exposure from TEP's counterparties as of that date.
As of September 30, 2017 we had $0.8 million and $3.0 million of cash in margin accounts and outstanding letters of credit, respectively, in support of our commodity derivative contracts. As of 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.
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 included 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.

20



The following table summarizes the fair value measurements of our derivative contracts as of September 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 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 September 30, 2017:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
472

 
$

 
$
472

 
$

Natural gas derivative contracts
$
1

 
$

 
$
1

 
$

As of December 31, 2016:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
440

 
$

 
$
440

 
$

Natural gas derivative contracts
$
116

 
$

 
$
116

 
$

11. Long-term Debt
Long-term debt consisted of the following at September 30, 2017 and December 31, 2016:
 
September 30, 2017
 
December 31, 2016
 
(in thousands)
Tallgrass Equity revolving credit facility
$
146,000

 
$
148,000

TEP revolving credit facility
881,000

 
1,015,000

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

 
400,000

TEP 5.50% senior notes due January 15, 2028
500,000

 

Less: Deferred financing costs, net (1)
(15,914
)
 
(7,019
)
Total long-term debt, net
$
2,261,086

 
$
1,555,981

(1) 
Deferred financing costs, net as presented above relate solely to the 2024 and 2028 Notes. Deferred financing costs associated with our revolving credit facilities are presented in noncurrent assets on our condensed consolidated balance sheets.
TEP Senior Unsecured Notes
On September 15, 2017, 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 15, 2017 (the "2028 Indenture") pursuant to which the Issuers issued $500 million in aggregate principal amount of 5.50% senior notes due 2028 (the "2028 Notes").
The 2028 Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all of TEP’s properties to, another person. As of September 30, 2017, TEP is in compliance with the covenants required under the 2028 Notes.

21



On September 1, 2016, the Issuers, the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the "2024 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 2024 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. 
The 2024 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 in the event of default or noncompliance with the covenants required, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. As of September 30, 2017, TEP is in compliance with the covenants required under the 2024 Notes.
Tallgrass Equity Revolving Credit Facility
The following table sets forth the available borrowing capacity under the Tallgrass Equity revolving credit facility as of September 30, 2017 and December 31, 2016:
 
September 30, 2017
 
December 31, 2016
 
(in thousands)
Total capacity under Tallgrass Equity revolving credit facility
$
150,000

 
$
150,000

Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility
(146,000
)
 
(148,000
)
Available capacity under the Tallgrass Equity revolving credit facility
$
4,000

 
$
2,000

In connection with the TEGP IPO, Tallgrass Equity entered into a $150 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 12, 2020. Among various other covenants and restrictive provisions, Tallgrass Equity is required to maintain a total leverage ratio of not more than 3.00 to 1.00. As of September 30, 2017, Tallgrass Equity is 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 of 0.50%. As of September 30, 2017, the weighted average interest rate on outstanding borrowings under the Tallgrass Equity revolving credit facility was 3.74%. During the nine months ended September 30, 2017, Tallgrass Equity's weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 3.88%.
TEP 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 TEP revolving credit facility as of September 30, 2017 and December 31, 2016:
 
September 30, 2017
 
December 31, 2016
 
(in thousands)
Total capacity under the TEP revolving credit facility
$
1,750,000

 
$
1,750,000

Less: Outstanding borrowings under the TEP revolving credit facility
(881,000
)
 
(1,015,000
)
Less: Letters of credit issued under the TEP revolving credit facility
(3,094
)
 

Available capacity under the TEP revolving credit facility
$
865,906

 
$
735,000


22



TEP's revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP's ability (as well as the ability of its 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 its business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 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 September 30, 2017, TEP is in compliance with the covenants required under its revolving credit facility.
The unused portion of TEP's revolving credit facility is subject to a commitment fee, which ranges from 0.250% to 0.500%, based on TEP's total leverage ratio. As of September 30, 2017, the weighted average interest rate on outstanding borrowings under the TEP revolving credit facility was 3.24%. During the nine months ended September 30, 2017, the weighted average effective interest rate under the TEP revolving credit facility, including the interest on outstanding borrowings under TEP's revolving credit facility, commitment fees, and amortization of deferred financing costs, was 3.25%.
Fair Value
The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of September 30, 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 September 30, 2017:
 
 
 
 
 
 
 
 
 
Revolving credit facilities
$

 
$
1,027,000

 
$

 
$
1,027,000

 
$
1,027,000

2024 Notes
$

 
$
772,028

 
$

 
$
772,028

 
$
739,444

2028 Notes
$

 
$
508,660

 
$

 
$
508,660

 
$
494,642

As of December 31, 2016:
 
 
 
 
 
 
 
 
 
Revolving credit facilities
$

 
$
1,163,000

 
$

 
$
1,163,000

 
$
1,163,000

2024 Notes
$

 
$
398,000

 
$

 
$
398,000

 
$
392,981

The long-term debt borrowed under the revolving credit facilities is carried at amortized cost. As of September 30, 2017 and December 31, 2016, the fair value of borrowings under the revolving credit facilities approximates the carrying amount of the borrowings using a discounted cash flow analysis. The 2024 and 2028 Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 and 2028 Notes is based upon quoted market prices adjusted for illiquid markets. We are not aware of any factors that would significantly affect the estimated fair value subsequent to September 30, 2017.

23



12. Partnership Equity and Distributions
TEGP Distributions to Holders of Class A Shares
The following table details the distributions for the periods indicated:
Three Months Ended
 
Date Paid
 
Distributions to Class A Shareholders
 
Distributions per Class A Share
 
 
 
 
(in thousands)
 
 
September 30, 2017
 
November 14, 2017 (1)
 
$
20,617

 
$
0.3550

June 30, 2017
 
August 14, 2017
 
19,891

 
0.3425

March 31, 2017
 
May 15, 2017
 
16,697

 
0.2875

December 31, 2016
 
February 14, 2017
 
16,116

 
0.2775

September 30, 2016
 
November 14, 2016
 
12,528

 
0.2625

June 30, 2016
 
August 12, 2016
 
11,693

 
0.2450

March 31, 2016
 
May 13, 2016
 
10,022

 
0.2100

(1) 
The distribution announced on October 10, 2017 for the third quarter of 2017 will be paid on November 14, 2017 to Class A shareholders of record at the close of business on October 31, 2017.
Subsidiary Distributions
TEP Distributions. 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)
 
 
September 30, 2017
 
November 14, 2017 (1)
 
$
69,174

 
$
37,744

 
$
1,219

 
$
108,137

 
$
0.9450

June 30, 2017
 
August 14, 2017
 
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

 
24,262

 
911

 
79,615

 
0.7550

March 31, 2016
 
May 13, 2016
 
48,238

 
19,816

 
830

 
68,884

 
0.7050

(1) 
The distribution announced on October 10, 2017 for the third quarter of 2017 will be paid on November 14, 2017 to unitholders of record at the close of business on October 31, 2017.
Repurchase of TEP Common Units Owned by TD
Following an offer received from TD with respect to TEP common units owned by TD not subject to the call option, TEP repurchased 736,262 TEP 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 TEP's general partner. These common units were deemed canceled upon TEP's purchase and as of such transaction date were no longer issued and outstanding.
TEP Equity Distribution Agreements
As of September 30, 2017, TEP had active equity distribution agreements pursuant to which it may sell from time to time through a group of managers, as its sales agents, TEP 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 TEP common units may be used for general partnership purposes, which includes, among other things, TEP's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with TEP'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.

24



TEP did not issue common units under the equity distribution agreements during the three months ended September 30, 2017. During the nine months ended September 30, 2017, TEP issued and sold 2,341,061 common units with a weighted average sales price of $48.82 per unit under its equity distribution agreements for net cash proceeds of approximately $112.4 million (net of approximately $1.9 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes as described above.
Noncontrolling Interests
As of September 30, 2017, noncontrolling interests in our subsidiaries consisted of a 63.06% interest in Tallgrass Equity held by the Exchange Right Holders, as defined in Note 13Net Income per Class A Share, the 72.67% limited partner interest in TEP held by TD and the public TEP unitholders and, a 31% membership interest in Deeprock Development, and the 2.0% membership interest in Pony Express held by TD. During the nine months ended September 30, 2017, we recognized contributions from and distributions to noncontrolling interests of $1.1 million and $229.7 million, respectively. Contributions from noncontrolling interests consisted primarily of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $135.4 million, Tallgrass Equity distributions to the Exchange Right Holders of $90.0 million, and distributions to Pony Express noncontrolling interests of $4.3 million.
During the nine months ended September 30, 2016, we received contributions from and made distributions to noncontrolling interests of $8.7 million and $177.4 million, respectively. Contributions from noncontrolling interests primarily consisted of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $103.7 million, Tallgrass Equity distributions to Exchange Right Holders of $68.7 million and distributions to Pony Express noncontrolling interests in the aggregate of $5.0 million.
Other Contributions and Distributions
During the nine months ended September 30, 2017 and 2016, TEP received contributions from TD of $2.3 million and $5.3 million, respectively, primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 15Legal and Environmental Matters.
13. Net Income per Class A Share
Basic net income per Class A share is determined by dividing net income attributable to TEGP by the weighted average number of outstanding Class A shares during the period. Class B shares do not share in the earnings of the Partnership. Accordingly, basic and diluted net income per Class B share has not been presented.
Diluted net income per Class A share is determined by dividing net income attributable to TEGP by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TEGP and the diluted weighted average number of Class A shares outstanding. The Exchange Right Holders refers to the group of persons who collectively own all of TEGP's outstanding Class B shares and an equivalent number of Tallgrass Equity units. The Exchange Right Holders are entitled to exercise the right to exchange their Tallgrass Equity units (together with an equivalent number of TEGP Class B shares) for TEGP Class A shares at an exchange ratio of one TEGP Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right Holders primarily consist of Kelso & Company and its affiliated investment funds, The Energy & Minerals Group and its affiliated investment funds, and Tallgrass KC, LLC, which is an entity owned by certain members of TEGP's and TEP's management.
Pursuant to the TEGP partnership agreement and the Tallgrass Equity limited liability company agreement, our capital structure and the capital structure of Tallgrass Equity will generally replicate one another in order to maintain the one-for-one exchange ratio between the Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the exchange of any Class B shares for Class A shares does not have a dilutive effect on basic net income per Class A share. However, for the nine months ended September 30, 2017 and 2016, the potential issuance of TEGP Equity Participation Shares would have had a dilutive effect on basic net income per Class A share.
All net income or loss from Terminals and NatGas prior to TEP's acquisition on January 1, 2017 is allocated to predecessor operations in the condensed consolidated statements of income. Accordingly, no net income or loss from Terminals and NatGas is allocated to our Class A shareholders. We present the financial results of any transferred business prior to the transaction date in the line item "Predecessor operations interest in net income" in the condensed consolidated statements of income.

