10-Q 1 tge201893010q.htm 10-Q Document


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, 2018
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-37365
 
 
 
 
 Tallgrass Energy, LP
(Exact name of registrant as specified in its charter)
 
 
 
Delaware
 
 
 
47-3159268
(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 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, a 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.
Large accelerated filer
 
x
 
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
¨ 
 
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 October 31, 2018, the Registrant had 156,308,654 Class A shares and 123,887,893 Class B shares outstanding.




TALLGRASS ENERGY, 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: the United States 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: accounting principles generally accepted 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, 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.
NYSE: New York Stock 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, LP
CONDENSED CONSOLIDATED BALANCE SHEETS 
(UNAUDITED)
 
September 30, 2018
 
December 31, 2017
 
(in thousands)
ASSETS
 
Current Assets:
 
 
 
Cash and cash equivalents
$
5,521

 
$
2,593

Accounts receivable, net
235,700

 
118,615

Receivable from related parties
3,369

 
1,340

Inventories
29,317

 
21,609

Prepayments and other current assets
16,344

 
13,165

Total Current Assets
290,251

 
157,322

Property, plant and equipment, net
2,662,055

 
2,394,337

Goodwill
404,838

 
404,838

Intangible assets, net
132,826

 
97,731

Unconsolidated investments
1,872,879

 
909,531

Deferred financing costs, net
11,778

 
12,563

Deferred tax asset
291,886

 
312,997

Deferred charges and other assets
3,527

 
2,694

Total Assets
$
5,670,040

 
$
4,292,013

LIABILITIES AND EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts payable
$
223,148

 
$
98,882

Accounts payable to related parties

 
5,342

Accrued taxes
25,437

 
19,272

Accrued interest
12,523

 
25,167

Accrued liabilities
18,032

 
10,540

Deferred revenue
103,652

 
88,471

Other current liabilities
14,409

 
11,202

Total Current Liabilities
397,201

 
258,876

Long-term debt, net
3,033,674

 
2,292,993

Other long-term liabilities and deferred credits
20,117

 
18,965

Total Long-term Liabilities
3,053,791

 
2,311,958

Commitments and Contingencies

 

Equity:
 
 
 
Class A Shareholders (155,887,756 and 58,085,002 shares outstanding at September 30, 2018 and December 31, 2017, respectively)
1,738,245

 
48,613

Class B Shareholders (124,305,459 and 99,154,440 shares outstanding at September 30, 2018 and December 31, 2017, respectively)

 

Total Partners' Equity
1,738,245

 
48,613

Noncontrolling interests (a)
480,803

 
1,672,566

Total Equity
2,219,048

 
1,721,179

Total Liabilities and Equity
$
5,670,040

 
$
4,292,013

(a) 
See Note 11 - Partnership Equity for a complete description of our noncontrolling interests.

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



TALLGRASS ENERGY, LP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except per unit amounts)
Revenues:
 
 
 
 
 
 
 
Crude oil transportation services
$
100,226

 
$
86,180

 
$
286,130

 
$
260,366

Natural gas transportation services
30,953

 
30,256

 
94,623

 
91,370

Sales of natural gas, NGLs, and crude oil
44,072

 
32,215

 
119,467

 
70,514

Processing and other revenues
25,069

 
27,218

 
72,783

 
58,882

Total Revenues
200,320


175,869


573,003


481,132

Operating Costs and Expenses:
 
 
 
 
 
 
 
Cost of sales
28,556

 
26,984

 
82,601

 
58,740

Cost of transportation services
12,588

 
10,538

 
35,672

 
38,799

Operations and maintenance
18,011

 
17,412

 
52,850

 
45,569

Depreciation and amortization
27,595

 
23,782

 
81,408

 
67,276

General and administrative
16,015

 
16,489

 
53,526

 
46,040

Taxes, other than income taxes
7,750

 
6,661

 
25,091

 
21,799

Gain on disposal of assets
(279
)
 

 
(9,417
)
 
(1,264
)
Total Operating Costs and Expenses
110,236


101,866


321,731


276,959

Operating Income
90,084


74,003


251,272


204,173

Other Income (Expense):
 
 
 
 
 
 
 
Equity in earnings of unconsolidated investments
76,268

 
123,642

 
222,857

 
187,121

Interest expense, net
(34,019
)
 
(24,408
)
 
(95,062
)
 
(61,539
)
Other (expense) income, net
(1,624
)
 
10,182

 
(843
)
 
12,409

Total Other Income (Expense)
40,625


109,416


126,952


137,991

Net income before tax
130,709


183,419


378,224


342,164

Deferred income tax expense
(11,997
)
 
(12,642
)
 
(35,498
)
 