25



The following table illustrates the calculation of net income per Class A share for the three and nine months ended September 30, 2017 and 2016:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands, except per share data)
Basic Net Income per Class A Share
 
 
 
 
 
 
 
Net income attributable to TEGP, excluding predecessor operations interest
$
15,866

 
$
7,041

 
$
36,648

 
$
18,078

Basic weighted average Class A Shares outstanding
58,075

 
47,725

 
58,075

 
47,725

Basic net income per Class A share
$
0.27

 
$
0.15

 
$
0.63

 
$
0.38

Diluted Net Income per Class A Share
 
 
 
 
 
 
 
Net income attributable to TEGP, excluding predecessor operations interest
$
15,866

 
$
7,041

 
$
36,648

 
$
18,078

Incremental net income attributable to TEGP including the effect of the assumed issuance of Equity Participation Shares
64

 
3

 
132

 
3

Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares
$
15,930

 
$
7,044

 
$
36,780

 
$
18,081

Basic weighted average Class A Shares outstanding
58,075

 
47,725

 
58,075

 
47,725

Equity Participation Shares equivalent shares
117

 
50

 
118

 
15

Diluted weighted average Class A Shares outstanding
58,192

 
47,775

 
58,193

 
47,740

Diluted net income per Class A Share
$
0.27

 
$
0.15

 
$
0.63

 
$
0.38

14. Regulatory Matters
There are no regulatory proceedings challenging the rates of Pony Express, Rockies Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT") or Trailblazer Pipeline Company LLC ("Trailblazer"). We have made certain regulatory filings with the FERC, including the following:
Pony Express
On May 22, 2017 and May 31, 2017, Pony Express made tariff filings with the FERC in Docket Nos. IS17-263-000, IS17-464-00, and IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the most recent FERC annual index adjustment of approximately 0.2%, which became effective July 1, 2017.
Rockies Express
Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000
On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 0.8 Bcf/d. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities. The project was placed in-service for the full 0.8 Bcf/d on January 6, 2017.
2016 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP16-702 and RP17-240
On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016. On December 1, 2016, Rockies Express made an interim fuel tracker filing with a proposed effective date of January 1, 2017 in Docket No. RP17-240. The FERC issued an order accepting the filing on December 29, 2016.

26



Electric Power Charge Clarification - FERC Docket No. RP17-285
On December 21, 2016, in Docket No. RP17-285, Rockies Express proposed certain revisions to the General Terms and Conditions of its tariff to clarify that the electric power costs associated with the operation of gas coolers installed in association with the Zone 3 Capacity Enhancement Project, at both electric and gas powered stations, will be included in the Power Cost Tracker. Several shippers submitted comments on the proposal. The FERC issued an order on January 19, 2017 accepting the proposed revisions permitting the recovery of electric power costs from the operation of both gas and electric powered compressor stations, subject to certain clarifications.
2017 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP17-401 and RP17-1064
On February 13, 2017, in Docket No. RP17-401, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2017. The FERC issued an order accepting the filing, including certain requested waivers, on March 21, 2017. On September 20, 2017, Rockies Express made its interim fuel tracker filing in Docket No. RP17-1064 with a proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on October 18, 2017.
TIGT
General Rate Case Filing - FERC Docket No. RP16-137-000, et seq.
On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the National Gas Act ("NGA"). The rate case proposed, among other things, a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT, certain changes to the transportation rate design of its system, a fixed fuel and lost and unaccounted for ("FL&U") and power cost tracker, and certain pro forma tariff records reflecting revisions to TIGT's Tariff.
On June 8, 2016, TIGT filed an Offer of Settlement (the "TIGT Rate Case Settlement") with the FERC, which resolved all issues the FERC had set for hearing. Following certification by the Administrative Law Judge and approval by the FERC, TIGT filed revised tariff records to implement the TIGT Rate Case Settlement, which the FERC subsequently approved on December 23, 2016. Per the terms of the TIGT Rate Case Settlement, TIGT is required to file a new general rate case on May 1, 2019 (provided that such rate case is not pre-empted by a pre-filing settlement).
On February 3, 2017, the FERC accepted TIGT’s pro forma tariff records, subject to conditions, and directed TIGT to file the actual tariff records within 30 days. TIGT subsequently submitted a compliance filing to implement the actual tariff records and restate its tariff to be effective April 1, 2017 and also filed to cancel its existing tariff (which was ultimately superseded by the new tariff). On March 16, 2017, the FERC accepted both filings.
2017 Annual Fuel Tracker Filing - FERC Docket No. RP17-428-000
On February 27, 2017, in Docket No. RP17-428-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2017. The filing incorporated the FL&U tracker and power cost tracker mechanisms agreed to in the TIGT Rate Case Settlement. The FERC accepted the filing on March 21, 2017.
Electric Power Charge Clarification - FERC Docket No. RP17-1051
On September 15, 2017, in Docket No. RP17-1051, TIGT proposed certain revisions to the General Terms and Conditions of its tariff to clarify, amongst other things, that the electric power costs associated with the operation of gas coolers at both electric and gas powered stations are properly included in the Power Cost Tracker. The FERC issued an order on October 3, 2017 accepting the proposed revisions.
Trailblazer
2017 Annual and Interim Fuel Tracker Filings - FERC Docket Nos. RP17-549 and RP17-1052
On March 22, 2017, in Docket No. RP17-549, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2017. The FERC accepted the filing on April 19, 2017. On September 15, 2017, Trailblazer made its interim fuel tracker filing in Docket No. RP17-1052 with a proposed effective date of November 1, 2017. The FERC accepted the filing on October 13, 2017.

27



15. 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, have recorded no reserve for legal claims as of September 30, 2017 or December 31, 2016.
Rockies Express
Ultra Resources
In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, seeking approximately $303 million in damages and other relief. On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of Texas, which operated as a stay of the Harris County state court proceeding.
On January 12, 2017, Rockies Express and Ultra entered into an agreement to settle Rockies Express' approximately $303 million claim against Ultra. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37 per dth/d, or approximately $26.8 million annually. TEP received its proportionate distribution from the cash settlement payment in July 2017.
Michels Corporation
On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due.
On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $10 million cash payment by Rockies Express. The cash payment was inclusive of approximately $5.9 million that Rockies Express had been withholding from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement and Rockies Express made the $10 million cash payment to Michels on February 16, 2017.
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 $7.7 million and $4.0 million at September 30, 2017 and December 31, 2016, 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.

28



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. On July 3, 2017, our partial delisting request was published by the EPA in the Federal Register. On August 3, 2017, there were no adverse public comments, therefore on August 29, 2017, the Casper Gas Plant portion of the Casper Mystery Bridge Superfund Site was delisted from the National Priorities List. A work plan has been developed to permanently close the associated monitoring wells, which is scheduled to be completed during the fourth quarter of 2017.
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
Trailblazer is currently operating at less than its current maximum allowable operating pressure ("MAOP"), public notice of which was first provided in June 2014. As a result of smart tool surveys conducted in 2014, Trailblazer identified approximately 25 - 35 miles of pipe that will likely need to be repaired or replaced in order for the pipeline to operate at its MAOP of 1,000 pounds per square inch across all segments of the Trailblazer Pipeline. Such repair or replacement will likely occur over a period of years, depending upon the remediation and repair plan implemented by Trailblazer. Segments of the Trailblazer Pipeline that require full replacement could cost as much as $2.7 million per mile and repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. 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 us.
With respect to the approximately 25 - 35 miles of pipe that has been identified, Trailblazer completed 32 excavation digs in 2015 at an aggregate cost of approximately $1.3 million. Trailblazer completed additional excavation digs and replaced approximately 8 miles of pipe at an aggregate cost of approximately $19.0 million during 2016, and intends to complete the pipe replacement project in 2017 at an estimated cost of $2.5 million. Trailblazer is currently exploring all possible cost recovery options to recover such out of pocket costs, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
In connection with our acquisition of the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions were necessitated by external corrosion caused by the pipeline's disbonded Hi-Melt CTE coating. The contractual indemnity provided by TD was capped at $20 million and was subject to a $1.5 million deductible. TEP has received $20 million from TD pursuant to the contractual indemnity as of September 30, 2017.
Pony Express
Pipeline Integrity
In connection with certain crack tool runs on the Pony Express System completed in 2015 and 2016, Pony Express completed approximately $9.8 million of remediation for anomalies identified on the Pony Express System associated with the initial conversion and commissioning of portions of the pipeline converted from natural gas to crude oil service, and has substantially completed additional remediation on the Pony Express System of approximately $9 million during the nine months ended September 30, 2017.
Terminals
System Failures
In January 2017, approximately 10,000 bbls of crude oil were released at the Sterling Terminal as the result of a defective roof drain system on a storage tank. The release was restricted to the containment area designed for such purpose and approximately 9,000 bbls were recovered. Remediation was complete as of June 30, 2017. The total cost to remediate the release was approximately $600,000.

29



16. Reportable Segments
Our operations are located in the United States. During the third quarter of 2017, management revised the operational reporting used by the chief operating decision maker in light of recent acquisitions and commercial management reorganization. As a result of this internal change, our reportable segments were updated to ensure that segment classification remains aligned with operational reporting. We are organized into three reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & Terminalling.
Natural Gas Transportation
The Natural Gas Transportation segment is engaged in the ownership and operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facility that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. The Natural Gas Transportation segment includes our 100% membership interest in NatGas acquired effective January 1, 2017 and our 49.99% membership interest in Rockies Express, including the additional 24.99% membership interest acquired effective March 31, 2017.
Crude Oil Transportation
The Crude Oil Transportation segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in the second quarter of 2015.
Gathering, Processing & Terminalling
The Gathering, Processing & Terminalling segment is engaged in the ownership and operation of natural gas gathering, 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, including the Douglas Gathering System acquired on June 5, 2017, as well as water business services provided primarily to the oil and gas exploration and production industry and the transportation of NGLs. The Gathering, Processing & Terminalling segment also includes Stanchion as well as our 100% membership interest in Terminals acquired effective January 1, 2017 and the PRB Crude System acquired on August 3, 2017.
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 facilities and the 2024 and 2028 Notes, 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.
The following tables set forth our segment information for the periods indicated:
 
Three Months Ended September 30, 2017
 
Three Months Ended September 30, 2016
Revenue:
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
(in thousands)
Natural Gas Transportation
$
36,084

 
$
(1,883
)
 
$
34,201

 
$
34,994

 
$
(1,427
)
 
$
33,567

Crude Oil Transportation
93,029

 
(6,947
)
 
86,082

 
95,826

 
(271
)
 
95,555

Gathering, Processing & Terminalling
57,736

 
(2,150
)
 
55,586

 
27,030

 
(2,884
)
 
24,146

Corporate and Other

 

 

 

 

 

Total revenue
$
186,849

 
$
(10,980
)
 
$
175,869

 
$
157,850

 
$
(4,582
)
 
$
153,268


30



 
Nine Months Ended September 30, 2017
 
Nine Months Ended September 30, 2016
Revenue:
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
(in thousands)
Natural Gas Transportation
$
105,622

 
$
(4,770
)
 
$
100,852

 
$
99,804

 
$
(4,192
)
 
$
95,612

Crude Oil Transportation
273,768

 
(6,947
)
 
266,821

 
283,868

 
(271
)
 
283,597

Gathering, Processing & Terminalling
121,415

 
(7,956
)
 
113,459

 
78,818

 
(8,576
)
 
70,242

Corporate and Other

 

 

 

 

 

Total revenue
$
500,805

 
$
(19,673
)
 
$
481,132

 
$
462,490

 
$
(13,039
)
 
$
449,451

 
Three Months Ended September 30, 2017
 
Three Months Ended September 30, 2016
Operating Income:
Total
Operating Income
 
Inter-
Segment
 
External
Operating Income
 
Total
Operating Income
 
Inter-
Segment
 
External
Operating Income
 
 (in thousands)
Natural Gas Transportation
$
17,016

 
$
(1,883
)
 
$
15,133

 
$
15,436

 
$
(1,427
)
 
$
14,009

Crude Oil Transportation
51,478

 
(441
)
 
51,037

 
53,227

 
4,230

 
57,457

Gathering, Processing & Terminalling
9,045

 
2,324

 
11,369

 
1,851

 
(2,803
)
 
(952
)
Corporate and Other
(3,536
)
 

 
(3,536
)
 
(3,571
)
 

 
(3,571
)
Total Operating Income
$
74,003

 
$

 
$
74,003

 
$
66,943

 
$

 
$
66,943

Reconciliation to Net Income:
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
 
 
 
(24,408
)
 
 
 
 
 
(12,157
)
Unrealized loss on derivative instruments
 
 
 
 

 
 
 
 
 
(4,419
)
Equity in earnings of unconsolidated investments
 
 
 
 
123,642

 
 
 
 
 
12,764

Gain on remeasurement of unconsolidated investment
 
 
 
 
9,728

 
 
 
 
 

Other income, net
 
 
 
 
454

 
 
 
 
 
480

Net income before tax
 
 
 
 
$
183,419

 
 
 
 
 
$
63,611


31



 
Nine Months Ended September 30, 2017
 
Nine Months Ended September 30, 2016
Operating Income:
Total
Operating Income
 
Inter-
Segment
 
External
Operating Income
 
Total
Operating Income
 
Inter-
Segment
 
External
Operating Income
 
 (in thousands)
Natural Gas Transportation
$
49,910

 
$
(4,770
)
 
$
45,140

 
$
39,873

 
$
(4,192
)
 
$
35,681

Crude Oil Transportation
145,462

 
8,054

 
153,516

 
159,619

 
12,613

 
172,232

Gathering, Processing & Terminalling
20,928

 
(3,284
)
 
17,644

 
(4,629
)
 
(8,421
)
 
(13,050
)
Corporate and Other
(12,127
)
 

 
(12,127
)
 
(9,717
)
 

 
(9,717
)
Total Operating Income
$
204,173

 
$

 
$
204,173

 
$
185,146

 
$

 
$
185,146

Reconciliation to Net Income:
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
 
 
 
(61,539
)
 
 
 
 
 
(31,275
)
Unrealized gain on derivative instruments
 
 
 
 
1,885

 
 
 
 
 
5,588

Equity in earnings of unconsolidated investments
 
 
 
 
187,121

 
 
 
 
 
37,495

Gain on remeasurement of unconsolidated investment
 
 
 
 
9,728

 
 
 
 
 

Other income, net
 
 
 
 
796

 
 
 
 
 
1,267

Net income before tax
 
 
 
 
$
342,164

 
 
 
 
 
$
198,221

 
Nine Months Ended September 30,
Capital Expenditures:
2017
 
2016
 
(in thousands)
Natural Gas Transportation
$
9,829

 
$
11,146

Crude Oil Transportation
28,785

 
25,985

Gathering, Processing & Terminalling
49,436

 
18,266

Corporate and Other

 

Total capital expenditures
$
88,050

 
$
55,397

Assets:
September 30, 2017
 
December 31, 2016
 
(in thousands)
Natural Gas Transportation
$
1,618,828

 
$
1,176,147

Crude Oil Transportation
1,384,981

 
1,410,695

Gathering, Processing & Terminalling
887,089

 
495,170

Corporate and Other
512,248

 
543,468

Total assets
$
4,403,146

 
$
3,625,480


32



Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The historical financial statements included in this Quarterly Report reflect the consolidated results of operations of TEGP's 36.94% interest in Tallgrass Equity, Tallgrass Equity's 100% membership interest in TEP GP, which owns all of the IDRs, and all of the outstanding general partner units in TEP, and Tallgrass Equity's 20 million TEP common units it acquired at the closing of the TEGP IPO. As used in this Quarterly Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEGP" and similar terms refer to Tallgrass Energy GP, LP, together with its consolidated subsidiaries (including Tallgrass Equity, TEP and their respective subsidiaries). The term our "general partner" refers to TEGP Management, LLC. References to "TD" refer to Tallgrass Development, LP. As discussed further in Note 2 – Summary of Significant Accounting Policies to the accompanying condensed consolidated financial statements, our financial statements for historical periods prior to January 1, 2017 have been recast to reflect the operations of Terminals and NatGas, which were acquired by TEP effective January 1, 2017.
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 TEGP's "Business" in our Annual Report on Form 10-K for the year ended December 31, 2016 (our "2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 15, 2017.
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 pay distributions to our Class A shareholders;
our expected receipt of, and amounts of, distributions from Tallgrass Equity;
TEP's ability to complete and integrate acquisitions from TD or from third parties, including its acquisitions of the PRB Crude System in August 2017, an additional 49% membership interest in Deeprock Development in July 2017, the Douglas Gathering System in June 2017, an additional 24.99% membership interest in Rockies Express from TD in March 2017 and a 100% membership interest in NatGas and Terminals from TD in January 2017;
the demand for TEP's services, including crude oil transportation, storage, gathering and terminalling services; natural gas transportation, storage, gathering and processing services; and water business services, as well as TEP's ability to successfully contract or re-contract with its customers;
large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;
our ability to successfully implement our business plan;
changes in general economic conditions;
competitive conditions in our industry;