(24,982
)
Net income
118,712


170,777


342,726


317,182

Net income attributable to noncontrolling interests
(59,162
)
 
(154,911
)
 
(265,378
)
 
(280,534
)
Net income attributable to TGE
$
59,550


$
15,866


$
77,348


$
36,648

Net income per Class A share:
 
 
 
 
 
 
 
Basic net income per Class A share
$
0.38

 
$
0.27

 
$
0.85

 
$
0.63

Diluted net income per Class A share
$
0.38

 
$
0.27

 
$
0.85

 
$
0.63

Basic average number of Class A shares outstanding
155,001

 
58,075

 
91,183

 
58,075

Diluted average number of Class A shares outstanding
156,088

 
58,192

 
92,661

 
58,193




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



TALLGRASS ENERGY, 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, 2018
$

 
$
48,613

 
$

 
$
1,672,566

 
$
1,721,179

Cumulative effect of ASC 606 implementation

 
4,588

 

 
39,543

 
44,131

Net income

 
77,348

 

 
265,378

 
342,726

Dividends paid to Class A shareholders

 
(126,714
)
 

 

 
(126,714
)
Noncash compensation expense

 
2,378

 

 
3,197

 
5,575

Acquisition of additional TEP common units from TD

 
(62,223
)
 

 
(189,520
)
 
(251,743
)
Issuance of Tallgrass Equity units

 

 

 
644,782

 
644,782

Acquisition of 25.01% membership interest in Rockies Express

 
34,116

 

 
74,421

 
108,537

Acquisition of additional 2% membership interest in Pony Express

 
(5,268
)
 

 
(44,732
)
 
(50,000
)
Consolidation of Deeprock North

 

 

 
31,843

 
31,843

Contributions from noncontrolling interest

 

 

 
183

 
183

Distributions to noncontrolling interest

 


 

 
(262,856
)
 
(262,856
)
Issuance of TEP common units to the public, net of offering costs

 
(98
)
 

 
(279
)
 
(377
)
TEP LTIP units tendered by employees to satisfy tax withholding obligations

 
(190
)
 

 
(1,531
)
 
(1,721
)
Conversion of Class B shares to Class A shares

 
(10,135
)
 

 
10,135

 

Deferred tax asset

 
13,503

 

 

 
13,503

Acquisition of additional TEP common units

 
(351,431
)
 

 
(1,762,327
)
 
(2,113,758
)
Issuance of Class A shares

 
2,113,758

 

 

 
2,113,758

Balance at September 30, 2018
$

 
$
1,738,245

 
$

 
$
480,803

 
$
2,219,048

 
 
 
 
 
 
 
 
 
 
 
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 common units to the public, net of offering costs

 
11,350

 

 
101,043

 
112,393

Dividends paid 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

Contributions from TD

 
850

 

 
1,451

 
2,301

Contributions from noncontrolling interest

 

 

 
1,093

 
1,093

Distributions to noncontrolling interest

 

 

 
(229,710
)
 
(229,710
)
Acquisition of noncontrolling interests

 
669

 

 
(7,109
)
 
(6,440
)
Balance at September 30, 2017
$


$
234,241


$


$
1,683,514


$
1,917,755


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



TALLGRASS ENERGY, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
Nine Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Cash Flows from Operating Activities:
 
 
 
Net income
$
342,726

 
$
317,182

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
86,121

 
73,087

Equity in earnings of unconsolidated investments
(222,857
)
 
(187,121
)
Distributions from unconsolidated investments
222,082

 
187,624

Deferred income tax expense
35,498

 
24,982

Other noncash items, net
(4,681
)
 
(6,772
)
Changes in components of working capital:
 
 
 
Accounts receivable and other
(115,330
)
 
(34,189
)
Accounts payable and accrued liabilities
104,920

 
42,680

Deferred revenue
14,265

 
26,898

Other current assets and liabilities
1,682

 
5,032

Other operating, net
1,965

 
974

Net Cash Provided by Operating Activities
466,391


450,377

Cash Flows from Investing Activities:
 
 
 
Contributions to unconsolidated investments
(444,788
)
 
(31,570
)
Capital expenditures
(265,073
)
 
(88,050
)
Acquisition of BNN North Dakota, net of cash acquired
(95,000
)
 

Distributions from unconsolidated investments in excess of cumulative earnings
60,720

 
41,886

Sale of Tallgrass Crude Gathering
50,046

 

Acquisition of Pawnee membership interest
(30,600
)
 

Acquisition of 38% membership interest in Deeprock North
(19,500
)
 