33



the effects of existing and future laws and governmental regulations;
actions taken by third-party operators, processors and transporters;
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, natural gas liquids, and other hydrocarbons;
the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the price of alternative and competing fuels;
competition from the same and alternative energy sources;
energy efficiency and technology trends;
operating hazards and other risks incidental to transporting, storing, gathering and terminalling crude oil; transporting, storing and processing natural gas; and transporting, gathering and disposing of water produced in connection with hydrocarbon exploration and production activities;
environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
interest rates;
labor relations;
changes in tax status;
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
TEGP is a limited partnership that has elected to be treated as a corporation for U.S. federal income tax purposes. We were formed as part of a reorganization involving entities that were previously controlled by Tallgrass Equity to effect the TEGP IPO, which was completed on May 12, 2015.
Our sole cash-generating asset is an approximate 36.94% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of the direct and indirect partnership interests in TEP as described below:
100% of the outstanding membership interests in TEP GP, which owns all of the general partner interest in TEP as well as all of the TEP IDRs. The general partner interest in TEP is represented by 834,391 general partner units, representing an approximate 1.13% general partner interest in TEP at November 2, 2017.
20,000,000 TEP common units, representing an approximate 27.01% limited partner interest in TEP at November 2, 2017.
TEP is a publicly traded, growth-oriented limited partnership formed in 2013 to own, operate, acquire and develop midstream energy assets in North America. TEP's 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.
TEP intends to continue to leverage its relationship with TD and utilize the significant experience of its management team to execute its growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of its existing assets and expanding its systems through construction of additional assets.
Our reportable business segments are:
Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities;
Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and

34



Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering, processing, treating and fractionation facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; and the transportation of NGLs.
Financial Presentation
TEGP has no operations outside of its indirect ownership interests in TEP. TEGP is the managing member of and therefore controls Tallgrass Equity. Tallgrass Equity, in turn, controls TEP through the direct ownership of 100% of TEP GP, TEP's general partner. As a result, under GAAP, TEGP consolidates Tallgrass Equity, TEP GP, TEP, and TEP's subsidiaries. As such, TEGP's results of operations will not differ materially from the results of operations of TEP. The most noteworthy reconciling items between TEGP's condensed consolidated financial statements and TEP's condensed consolidated financial statements primarily relate to (i) the inclusion of the Tallgrass Equity revolving credit facility, (ii) the impact of TEGP's election to be treated as a corporation for U.S. federal income tax purposes and (iii) the presentation of noncontrolling interests in Tallgrass Equity and TEP. The interests in Tallgrass Equity and TEP that are not directly or indirectly owned by TEGP will be reflected as being attributable to noncontrolling interests in TEGP's condensed consolidated financial statements.
Recent Developments
TEGP Distribution Announced
On October 10, 2017, the Board of Directors of our general partner declared a cash distribution for the quarter ended September 30, 2017 of $0.3550 per Class A share. The distribution will be paid on November 14, 2017, to Class A shareholders of record on October 31, 2017.
TEP Distribution Announced
On October 10, 2017, the Board of Directors of TEP's general partner declared a cash distribution for the quarter ended September 30, 2017 of $0.9450 per common unit. The distribution will be paid on November 14, 2017, to unitholders of record on October 31, 2017.
How We Evaluate Our Operations
We evaluate our results using, among other measures, cash distributions received from Tallgrass Equity, TEP's contract profile and volumes, and operating costs and expenses of TEGP and its consolidated subsidiaries.
Cash Distributions Received from Tallgrass Equity
Our cash flow is currently generated solely by distributions received from Tallgrass Equity. Tallgrass Equity currently receives all of its cash flows from distributions on its direct and indirect partnership interests in TEP. Tallgrass Equity is therefore entirely dependent upon the ability of TEP to make cash distributions to its partners.
TEP's Contract Profile and Volumes
TEP's results are driven primarily by the volume of natural gas transportation and storage capacity, crude oil transportation, storage, gathering and terminalling capacity, NGL transportation capacity, and water transportation, gathering and disposal capacity under firm fee contracts, as well as the volume of natural gas that it gathers and processes and the fees assessed for such services.
Operating Costs and Expenses
The primary components of TEP's operating costs and expenses that we evaluate include cost of sales, cost of transportation services, operations and maintenance and general and administrative costs. TEP's operating expenses are driven primarily by expenses related to the operation, maintenance and growth of its asset base.

35



Results of Operations
The following provides a summary of our operating metrics for the periods indicated:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Natural Gas Transportation Segment:
 
 
 
 
 
 
 
Gas transportation average firm contracted volumes (MMcf/d) (1)
1,646

 
1,601

 
1,737

 
1,625

Crude Oil Transportation Segment:
 
 
 
 
 
 
 
Crude oil transportation average contracted capacity (Bbls/d)
306,916

 
298,580

 
302,476

 
294,364

Crude oil transportation average throughput (Bbls/d)
269,585

 
276,138

 
268,435

 
284,512

Gathering, Processing & Terminalling Segment:
 
 
 
 
 
 
 
Natural gas processing inlet volumes (MMcf/d)
111

 
103

 
106

 
102

Freshwater average volumes (Bbls/d)
109,988

 
31,656

 
93,885

 
31,291

Produced water gathering and disposal average volumes (Bbls/d)
43,924

 
23,784

 
23,405

 
18,176

(1) 
Volumes transported under firm fee contracts, excluding Rockies Express.

36



The following provides a summary of our consolidated results of operations for the periods indicated:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
Crude oil transportation services
$
86,180

 
$
91,387

 
$
260,366

 
$
279,281

Natural gas transportation services
30,256

 
31,444

 
91,370

 
89,406

Sales of natural gas, NGLs, and crude oil
32,215

 
20,487

 
70,514

 
51,243

Processing and other revenues
27,218

 
9,950

 
58,882

 
29,521

Total Revenues
175,869

 
153,268

 
481,132

 
449,451

Operating Costs and Expenses:
 
 
 
 
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
26,984

 
18,319

 
58,740

 
47,845

Cost of transportation services (exclusive of depreciation and amortization shown below)
10,538

 
10,842

 
38,799

 
35,946

Operations and maintenance
17,412

 
15,146

 
45,569

 
42,374

Depreciation and amortization
23,782

 
21,177

 
67,276

 
65,074

General and administrative
16,489

 
13,981

 
46,040

 
42,863

Taxes, other than income taxes
6,661

 
6,860

 
21,799

 
20,293

Contract termination

 

 

 
8,061

(Gain) loss on disposal of assets

 

 
(1,264
)
 
1,849

Total Operating Costs and Expenses
101,866

 
86,325

 
276,959

 
264,305

Operating Income
74,003

 
66,943

 
204,173

 
185,146

Other Income (Expense):
 
 
 
 
 
 
 
Interest expense, net
(24,408
)
 
(12,157
)
 
(61,539
)
 
(31,275
)
Unrealized (loss) gain on derivative instrument

 
(4,419
)
 
1,885

 
5,588

Equity in earnings of unconsolidated investments
123,642

 
12,764

 
187,121

 
37,495

Gain on remeasurement of unconsolidated investment
9,728

 

 
9,728

 

Other income, net
454

 
480

 
796

 
1,267

Total Other Income (Expense)
109,416

 
(3,332
)
 
137,991

 
13,075

Net income before tax
183,419

 
63,611

 
342,164

 
198,221

Deferred income tax expense
(12,642
)
 
(3,209
)
 
(24,982
)
 
(12,792
)
Net income
170,777

 
60,402

 
317,182

 
185,429

Net income attributable to noncontrolling interests
(154,911
)
 
(49,750
)
 
(280,534
)
 
(163,943
)
Net income attributable to TEGP
$
15,866

 
$
10,652

 
$
36,648

 
$
21,486

Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016
Revenues. Total revenues were $175.9 million for the three months ended September 30, 2017, compared to $153.3 million for the three months ended September 30, 2016, which represents an increase of $22.6 million, or 15%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $30.7 million and $1.1 million in the Gathering, Processing & Terminalling and Natural Gas Transportation segments, respectively, partially offset by decreased revenues of $2.8 million in the Crude Oil Transportation segment, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $101.9 million for the three months ended September 30, 2017 compared to $86.3 million for the three months ended September 30, 2016, which represents an increase of $15.5 million, or 18%, in operating costs and expenses. The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $23.5 million in the Gathering, Processing & Terminalling segment, partially offset by decreased operating costs and expenses of $1.0 million and $0.5 million in the Crude Oil Transportation and Natural Gas Transportation segments, respectively, as discussed further below, as well as intersegment eliminations.

37



Interest expense, net. Interest expense of $24.4 million for the three months ended September 30, 2017 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities, the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017. Interest expense of $12.2 million for the three months ended September 30, 2016 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities, as well as the 2024 Notes issued on September 1, 2016. The increase in interest and fees, is primarily due to increased borrowings to fund a portion of our acquisitions as discussed further in Note 4 – Acquisitions, as well as the higher borrowing rate on the 2024 and 2028 Notes, the proceeds of which were used to repay borrowings under TEP's revolving credit facility.
Unrealized (loss) gain on derivative instrument. Unrealized loss on derivative instrument of $4.4 million for the three months ended September 30, 2016 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. As of February 1, 2017, no TEP common units remained subject to the call option.
Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $123.6 million and $12.8 million for the three months ended September 30, 2017 and 2016, respectively. Equity in earnings of unconsolidated investments of $123.6 million for three months ended September 30, 2017 primarily reflects our portion of earnings and the amortization of a negative basis difference of $6.6 million associated with our 49.99% membership interest in Rockies Express. During the three months ended September 30, 2017, Rockies Express recognized a $150 million gain on settlement of the Ultra litigation as discussed in Note 15Legal and Environmental Matters. Equity in earnings of unconsolidated investments of $12.8 million for the three months ended September 30, 2016 reflects our portion of earnings and the amortization of a negative basis difference of $3.5 million associated with our acquisition of a 25% membership interest in Rockies Express effective May 6, 2016, as well as $0.7 million related to our 20% membership interest in Deeprock Development during the three months ended September 30, 2016. For additional information, see Note 8 – Investments in Unconsolidated Affiliates.
Gain on remeasurement on unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.7 million for the three months ended September 30, 2017 was related to the remeasurement to fair value of our existing 20% membership interest in Deeprock Development in connection with TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017. For additional information, see Note 4 – Acquisitions.
Other income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income was $0.5 million for the three months ended September 30, 2017 and 2016.
Deferred income tax expense. Deferred income tax expense for the three months ended September 30, 2017 was $12.6 million, compared to a deferred income tax expense of $3.2 million for the three months ended September 30, 2016, which represents an increase of $9.4 million, or 294%. The increase in deferred income tax expense was driven by the increase in taxable income, primarily attributable to the increased equity in earnings associated with Rockies Express as a result of the Ultra settlement.
Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016
Revenues. Total revenues were $481.1 million for the nine months ended September 30, 2017, compared to $449.5 million for the nine months ended September 30, 2016, which represents an increase of $31.7 million, or 7%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $42.6 million and $5.8 million in the Gathering, Processing & Terminalling and Natural Gas Transportation segments, respectively, partially offset by decreased revenues of $10.1 million in the Crude Oil Transportation segment, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $277.0 million for the nine months ended September 30, 2017 compared to $264.3 million for the nine months ended September 30, 2016, which represents an increase of $12.7 million, or 5%. The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $17.0 million and $4.1 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by decreased operating costs and expenses of $4.2 million in the Natural Gas Transportation, as discussed further below, as well as a $2.4 million increase in corporate general and administrative costs primarily due to payroll taxes associated with the vesting of TEP common units associated with equity-based compensation grants under the general partner's Long-term Incentive Plan as well as new equity-based compensation grants during the nine months ended September 30, 2017.

38



Interest expense, net. Interest expense of $61.5 million for the nine months ended September 30, 2017 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities, the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017. Interest expense of $31.3 million for the nine months ended September 30, 2016 was primarily composed of interest and fees associated with our revolving credit facility and the 2024 Notes issued on September 1, 2016. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our acquisitions as discussed further in Note 4 – Acquisitions, as well as the higher borrowing rate on the 2024 and 2028 Notes, the proceeds of which were used to repay borrowings under TEP's revolving credit facility.
Unrealized (loss) gain on derivative instrument. Unrealized gain on derivative instrument of $1.9 million and $5.6 million for the nine months ended September 30, 2017 and 2016, respectively, 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. As of February 1, 2017, no TEP common units remained subject to the call option.
Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $187.1 million and $37.5 million for the nine months ended September 30, 2017 and 2016, respectively. Equity in earnings of unconsolidated investments of $187.1 million for nine months ended September 30, 2017 primarily reflects our portion of earnings and the amortization of a negative basis difference of $16.7 million associated with our 49.99% membership interest in Rockies Express, as well as $1.5 million of equity in earnings related to our 20% membership interest in Deeprock Development prior to TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017, as discussed in Note 4 – Acquisitions. During the nine months ended September 30, 2017, Rockies Express recognized the $150 million gain on settlement of the Ultra litigation as discussed in Note 15Legal and Environmental Matters. Equity in earnings of unconsolidated investments of $37.5 million for the nine months ended September 30, 2016 represents earnings associated with our acquisition of a 25% membership interest in Rockies Express effective May 6, 2016, as well as $2.1 million related to our 20% membership interest in Deeprock Development during the nine months ended September 30, 2016. For additional information, see Note 8 – Investments in Unconsolidated Affiliates.
Gain on remeasurement on unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.7 million for the nine months ended September 30, 2017 was related to the remeasurement to fair value of our existing 20% membership interest in Deeprock Development in connection with TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017. For additional information, see Note 4 – Acquisitions.
Other income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income for the nine months ended September 30, 2017 was $0.8 million compared to $1.3 million for the nine months ended September 30, 2016. The decrease in other income was driven by lower income related to reimbursable projects at TIGT due to contract modifications.
Deferred income tax expense. Deferred income tax expense for the nine months ended September 30, 2017 was $25.0 million, compared to a deferred income tax expense of $12.8 million for the nine months ended September 30, 2016, which represents an increase of $12.2 million, or 95%. The increase in deferred income tax expense was driven by the increase in taxable income, primarily attributable to the increased equity in earnings associated with Rockies Express as a result of the Ultra settlement.

39



The following provides a summary of our Natural Gas Transportation segment results of operations for the periods indicated:
Segment Financial Data - Natural Gas Transportation (1)
Three Months Ended September 30,
 
Nine Months Ended September 30,
2017
 
2016
 
2017
 
2016
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
Natural gas transportation services
$
32,139

 
$
32,871

 
$
96,140

 
$
93,598

Sales of natural gas, NGLs, and crude oil
603

 
935

 
2,793

 
1,331

Processing and other revenues
3,342

 
1,188

 
6,689

 
4,875

Total revenues
36,084

 
34,994

 
105,622

 
99,804

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
586

 
749

 
2,177

 
2,268

Cost of transportation services
1,489

 
874

 
2,731

 
4,171

Operations and maintenance
7,114

 
8,025

 
21,502

 
21,711

Depreciation and amortization
4,794

 
4,876

 
14,369

 
16,233

General and administrative
4,180

 
3,872

 
11,534

 
12,068

Taxes, other than income taxes
905

 
1,162

 
3,399

 
3,480

Total operating costs and expenses
19,068

 
19,558

 
55,712

 
59,931

Operating income
$
17,016

 
$
15,436

 
$
49,910

 
$
39,873

(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 16Reportable Segments to the accompanying condensed consolidated financial statements.
Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016
Revenues. Natural Gas Transportation segment revenues were $36.1 million for the three months ended September 30, 2017, compared to $35.0 million for the three months ended September 30, 2016, which represents an increase of $1.1 million, or 3%, in segment revenues primarily due to a $2.2 million increase in other revenues driven by an increase in the fee that NatGas receives as the operator of the Rockies Express Pipeline attributable to the Ultra settlement recognized during the three months ended September 30, 2017, as discussed in Note 14 – Legal and Environmental Matters. The increase in other revenues was partially offset by a $0.7 million decrease in natural gas transportation services driven by lower throughput volumes at TIGT and a $0.3 million decrease in natural gas sales.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $19.1 million for the three months ended September 30, 2017, compared to $19.6 million for the three months ended September 30, 2016, which represents a decrease of $0.5 million, or 3%. The overall decrease in operating costs and expenses was primarily due to a $0.9 million decrease in operations and maintenance costs due to the timing of pipeline integrity work, partially offset by a $0.6 million increase in cost of transportation services.
Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016
Revenues. Natural Gas Transportation segment revenues were $105.6 million for the nine months ended September 30, 2017, compared to $99.8 million for the nine months ended September 30, 2016, which represents an increase of $5.8 million, or 6%, in segment revenues due to a $2.5 million increase in natural gas transportation services, a $1.8 million increase in other revenue, and a $1.5 million increase in sales of natural gas. The $2.5 million increase in natural gas transportation services was driven by increased tariff rates at TIGT, partially offset by a change in the fuel recovery structure, beginning May 1, 2016 as a result of the rate case settlement discussed in Note 13 – Regulatory Matters, as well as increased throughput volumes at Trailblazer. The $1.8 million increase in other revenues was primarily due to the increase in the Rockies Express operator fee as discussed above. The $1.5 million increase in natural gas sales was driven by increased volumes sold and a 25% increase in natural gas prices during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.