Acquisition of Rockies Express membership interest

 
(400,000
)
Acquisition of Terminals and NatGas

 
(140,000
)
Acquisition of Douglas Gathering System

 
(128,526
)
Acquisition of Deeprock Development

 
(57,202
)
Acquisition of PRB Crude System

 
(36,030
)
Other investing, net
(12,304
)
 
(13,449
)
Net Cash Used in Investing Activities
(756,499
)

(852,941
)
Cash Flows from Financing Activities:
 
 
 
Proceeds from issuance of long-term debt
500,000

 
850,000

Distributions to noncontrolling interests
(262,856
)
 
(229,710
)
Borrowings (repayments) under revolving credit facilities, net
244,000

 
(136,000
)
Dividends paid to Class A shareholders
(126,714
)
 
(52,704
)
Acquisition of Pony Express membership interest
(50,000
)
 

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

 
112,393

Partial exercise of call option

 
(72,381
)
Repurchase of TEP common units from TD

 
(35,335
)
Other financing, net
(11,394
)
 
(32,879
)
Net Cash Provided by Financing Activities
293,036


403,384

Net Change in Cash and Cash Equivalents
2,928

 
820

Cash and Cash Equivalents, beginning of period
2,593

 
2,459

Cash and Cash Equivalents, end of period
$
5,521

 
$
3,279


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



Schedule of Noncash Investing and Financing Activities:
 
 
 
Acquisition of additional TEP common units (a)(b)
$
(2,365,501
)
 
$

Issuance of Class A shares (a)
$
2,113,758

 
$

Issuance of Tallgrass Equity units (b)
$
644,782

 
$

Acquisition of Rockies Express membership interest (b)
$
(393,039
)
 
$

Contribution of 38% membership interest in Deeprock North to Deeprock Development
$
(19,500
)
 
$

Issuance of noncontrolling interests in Deeprock Development in exchange for 62% membership interest in Deeprock North
$
(31,843
)
 
$

Increase in accrual for payment of property, plant and equipment
$
8,517

 
$
1,342

TEP common units issued as partial consideration to acquire additional 9% membership interest in Deeprock Development
$

 
$
6,617

(a) 
Represents the acquisition of additional TEP common units in exchange for Class A shares associated with the Merger Agreement as discussed in Note 1Description of Business.
(b) 
Represents the issuance of Tallgrass Equity units associated with our acquisition of a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units as discussed in Note 3Acquisitions and Dispositions.

The accompanying notes are an integral part of these condensed consolidated financial statements.
5



TALLGRASS ENERGY, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. Description of Business
Tallgrass Energy, LP ("TGE"), formerly known as Tallgrass Energy GP, LP, is a limited partnership that owns, operates, acquires and develops midstream energy assets in North America and has elected to be treated as a corporation for U.S. federal income tax purposes. "We," "us," "our" and similar terms refer to TGE together with its consolidated subsidiaries.
Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity, LLC ("Tallgrass Equity"), in which we directly own an approximate 55.64% membership interest as of September 30, 2018. We 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 an integrated natural gas storage facility;
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 and processing facilities; crude oil storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs.
Natural Gas Transportation. We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 75% 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"), and our 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas"), 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. We provide crude oil transportation to customers in Wyoming, Colorado, Kansas, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated crude oil pipeline commencing in both Guernsey, Wyoming and Weld County, Colorado and terminating in Cushing, Oklahoma (the "Pony Express System"). In the second quarter of 2018, Pony Express placed into service an extension of the system from an additional origin point in Weld County, Colorado located near Platteville, Colorado.
Gathering, Processing & Terminalling. We provide 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"), (2) natural gas processing facilities in Casper and Douglas, and (3) a natural gas treating facility at West Frenchie Draw. We also provide NGL transportation services in Northeast Colorado and Wyoming. We perform water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, Wyoming, and North Dakota through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals"), which owns and operates crude oil terminals in Colorado, Oklahoma, and Kansas. The Gathering, Processing & Terminalling segment also includes 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. 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.

6



Merger Agreement with Tallgrass Energy Partners, LP
TGE previously entered into a definitive Agreement and Plan of Merger, dated as of March 26, 2018 (the "Merger Agreement"), with Tallgrass Equity, Tallgrass Energy Partners, LP, a Delaware limited partnership ("TEP"), Tallgrass MLP GP, LLC, a Delaware limited liability company and the general partner of TEP ("TEP GP"), and Razor Merger Sub, LLC, a Delaware limited liability company. The merger transaction contemplated by the Merger Agreement (the "TEP Merger") was completed effective June 30, 2018, and as a result, 47,693,097 TEP common units held by the public were converted into the right to receive Class A shares of TGE at an exchange ratio of 2.0 Class A shares for each outstanding TEP common unit, TEP's incentive distribution rights were cancelled, TEP's common units are no longer publicly traded, and 100% of TEP's equity interests are now owned by Tallgrass Equity and its subsidiaries. The TEP Merger was accounted for as an acquisition of noncontrolling interest. Following consummation of the TEP Merger, TGE changed its name from "Tallgrass Energy GP, LP" to "Tallgrass Energy, LP" and began trading on the New York Stock Exchange under the ticker symbol "TGE" on July 2, 2018.
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, 2018 and 2017 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of accounting principles generally accepted 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, 2018 and 2017 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, 2018 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2018. 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, 2017 ("2017 Form 10-K") filed with the SEC on February 13, 2018.
The condensed consolidated financial statements include the accounts of TGE 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 TGE is attributed to TGE and noncontrolling interests in accordance with the respective ownership interests.
A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Our consolidated VIEs did not have material assets that could only be used to settle specific obligations of the consolidated VIEs. Prior to June 29, 2018, both Tallgrass Equity and TEP were considered to be VIEs under the applicable authoritative guidance and included in our consolidated results. As a result of the TEP Merger, and changes in ownership and their respective partnership arrangements, Tallgrass Equity and TEP are no longer considered to be VIEs. We continue to consolidate our membership interests in Tallgrass Equity and TEP through the voting interest model.

7



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
Revenue Recognition
In May 2014, the FASB issued Accounting Standards Update ("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.
Management completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. 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 members' equity. Consolidated revenues presented in the comparative consolidated financial statements for periods prior to January 1, 2018 have not been revised.
On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million, increased the carrying amount of our investment in Rockies Express by $42.8 million, and recognized a receivable from Rockies Express of $1.3 million. These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of ASC 606. The cumulative effect adjustment at Rockies Express arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas during the periods prior to implementation.
Through our review process, we also identified the following changes to our revenue recognition policies that did not result in a cumulative effect adjustment on January 1, 2018:
Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas will be accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees previously recognized in revenue will be reported as a reduction to cost of sales under ASC 606.
Pipeline Loss Allowance. We have determined that pipeline loss allowance, or PLA, collected under certain crude oil transportation arrangements is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue stream to Pony Express. Under ASC 606, PLA barrels retained from customers will be subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value.
See Note 12 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and 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.

8



Accounting Pronouncements Not Yet Adopted
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.
Management is currently evaluating the impact of our pending adoption of ASC 842. The status of our implementation is as follows:
Management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status.
Management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts.
Management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process.
Management plans to provide internal training and awareness related to the revised guidance to the key stakeholders throughout its organization.
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 plan to adopt ASU 2016-02 on January 1, 2019 using the modified retrospective method. ASC 842 provides for a number of practical expedients. We intend to elect the following practical expedients upon adoption of ASC 842:
An entity need not reassess whether any expired or existing contracts are or contain leases.
An entity need not reassess the lease classification for any expired or existing leases.
An entity need not reassess initial direct costs for any existing leases.
An entity may elect to not assess whether existing or expired land easements that were not previously accounted for as leases are or contain a lease under ASC 842.
While we are still in the process of quantifying the impact of adoption, we do not currently expect the adoption to have a material impact. We expect to recognize a right of use asset and lease liability at the implementation date, but we cannot reasonably estimate the full impact of the standard at this time. 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 lease guidance.
3. Acquisitions and Dispositions
Acquisition of Pawnee
On January 2, 2018, we entered into an agreement to acquire a 51% membership interest in the Pawnee, Colorado crude oil terminal ("Pawnee") from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $30.6 million. The transaction closed on April 1, 2018. As the 51% membership interest does not represent a controlling interest in Pawnee, our investment in Pawnee is recorded under the equity method of accounting and reported as "Unconsolidated investments" on the condensed consolidated balance sheets.
Acquisition of an Additional 25.01% Membership Interest in Rockies Express and Additional TEP Common Units
In February 2018, Tallgrass Development, LP ("TD") merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity ("Tallgrass Development Holdings"), and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Equity issued 27,554,785 unregistered TGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of TD. Subsequent to the closing of the transaction, our aggregate membership interest in Rockies Express is 75%.