40



Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $55.7 million for the nine months ended September 30, 2017, compared to $59.9 million for the nine months ended September 30, 2016, which represents a decrease of $4.2 million, or 7%. The overall decrease in operating costs and expenses was primarily due to a $1.9 million decrease in depreciation and amortization and a $1.4 million decrease in the cost of transportation services. The $1.9 million decrease in depreciation and amortization was driven by changes in depreciation rates at TIGT and the $1.4 million decrease in the cost of transportation services was driven by lower costs associated with fuel reimbursements as a result of changes to TIGT's fuel recovery structure, both as a result of the 2016 rate case settlement discussed above.
The following provides a summary of our Crude Oil Transportation segment results of operations for the periods indicated:
Segment Financial Data - Crude Oil Transportation (1)
Three Months Ended September 30,
 
Nine Months Ended September 30,
2017
 
2016
 
2017
 
2016
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
Crude oil transportation services
$
90,113

 
$
91,387

 
$
264,299

 
$
279,281

Sales of natural gas, NGLs, and crude oil
2,916

 
4,439

 
9,469

 
4,587

Total revenues
93,029

 
95,826

 
273,768

 
283,868

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
2,819

 
3,487

 
8,154

 
3,487

Cost of transportation services
11,957

 
12,939

 
39,708

 
41,586

Operations and maintenance
2,976

 
3,203

 
9,048

 
10,244

Depreciation and amortization
13,127

 
12,836

 
39,230

 
38,448

General and administrative
5,320

 
4,866

 
15,318

 
15,236

Taxes, other than income taxes
5,352

 
5,268

 
16,848

 
15,248

Total operating costs and expenses
41,551

 
42,599

 
128,306

 
124,249

Operating income
$
51,478

 
$
53,227

 
$
145,462

 
$
159,619

(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 16Reportable Segments to the accompanying condensed consolidated financial statements.
Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016
Revenues. Crude Oil Transportation segment revenues were $93.0 million for the three months ended September 30, 2017, compared to $95.8 million for the three months ended September 30, 2016, which represents a decrease of $2.8 million, or 3%, in segment revenues driven by a $1.5 million decrease in sales of crude oil primarily due to decreased volumes sold during the three months ended September 30, 2017 compared to the three months ended September 30, 2016 and a $1.3 million decrease in crude oil transportation services, primarily due to a $6.5 million increase in shipper deficiency payments that are not recognized in revenue, partially offset by a $3.6 million increase in walk-up barrels shipped and a $1.8 million increase in committed barrels shipped.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $41.6 million for the three months ended September 30, 2017 compared to $42.6 million for the three months ended September 30, 2016, which represents a decrease of $1.0 million, or 2%. The overall decrease in operating costs and expenses was primarily driven by a $1.0 million decrease in cost of transportation services driven by lower rent expense as a result of an amendment to the Deeprock Terminal lease agreement and a $0.7 million decrease in cost of sales primarily due to decreased volumes of crude oil sold during the three months ended September 30, 2017, partially offset by a $0.5 million increase in general and administrative costs.

41



Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016
Revenues. Crude Oil Transportation segment revenues were $273.8 million for the nine months ended September 30, 2017, compared to $283.9 million for the nine months ended September 30, 2016, which represents a decrease of $10.1 million, or 4%, in segment revenues driven by a $15.0 million decrease in crude oil transportation services, primarily due to a $16.8 million increase in shipper deficiency payments that are not recognized in revenue and an $8.1 million decrease in the incremental barrels delivered during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, partially offset by a $6.0 million increase in committed barrels shipped and a $3.4 million increase in walk-up barrels shipped. The decrease in crude oil transportation services was partially offset by a $4.9 million increase in sales of crude oil primarily due to increased volumes of crude oil sold during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $128.3 million for the nine months ended September 30, 2017 compared to $124.2 million for the nine months ended September 30, 2016, which represents an increase of $4.1 million, or 3%. The overall increase in operating costs and expenses was primarily driven by a $4.7 million increase in cost of sales primarily due to increased volumes of crude oil sold during the nine months ended September 30, 2017 and a $1.6 million increase in taxes, other than income taxes driven by assets placed in service throughout 2016. These increases were partially offset by a $1.9 million decrease in cost of transportation services driven by lower rent expense as a result of an amendment to the Deeprock Terminal lease agreement and higher electric costs associated with pressure restrictions during the nine months ended September 30, 2016 and reduced throughput volumes during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.
The following provides a summary of our Gathering, Processing & Terminalling segment results of operations for the periods indicated:
Segment Financial Data - Gathering, Processing & Terminalling (1)
Three Months Ended September 30,
 
Nine Months Ended September 30,
2017
 
2016
 
2017
 
2016
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
Sales of natural gas, NGLs, and crude oil
$
28,696

 
$
15,384

 
$
58,252

 
$
45,596

Processing and other revenues
29,040

 
11,646

 
63,163

 
33,222

Total revenues
57,736

 
27,030

 
121,415

 
78,818

Operating costs and expenses:
 
 
 
 
 
 
 
Cost of sales
24,120

 
14,435

 
49,148

 
42,516

Cost of transportation services
7,531

 
1,259

 
15,294

 
2,802

Operations and maintenance
7,322

 
3,918

 
15,019

 
10,419

Depreciation and amortization
5,861

 
3,465

 
13,677

 
10,393

General and administrative
3,453

 
1,672

 
7,061

 
5,842

Contract termination

 

 

 
8,061

Taxes, other than income taxes
404

 
430

 
1,552

 
1,565

(Gain) loss on disposal of assets

 

 
(1,264
)
 
1,849

Total operating costs and expenses
48,691

 
25,179

 
100,487

 
83,447

Operating income (loss)
$
9,045

 
$
1,851

 
$
20,928

 
$
(4,629
)
(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 16Reportable Segments to the accompanying condensed consolidated financial statements.

42



Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016
Revenues. Gathering, Processing & Terminalling segment revenues were $57.7 million for the three months ended September 30, 2017, compared to $27.0 million for the three months ended September 30, 2016, which represents a $30.7 million, or 114%, increase in segment revenues. The increase in segment revenues was primarily due to a $17.4 million increase in processing and other revenues and a $13.3 million increase in sales of natural gas, NGLs, and crude oil. The increase in processing and other revenues was driven by increased water business services revenue of $12.7 million as a result of increased fresh water transportation and produced water disposal volumes, increased terminalling services revenue of $2.4 million driven by the acquisition of a controlling financial interest in Deeprock Development in July 2017, and increased fee income of $2.0 million driven by the acquisition of the Douglas Gathering System in May 2017. The increase in sales of natural gas, NGLs, and crude oil was primarily driven by a 40% increase in NGL prices and residue natural gas sales from the Douglas Gathering System, partially offset by lower volumes of NGLs sold.
Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $48.7 million for the three months ended September 30, 2017 compared to $25.2 million for the three months ended September 30, 2016, which represents an increase of $23.5 million, or 93%. The increase in operating costs and expenses was due to a $9.7 million increase in cost of sales, a $6.3 million increase in cost of transportation services, a $3.4 million increase in operations and maintenance costs, a $2.4 million increase in depreciation and amortization, and a $1.8 million increase in general and administrative costs. The increase in cost of sales was primarily driven by higher producer settlements and higher NGL sales driven by prices as discussed above. The increase in cost of transportation services was primarily driven by crude oil transportation fees paid by Stanchion and increased volumes in water business services as discussed above. The increase in operations and maintenance costs, depreciation and amortization, and general and administrative costs were primarily driven by the acquisitions of the Douglas Gathering System and Deeprock Development.
Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016
Revenues. Gathering, Processing & Terminalling segment revenues were $121.4 million for the nine months ended September 30, 2017, compared to $78.8 million for the nine months ended September 30, 2016, which represents a $42.6 million, or 54%, increase in segment revenues. The increase in segment revenues was primarily due to a $29.9 million increase in processing and other revenues and a $12.7 million increase in sales of natural gas, NGLs, and crude oil. The increase in processing and other revenues was driven by increased water business services revenue of $25.1 million as a result of increased fresh water transportation and produced water disposal volumes, increased terminalling services revenue of $2.6 million driven by the acquisition of a controlling interest in Deeprock Development in July 2017, and increased fee income of $2.0 million driven by the acquisition of the Douglas Gathering System in May 2017. The increase in sales of natural gas, NGLs, and crude oil was driven by a 42% increase in NGL prices and four months of residue natural gas sales from the Douglas Gathering System, partially offset by lower volumes of NGLs sold.
Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $100.5 million for the nine months ended September 30, 2017 compared to $83.4 million for the nine months ended September 30, 2016, which represents an increase of $17.0 million, or 20%. The increase in operating costs and expenses was primarily due to a $12.5 million increase in cost of transportation services, a $6.6 million increase in cost of sales, a $4.6 million increase in operations and maintenance costs, a $3.3 million increase in depreciation and amortization, and a $1.2 million increase in general and administrative costs. The increase in cost of sales was primarily driven by higher producer settlements and higher NGL sales attributable to the Douglas Gathering System. The increase in cost of transportation services was primarily driven by crude oil transportation fees paid by Stanchion and increased volumes in water business services as discussed above. The increase in operations and maintenance costs, depreciation and amortization, and general and administrative costs were primarily driven by the acquisitions of the Douglas Gathering System and Deeprock Development. These increases were partially offset by a $8.1 million contract termination as a result of the buyout of an operating agreement at the Sterling Terminal during the nine months ended September 30, 2016 and a $3.1 million decrease in loss (gain) on disposal of assets primarily driven by a gain on disposal of assets from insurance proceeds received during the nine months ended September 30, 2017 related to assets destroyed by a fire caused by a lightning strike during the nine months ended September 30, 2016.
Liquidity and Capital Resources Overview
Our primary sources of liquidity for the three months ended September 30, 2017 were proceeds from TEP's issuance of long-term debt, borrowings under TEP's revolving credit facility, and cash generated from operations. We expect our sources of liquidity in the future to include:
cash generated from our operations;
borrowing capacity available under TEP's revolving credit facility; and
future issuances of additional TEP common units and/or debt securities.
We believe that cash on hand, cash generated from operations, and availability under TEP's 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 shareholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of borrowings under TEP's revolving credit facility and issuances of debt and/or equity securities at TEP. For additional information regarding our revolving credit facilities and senior unsecured notes, see Note 11Long-term Debt. For additional information regarding our equity transactions, see Note 12Partnership Equity and Distributions.
Our total liquidity as of September 30, 2017 and December 31, 2016 was as follows:
 