9



The transfer of the Rockies Express membership interest between TD and Tallgrass Equity is considered a transaction between entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed contribution representing the excess carrying value of the 25.01% membership interest in Rockies Express acquired over the fair value of the consideration paid. For further discussion, see Note 11 - Partnership Equity. As the aggregate 75% membership interest does not represent a controlling interest in Rockies Express, TGE'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 25.01% membership interest in Rockies Express was transferred to Tallgrass Equity at TD's historical carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the investment and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD. For additional information, see Note 7 - Investments in Unconsolidated Affiliates.
The acquisition of an additional 5,619,218 TEP common units is considered an acquisition of noncontrolling interest and resulted in the recognition of a noncash deemed distribution representing the excess purchase price over the $53.8 million carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018. For further discussion, see Note 11 - Partnership Equity.
As of February 7, 2018, the negative basis difference in Rockies Express carried over from TD was approximately $376.5 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. At September 30, 2018, the basis difference for our membership interests in Rockies Express was allocated as follows:
 
Basis Difference
 
Amortization Period
 
(in thousands)
 
 
Long-term debt
$
48,019

 
2 - 25 years
Property, plant and equipment
(1,156,562
)
 
35 years
Total basis difference
$
(1,108,543
)
 
 
Sale of Tallgrass Crude Gathering
In February 2018, we entered into an agreement with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to sell our 100% membership interest in Tallgrass Crude Gathering, LLC ("TCG"), which owns a 50-mile crude oil gathering system in the Powder River Basin, for approximately $50.0 million. The sale of TCG closed on February 23, 2018. During the nine months ended September 30, 2018, we recognized a gain of $9.4 million on the sale which is presented in the line item "Gain on disposal of assets" in the condensed consolidated statements of income.
Joint Venture with Silver Creek
In February 2018, we entered into an agreement with Silver Creek to form Iron Horse Pipeline, LLC ("Iron Horse"), a new joint venture pipeline to transport crude oil from the Powder River Basin. During the nine months ended September 30, 2018, we contributed an initial $3.5 million and committed to funding our proportionate share of the remaining costs of construction in exchange for a 75% membership interest in Iron Horse. As the 75% membership interest does not represent a controlling interest in Iron Horse, our investment in Iron Horse is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the condensed consolidated balance sheets.
In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the contribution by us and Silver Creek of additional Powder River Basin assets. Upon the closing of the additional contributions, the expanded joint venture will operate under the name Powder River Gateway, LLC, and will own the Iron Horse pipeline, the Powder River Express Pipeline, and crude oil terminal facilities in Guernsey, Wyoming. We will own a 51% membership interest and continue to operate the joint venture following closing, and Silver Creek will own a 49% membership interest. We expect to close the additional contributions in the fourth quarter of 2018, subject to certain closing conditions.
Acquisition of Additional 2% Membership Interest in Pony Express
In February 2018, we acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from TD for cash consideration of approximately $60 million, bringing our aggregate membership interest in Pony Express to 100%. The acquisition of the remaining 2% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction has not been recast to reflect the additional 2% membership interest.

10



Acquisition of BNN North Dakota
In January 2018, we acquired 100% of the membership interests in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC, which were subsequently merged and renamed BNN North Dakota, LLC ("BNN North Dakota"), for approximately $95.0 million, net of cash acquired. BNN North Dakota owns a produced water gathering and disposal system in the Bakken basin with approximately 133,000 acres under dedication. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.
The following represents the fair value of assets acquired and liabilities assumed (in thousands):
Accounts receivable
$
2,457

 
Inventory
67

 
Property, plant and equipment
48,900

 
Intangible asset
46,800

(1) 
Accounts payable and accrued liabilities
(3,224
)
 
Net identifiable assets acquired (excluding cash)
$
95,000

 
(1) 
The $46.8 million intangible asset acquired represents three major customer relationships. This intangible asset is amortized on a straight-line basis over a period of 8 - 14 years, the remaining terms of the underlying contracts at the time of acquisition.
At March 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2018. Actual revenue and net income attributable to TGE from BNN North Dakota of $13.3 million and $2.9 million, respectively, was recognized in the accompanying condensed consolidated statements of income for the period from January 12, 2018 to September 30, 2018.
Pro Forma Financial Information
Unaudited pro forma revenue and net income attributable to TGE for the nine months ended September 30, 2018 and 2017 is presented below as if the acquisition of BNN North Dakota had been completed on January 1, 2017.
 
Nine Months Ended September 30,
 
2018
 
2017
 
(in thousands)
Revenue
$
573,431

 
$
488,076

Net income attributable to TGE
$
77,374

 
$
36,384

The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TGE would have been if the transaction had in fact occurred on the date or for the period indicated, nor does it purport to project the results of operations or financial position of TGE 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 transaction or the costs to achieve these cost savings, operating synergies, and revenue enhancements.
Acquisition of Deeprock North and Merger with Deeprock Development
In January 2018, we acquired an approximate 38% membership interest in Deeprock North, LLC ("Deeprock North") from Kinder Morgan Deeprock North Holdco LLC for cash consideration of $19.5 million. Immediately following the acquisition, Deeprock North was merged into Deeprock Development, LLC ("Deeprock Development"), and the members of Deeprock North and Deeprock Development received adjusted membership interests in the combined entity. As a result, we recognized additional noncontrolling interests in Deeprock Development of $31.8 million. The acquisition of Deeprock North by Deeprock Development 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. After the acquisition and merger, we own an approximate 60% membership interest in the combined entity.
4. Related Party Transactions
As a result of our relationship with Tallgrass Energy Holdings, LLC ("Tallgrass Energy Holdings") 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.