September 30, 2017
 
December 31, 2016
 
(in thousands)
Cash on hand
$
3,279

 
$
2,459

 
 
 
 
Total capacity under the TEP revolving credit facility
1,750,000

 
1,750,000

Less: Outstanding borrowings under the TEP revolving credit facility
(881,000
)
 
(1,015,000
)
Less: Letters of credit issued under the TEP revolving credit facility
(3,094
)
 

Available capacity under the TEP revolving credit facility
865,906

 
735,000

Total capacity under Tallgrass Equity revolving credit facility
$
150,000

 
$
150,000

Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility
(146,000
)
 
(148,000
)
Available capacity under the Tallgrass Equity revolving credit facility
$
4,000

 
$
2,000

Total liquidity
$
873,185

 
$
739,459

Working Capital
Working capital is the amount by which current assets exceed current liabilities. While various other factors may impact our working capital requirements from period to period, our working capital requirements have typically been, and we expect will continue to be, driven by changes in accounts receivable, accounts payable and deferred revenue. TEP manages its working capital needs through borrowings and repayments of borrowings under its revolving credit facility. 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 that we buy and sell in the normal course of business can also impact the timing of changes in accounts receivable and accounts payable. Factors impacting deferred revenue include the volume of barrels transported, the amount of deficiency payments received, and the volume of prior deficiencies utilized during the period.
As of September 30, 2017, we had a working capital deficit of $92.4 million compared to a working capital deficit of $37.7 million at December 31, 2016, which represents an increase in the working capital deficit of $54.7 million. The overall increase in the working capital deficit was primarily attributable to changes in the following components:
an increase in accounts payable of $45.2 million primarily due to crude oil purchases at Stanchion, as well as increased volumes at TMID and Water Solutions;
an increase in deferred revenue of $27.2 million primarily from deficiency payments collected by Pony Express;
a decrease in derivative assets at fair value of $11.0 million as TEP exercised the remainder of the call option granted by TD; and
an increase in accrued taxes of $5.9 million as a result of increased tax assessments on Pony Express assets placed in service during 2016.
These working capital decreases were partially offset by:
an increase in accounts receivable of $36.1 million primarily due to crude oil sales at Stanchion; and
a decrease in accrued liabilities of $5.6 million primarily due to a decrease in interest accrued at September 30, 2017 compared to December 31, 2016 due to the timing of interest payments in September 2017.
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.

43



Cash Flows
The following table and discussion presents a summary of our cash flow for the periods indicated:
 
Nine Months Ended September 30,
 
2017
 
2016
 
(in thousands)
Net cash provided by (used in):
 
 
 
Operating activities
$
450,377

 
$
306,063

Investing activities
$
(852,941
)
 
$
(559,774
)
Financing activities
$
403,384

 
$
252,836

Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016
Operating Activities. Cash flows provided by operating activities were $450.4 million and $306.1 million for the nine months ended September 30, 2017 and 2016, respectively. The increase in net cash flows provided by operating activities of $144.3 million was primarily driven by a $150.3 million increase in distributions received from Rockies Express as a result of the Ultra settlement received in July 2017 as well as our increased membership interest during the nine months ended September 30, 2017.
Investing Activities. Cash flows used in investing activities were $852.9 million for the nine months ended September 30, 2017. Investing cash outflows for the nine months ended September 30, 2017 were primarily driven by:
cash outflows of $400.0 million for the acquisition of an additional 24.99% membership interest in Rockies Express;
cash outflows of $140.0 million for the acquisition of Terminals and NatGas;
cash outflows of $128.5 million for the acquisition of the Douglas Gathering System;
capital expenditures of $88.1 million, primarily due to spending on an additional freshwater connection at Water Solutions and on a connection to a refinery complex on the Pony Express System and remediation digs on the Pony Express System as discussed in Note 15 – Legal and Environmental Matters;
cash outflows of $57.2 million for the acquisition of an additional 40% membership interest in Deeprock Development;
cash outflows of $36.0 million for the acquisition of the PRB Crude System; and
contributions to unconsolidated investments in the amount of $31.6 million, primarily to fund remaining costs associated with the Zone 3 Capacity Enhancement project at Rockies Express.
These cash outflows were partially offset by $41.9 million of distributions received from Rockies Express in excess of cumulative earnings recognized.
Cash flows used in investing activities were $559.8 million for the nine months ended September 30, 2016. Investing cash outflows for the nine months ended September 30, 2016 were primarily driven by:
cash outflows of $436.0 million for the acquisition of a 25% membership interest in Rockies Express;
capital expenditures of $55.4 million, primarily due to post in-service spending on Pony Express System projects and costs associated with construction of the Buckingham Terminal;
cash outflows of $49.1 million for a portion of the acquisition of an additional 31.3% membership interest in Pony Express, the remainder of which is classified as a financing activity as discussed below; and
contributions to Rockies Express in the amount of $35.5 million.
These cash outflows were partially offset by $16.1 million of distributions from Rockies Express in excess of cumulative earnings recognized.
Financing Activities. Cash flows provided by financing activities were $403.4 million for the nine months ended September 30, 2017. Financing cash inflows for the nine months ended September 30, 2017 were primarily driven by:
proceeds from TEP's issuance of $850.0 million in aggregate principal amount of 2024 Notes and 2028 Notes; and
net cash proceeds of $112.4 million from the issuance of 2,341,061 TEP common units under its Equity Distribution Agreements.

44



These financing cash inflows were partially offset by cash outflows of:
distributions to noncontrolling interests of $229.7 million, consisting of distributions to TEP unitholders of $135.4 million, Tallgrass Equity distributions to the Exchange Right Holders of $90.0 million, and distributions to Pony Express noncontrolling interests of $4.3 million;
net repayments under the revolving credit facilities of $136.0 million;
$72.4 million for the exercise of the remainder of the call option granted by TD covering 1,703,094 TEP common units;
$35.3 million for 736,262 TEP common units repurchased from TD; and
distributions to Class A shareholders of $52.7 million.
Cash flows provided by financing activities were $252.8 million for the nine months ended September 30, 2016. Financing cash inflows for the nine months ended September 30, 2016 were primarily driven by:
proceeds from TEP's issuance of $400.0 million in aggregate principal amount of 5.50% Senior Notes due 2024;
net cash proceeds of $290.5 million from the issuance of 6,703,984 TEP common units under its Equity Distribution Agreements;
net borrowings under the TEP revolving credit facility of $252.0 million; and
net cash proceeds of $90.0 million from TEP's issuance of 2,416,987 common units representing limited partnership interests in a private placement transaction.
These financing cash inflows were partially offset by cash outflows of:
$425.9 million for the portion of the acquisition of an additional 31.3% membership interest in Pony Express which exceeds the cumulative capital spending on the underlying assets acquired;
distributions to noncontrolling interests of $177.4 million, which consisted of distributions to TEP unitholders of $103.7 million, Tallgrass Equity distributions to the Exchange Right Holders of $68.7 million, and distributions to Pony Express noncontrolling interests of $5.0 million;
$151.4 million for the partial exercise of the call option granted by TD covering 3,563,146 TEP common units; and
distributions to Class A shareholders of $30.0 million.
Distributions
Distributions to our Class A shareholders. We distribute 100% of our available cash at the end of each quarter to Class A shareholders of record beginning with the quarter ended June 30, 2015. Our sole cash-generating asset is an approximate 36.94% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of direct and indirect partnership interests in TEP, as detailed above in "—Overview". Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter (including expected distributions from Tallgrass Equity in respect of such quarter) less reserves established at the discretion of our general partner as permitted by our partnership agreement. For a discussion of factors and trends impacting TEP's business, which in turn impacts our ability to pay cash distributions to our Class A shareholders, please see "—Factors and Trends Impacting Our Business" in our 2016 Form 10-K.
Our distribution for the three months ended September 30, 2017, in the amount of $0.3550 per Class A share, or $20.6 million in the aggregate, was announced on October 10, 2017 and will be paid on November 14, 2017 to Class A shareholders of record on October 31, 2017.
Capital Requirements
The midstream energy business can be capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of, the following:
maintenance capital expenditures, which are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements; and
expansion capital expenditures, which are cash expenditures we expect will increase our operating income or operating capacity over the long-term. Expansion capital expenditures include acquisitions or capital improvements (such as additions to or improvements on the capital assets owned, or acquisition or construction of new capital assets).