11



All of our employees are employed by Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018, Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings. In connection with the closing of the TEP initial public offering on May 17, 2013, TEP and TEP GP entered into an Omnibus Agreement with Tallgrass Energy Holdings and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse Tallgrass Energy Holdings 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 Tallgrass Energy Holdings and its affiliates, 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 the TGE initial public offering on May 12, 2015 (the "TGE IPO"), TGE entered into an Omnibus Agreement (the "TGE Omnibus Agreement") with Tallgrass Energy GP, LLC (formerly known as TEGP Management, LLC), Tallgrass Equity and Tallgrass Energy Holdings.
Effective July 1, 2018, Tallgrass Management was contributed to Tallgrass Equity in connection with the TEP Merger. As a result, the costs of employer and director compensation and benefits are now incurred directly by Tallgrass Equity.
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,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Processing and other revenues (1)
$
1,838

 
$
3,338

 
$
5,603

 
$
6,662

Cost of transportation services (2)
$

 
$
1,062

 
$

 
$
10,476

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

 
$
765

 
$

 
$
1,568

Operations and maintenance
$

 
$
7,973

 
$

 
$
21,680

General and administrative
$

 
$
11,960

 
$

 
$
32,628

(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.
(3) 
Charges to TGE, inclusive of Tallgrass Equity and TEP, include indirectly charged wages and salaries, other compensation and benefits, and shared services for periods prior to January 1, 2018. Effective January 1, 2018, these costs are incurred by TEP directly and, in the case of certain employee compensation and benefits, paid on TEP's behalf by its affiliate, Tallgrass Management, LLC, pursuant to the TEP Omnibus Agreement.
Details of balances with affiliates included in "Receivable from related parties" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows:
 
September 30, 2018
 
December 31, 2017
 
(in thousands)
Receivable from related parties:
 
 
 
Rockies Express Pipeline LLC
$
3,152

 
$
1,340

Iron Horse Pipeline, LLC
112

 

Pawnee Terminal, LLC
105

 

Total receivable from related parties
$
3,369

 
$
1,340

Accounts payable to related parties:
 
 
 
Tallgrass Operations, LLC (1)
$

 
$
5,342

Total accounts payable to related parties
$

 
$
5,342

(1) 
Reflects accounts payable for charges to TGE, inclusive of Tallgrass Equity and TEP, including indirectly charged wages and salaries, other compensation and benefits, and shared services prior to January 1, 2018 as discussed above.

12



Gas imbalances with affiliated shippers are as follows:
 
September 30, 2018
 
December 31, 2017
 
(in thousands)
Affiliate gas imbalance receivables
$
17

 
$
18

Affiliate gas imbalance payables
$
689

 
$
442

5. Inventory
The components of inventory at September 30, 2018 and December 31, 2017 consisted of the following:
 
September 30, 2018
 
December 31, 2017
 
(in thousands)
Crude oil
$
18,893

 
$
12,792

Materials and supplies
6,359

 
5,891

Natural gas liquids
364

 
942

Gas in underground storage
3,701

 
1,984

Total inventory
$
29,317

 
$
21,609

6. Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
 
September 30, 2018
 
December 31, 2017
 
(in thousands)
Crude oil pipelines
$
1,290,868

 
$
1,220,379

Gathering, processing and terminalling assets (1)
791,766

 
675,092

Natural gas pipelines
612,729

 
581,400

General and other
125,261

 
98,680

Construction work in progress
198,356

 
97,978

Accumulated depreciation and amortization
(356,925
)
 
(279,192
)
Total property, plant and equipment, net
$
2,662,055

 
$
2,394,337

(1) 
Includes approximately $46.2 million and $40.1 million of assets associated with the acquisitions of Deeprock North and BNN North Dakota, respectively, in January 2018.
7. Investments in Unconsolidated Affiliates
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, 2018, we recognized equity in earnings associated with our aggregate 75% membership interest in Rockies Express of $220.3 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $278.1 million and $420.3 million, respectively. As discussed in Note 3Acquisitions and Dispositions, we acquired an additional 25.01% membership interest in Rockies Express in February 2018.
In July 2018, we made a special contribution of approximately $412.5 million to fund our portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018.