45



We expect to incur approximately $148 million for expansion capital projects and approximately $15 million, net of anticipated reimbursements, for maintenance capital expenditures in 2017.
The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:
 
Nine Months Ended September 30,
 
2017
 
2016
 
(in thousands)
Maintenance capital expenditures
$
7,746

 
$
7,085

Expansion capital expenditures
78,448

 
29,452

Total capital expenditures incurred
$
86,194

 
$
36,537

Capital expenditures incurred represent capital expenditures paid and accrued during the period. Capital expenditures are presented net of noncontrolling interest, and contributions and reimbursements received. The increase in maintenance capital expenditures to $7.7 million for the nine months ended September 30, 2017 from $7.1 million for the nine months ended September 30, 2016 is primarily driven by increased expenditures in the Natural Gas Transportation segment, partially offset by decreased expenditures in the Crude Oil Transportation segment. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. The increase in expansion capital expenditures to $78.4 million for the nine months ended September 30, 2017 is primarily driven by increased expansion capital expenditures in the Gathering, Processing & Terminalling and Crude Oil Transportation segments. Expansion capital expenditures for the nine months ended September 30, 2017 consisted primarily of spending on an additional freshwater connection at Water Solutions and on a connection to a refinery complex on the Pony Express System and remediation digs on the Pony Express System, as discussed in Note 15Legal and Environmental Matters. Expansion capital expenditures of $29.5 million for the nine months ended September 30, 2016 consisted primarily of post in-service spending on Pony Express System projects and costs associated with construction of the Buckingham Terminal.
In addition, we invested cash in unconsolidated affiliates of $31.6 million and $35.5 million during the nine months ended September 30, 2017 and 2016, respectively, to fund our share of capital projects. During the nine months ended September 30, 2017, we invested $9.1 million in a new unconsolidated affiliate, BNN Colorado Water, LLC ("BNN Colorado"). In connection with the investment in BNN Colorado, we have made commitments to fund the remaining construction of the pipeline system, estimated at $8.4 million as of September 30, 2017.
We intend to make cash distributions to our Class A shareholders. Due to our cash distribution policy, we expect that we will distribute available cash to our Class A shareholders on a quarterly basis. We expect TEP to fund future capital expenditures with funds generated from its operations, borrowings under its revolving credit facility, the issuance of additional TEP common units and/or the issuance of long-term debt. If these sources are not sufficient, TEP may reduce its discretionary spending.
Contractual Obligations
There have been no material changes in our contractual obligations as reported in our 2016 Form 10-K.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our 2016 Form 10-K for the year ended December 31, 2016 and have not changed.

46



Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Prior to our acquisition of the Douglas Gathering System on June 5, 2017, approximately 99% of our reserved processing capacity was subject to firm or volumetric fee contracts, with the majority of fee revenue based on the volumes actually processed. With our acquisition of the Douglas Gathering System, the largest existing firm fee contract was terminated because the counterparty to this contract, DCP Douglas, LLC, became our indirect wholly-owned subsidiary. In addition, we acquired a number of commodity sensitive gathering and processing contracts such as percent of proceeds or keep whole processing contracts in the acquisition. For the three months ended September 30, 2017, approximately 81% of our gathering and processing volumes were subject to firm or volumetric fee contracts, with the majority of fee revenue based on the volumes actually processed. The remaining 19% was subject to commodity sensitive contracts such as percent of proceeds or keep whole processing contracts. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. 
Our Gathering, Processing & Terminalling segment comprised approximately 10% and 3% of our operating income for the nine months ended September 30, 2017 and 2016, respectively. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. Starting in the second half of 2014, the prices of crude oil, natural gas, and NGLs became extremely volatile and declined significantly. Downward pressure and volatility of commodity prices continued in 2015 before recovering somewhat in 2016 and 2017. These declines directly and indirectly resulted in lower realizations and processing volumes on our percent of proceeds and keep whole processing contracts.
Historically, we have had a limited amount of direct commodity price exposure related to natural gas collected for electrical compression costs and lost and unaccounted for gas on the TIGT System. Accordingly, we have historically entered into derivative contracts with third parties for a substantial majority of the natural gas we expected to collect for the purpose of hedging our commodity price exposures. In 2016, we also entered into long natural gas swaps covering a portion of the natural gas that TMID expects to purchase in 2017. In addition, we have a limited amount of direct commodity price exposure related to crude oil collected as part of our contractual pipeline loss allowance at Pony Express and Terminals. During 2016, we began entering into derivative contracts for the sale of crude oil inventory. In 2017, Stanchion began to transact in crude oil and enter into financial derivative contracts in connection with these transactions.
We measure the risk of price changes in our crude oil and natural gas derivatives utilizing a sensitivity analysis model. The sensitivity analysis measures the potential income or loss (i.e., the change in fair value of the derivative instruments) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. We enter into derivative contracts primarily for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, both the sensitivity analysis model and the change in the market value of our outstanding derivative contracts are offset largely by changes in the value of the underlying physical commodity prices.
The following table summarizes our commodity derivatives and the change in fair value that would be expected from a 10% price increase or decrease as of September 30, 2017, assuming a parallel shift in the forward curve through the end of 2017:
 
Fair Value
 
Effect of 10% Price Increase
 
Effect of 10% Price Decrease
 
(in thousands)
Natural gas derivative contracts (1)
$
1

 
$
29

 
$
(29
)
Crude oil derivative contracts (2)
$
472

 
$
(875
)
 
$
875

(1) 
Represents long natural gas swaps outstanding with a notional volume of approximately 0.1 Bcf covering a portion of the natural gas that is expected to be purchased by our Gathering, Processing & Terminalling segment throughout 2017.
(2) 
Represents the purchase and sale of 323,620 barrels of crude oil by our Gathering, Processing & Terminalling segment which will settle throughout 2017 and the first quarter of 2018.

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The Commodity Futures Trading Commission ("CFTC") has promulgated regulations to implement the Dodd-Frank Wall Street Reform and Consumer Protection Act's changes to the Commodity Exchange Act, including the definition of commodity-based swaps subject to those regulations. The CFTC regulations implemented new reporting and record keeping requirements related to those swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate that most, if not all, of our swap transactions should continue to qualify for an exemption to the clearing and exchange-execution requirements, we will still be subject to record keeping and reporting requirements.
Interest Rate Risk
As described in Note 11Long-term Debt, Tallgrass Equity currently has $146 million in outstanding borrowings under its revolving credit facility. Borrowings under the credit facility bear interest, at Tallgrass Equity's option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin is 1.50%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is 2.50%.
As of September 30, 2017, TEP has issued $750 million of 2024 Notes and $500 million of 2028 Notes. In addition, TEP currently has a $1.75 billion revolving credit facility with borrowings of approximately $881.0 million as of September 30, 2017. Borrowings under the revolving credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. During the three months ended September 30, 2017, for borrowings bearing interest based on the base rate, the applicable margin was 0.75%, and for borrowings bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin was 1.75%. For periods after September 30, 2017, the applicable margin will range from 0.50% to 1.50% for base rate borrowings and 1.50% to 2.50% for reserve adjusted Eurodollar rate borrowings, based upon our total leverage ratio.
We do not currently hedge the interest rate risk on our borrowings under the revolving credit facilities. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the debt by $0.5 million based on our outstanding debt under our revolving credit facilities as of September 30, 2017.
Credit Risk
We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through a credit approval process which includes credit analysis, the establishment of credit limits and ongoing monitoring procedures. We may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support.
A substantial majority of our revenue is produced under long-term firm fee contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with a majority of our revenues derived from customers who have BB+ or Ba1 and better credit ratings or are part of corporate families with such credit ratings as of September 30, 2017.
We also have indirect credit risk exposure with respect to our investment in Rockies Express. See Item 1A.Risk Factors in our 2016 Form 10-K for additional information.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a- 15(e) or Rule 15d- 15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

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Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

49



PART II - OTHER INFORMATION
Item 1. Legal Proceedings
See Note 15Legal and Environmental Matters to the condensed consolidated financial statements included in Part I—Item 1.—Financial Statements of this Quarterly Report, which is incorporated herein by reference.
Item 1A. Risk Factors
Item 1A of our 2016 Form 10-K sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended September 30, 2017. There have been no material changes to the risk factors contained in our 2016 Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
None.
Item 6. Exhibits
Exhibit No.
 
Description
 
 
 
 
 
 
 
 


 
 
 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.INS*
 
XBRL Instance Document.
 
 
 
101.SCH*
 
XBRL Taxonomy Extension Schema Document.
 
 
 
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
 
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
 
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase Document.
 
 
 
101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document.
* -
filed herewith
†  - Management contract of compensatory plan or arrangement required to be filed as an exhibit to this Form 10-Q pursuant to Item 6.

50



SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
Tallgrass Energy GP, LP
 
 
 
(registrant)
 
 
 
By:
TEGP Management, LLC, its general partner
 
 
 
 
 
 
 
 
Date:
November 2, 2017
By:
/s/ Gary J. Brauchle
 
 
 
 
 
Name:
Gary J. Brauchle
 
 
 
 
 
Title:
Executive Vice President and Chief Financial Officer
 
 
 
 
 
(Duly Authorized Officer and Principal Financial Officer)


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