13



Summarized financial information for Rockies Express is as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
Revenue
$
225,753

 
$
216,756

 
$
683,426

 
$
625,243

Operating income
$
127,119

 
$
123,965

 
$
385,831

 
$
344,037

Net income to Members
$
90,707

 
$
233,990

 
$
270,338

 
$
371,185

8. 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,
 
2018
 
2017
 
Natural Gas Transportation
 
Gathering, Processing & Terminalling
 
Total
 
Natural Gas Transportation
 
Gathering, Processing & Terminalling
 
Total
 
(in thousands)
Balance at beginning of period
$
255,558

 
$
149,280

 
$
404,838

 
$
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

 
$
149,280

 
$
404,838

(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.
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. 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. 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 elected to apply the qualitative assessment option for four of our five reporting units. In conducting the qualitative assessment we considered relevant factors and circumstances that affect the fair value or carrying amount of the reporting entity. Such factors included changes in discount rates, projected cash flows, macroeconomic considerations, industry and market considerations, overall financial performance, prior quantitative results, and entity and reporting unit specific events. For each of these reporting units, the results of the qualitative assessment indicated that it was more likely than not that the fair value of the reporting units exceeded their respective book values. As such, we did not perform a quantitative impairment analysis, and we concluded that no impairment was indicated as of August 31, 2018.

14



We did not elect to apply the qualitative assessment option for one reporting unit during our 2018 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. We compared the fair value of the reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. The fair value of the reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates, maintenance capital expenditures, and the weighted average cost of capital. The fair value of the reporting unit was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For this reporting unit, the results of the quantitative impairment test indicated no impairment as the fair value of the reporting unit was greater than its respective book value. As a result, in accordance with the Codification guidance, we did not record a goodwill impairment during the nine months ended September 30, 2018. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow model 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.
9. 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, 2018
 
December 31, 2017
 
 
 
(in thousands)
Crude oil derivative contracts (1)
Current assets
 
$
6,014

 
$

Crude oil derivative contracts (2)
Current liabilities
 
$
4,163

 
$
2,368

(1) 
As of September 30, 2018, the fair value shown for crude oil derivative contracts represents the forward purchase of 3,565,000 barrels which will settle throughout the fourth quarter of 2018 and 2019.
(2) 
As of September 30, 2018, the fair value shown for crude oil derivative contracts represents the forward sale of 3,163,500 barrels of crude oil which will settle throughout the fourth quarter of 2018 and 2019. As of December 31, 2017, the fair value shown for crude oil derivative contracts represents the forward sale of 356,000 barrels of crude oil which settled in the first quarter of 2018.
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, 2018 and 2017:
 
 
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,
 
2018
 
2017
 
2018
 
2017
 
 
 
 
(in thousands)
Crude oil derivative contracts
 
Sales of natural gas, NGLs, and crude oil
 
$
9,435

 
$
175

 
$
16,665

 
$
1,065

Natural gas derivative contracts
 
Sales of natural gas, NGLs, and crude oil
 
$

 
$
(22
)
 
$

 
$
84

Call option derivative
 
Other income, net
 
$

 
$

 
$

 
$
1,885


15



Call Option Derivative
As part of our 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. On February 1, 2017, we exercised the remainder of the call option covering an additional 1,703,094 TEP common units for a cash payment of $72.4 million. These TEP 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 commodity derivatives consist of market participants and 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 derivative contracts are entered into with counterparties through central trading organizations such as futures, options or stock exchanges or counterparties outside of central trading organizations. While we typically enter into derivative transactions with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. The maximum potential exposure to credit losses on our crude oil derivative contracts at September 30, 2018 was:
 
Asset Position
 
(in thousands)
Gross
$
6,014

Netting agreement impact

Cash collateral held

Net exposure
$
6,014

As of September 30, 2018 and December 31, 2017, we had $1.1 million and $3.0 million, respectively, of cash in margin accounts and outstanding letters of credit in support of 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.

16



The following table summarizes the fair value measurements of our derivative contracts as of September 30, 2018 and December 31, 2017, 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 September 30, 2018:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
6,014

 
$

 
$
6,014

 
$

 
 
 
Liability Fair Value Measurements Using
 
Total
 
Quoted prices in
active markets
for identical
assets
(Level 1)
 
Significant
other observable
inputs
(Level 2)
 
Significant
unobservable
inputs
(Level 3)
 
(in thousands)
As of September 30, 2018:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
4,163

 
$

 
$
4,163

 
$

As of December 31, 2017:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
2,368

 
$

 
$
2,368

 
$

10. Long-term Debt
Long-term debt consisted of the following at September 30, 2018 and December 31, 2017:
 
September 30, 2018
 
December 31, 2017
 
(in thousands)
Tallgrass Equity revolving credit facility (1)
$

 
$
146,000

TEP revolving credit facility
1,051,000

 
661,000

TEP 4.75% senior notes due October 1, 2023
500,000

 

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

 
750,000

TEP 5.50% senior notes due January 15, 2028
750,000

 
750,000

Less: Deferred financing costs, net (2)
(20,793
)
 
(17,737
)
Plus: Unamortized premium on 2028 Notes
3,467

 
3,730

Total long-term debt, net
$
3,033,674

 
$
2,292,993

(1) 
On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility.
(2) 
Deferred financing costs, net as presented above relate solely to the Senior Notes (as defined below). 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 26, 2018, 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 26, 2018 (the "2023 Indenture") pursuant to which the Issuers issued $500 million in aggregate principal amount of 4.75% senior notes due 2023 (the "2023 Notes"). The 2023 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 TEP's properties to, another person.

17



The Issuers have also previously issued $500 million in aggregate principal amount of 5.50% senior notes due 2028 (the "2028 Notes") on September 15, 2017 and an additional $250 million in aggregate principal amount of the 2028 Notes on December 11, 2017. The 2028 Notes issued on September 15, 2017 and December 11, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date and offering price. The 2028 Notes are governed by an Indenture dated September 15, 2017 (the "2028 Indenture") which 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 TEP's properties to, another person.
In addition, the Issuers have previously issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes") on September 1, 2016 and an additional $350 million in aggregate principal amount of the 2024 Notes on May 16, 2017. The 2024 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 Notes are governed by an Indenture dated September 1, 2016 (the "2024 Indenture") which 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.
The 2023 Notes, 2024 Notes, and 2028 Notes are together referred to as the "Senior Notes." As of September 30, 2018, TEP was in compliance with the covenants required under the 2023 Indenture, the 2024 Indenture, and the 2028 Indenture.
TEP Revolving Credit Facility
The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of September 30, 2018 and December 31, 2017:
 
September 30, 2018
 
December 31, 2017
 
(in thousands)
Total capacity under the TEP revolving credit facility
$
2,250,000

 
$
1,750,000

Less: Outstanding borrowings under the TEP revolving credit facility
(1,051,000
)
 
(661,000
)
Less: Letters of credit issued under the TEP revolving credit facility
(94
)
 
(94
)
Available capacity under the TEP revolving credit facility
$
1,198,906

 
$
1,088,906

On July 26, 2018, TEP and certain of its subsidiaries entered into Amendment No. 1 (the "Amendment") to its existing revolving credit facility with Wells Fargo Bank, National Association, as administrative agent and collateral agent, and a syndicate of lenders (the "Credit Agreement"). The Amendment modified certain provisions of the Credit Agreement to, among other things, (i) increase the available amount of the TEP revolving credit facility to $2.25 billion, (ii) reduce certain applicable margins in the pricing grids used to determine the interest rate and revolving credit commitment fees, (iii) modify the use of proceeds to allow TEP to pay off the Tallgrass Equity revolving credit facility, and (iv) increase the maximum total leverage ratio to 5.50 to 1.00.
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 5.50 to 1.00 (5.00 to 1.00 prior to the Amendment), 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, 2018, TEP was 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 0.375% (0.250% to 0.500% prior to the Amendment), based on TEP's total leverage ratio. As of September 30, 2018, the weighted average interest rate on outstanding borrowings under the TEP revolving credit facility was 3.54%. During the nine months ended September 30, 2018, 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 3.98%.

18



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, 2018 and December 31, 2017, 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, 2018:
 
 
 
 
 
 
 
 
 
Revolving credit facility
$

 
$
1,051,000

 
$

 
$
1,051,000

 
$
1,051,000

2023 Notes
$

 
$
500,310

 
$

 
$
500,310

 
$
495,637

2024 Notes
$

 
$
766,635

 
$

 
$
766,635

 
$
740,969

2028 Notes
$

 
$
759,458

 
$

 
$
759,458

 
$
746,068

As of December 31, 2017:
 
 
 
 
 
 
 
 
 
Revolving credit facilities
$

 
$
807,000

 
$

 
$
807,000

 
$
807,000

2024 Notes
$

 
$
771,645

 
$

 
$
771,645

 
$
739,824

2028 Notes
$

 
$
758,168

 
$

 
$
758,168

 
$
746,169

The long-term debt borrowed under the revolving credit facilities is carried at amortized cost. As of September 30, 2018 and December 31, 2017, the fair value of borrowings under the revolving credit facilities approximates the carrying amount of the borrowings using a discounted cash flow analysis. The Senior Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the Senior 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, 2018.
11. Partnership Equity
TGE Dividends to Holders of Class A Shares
The following table details the dividends for the periods indicated:
Three Months Ended
 
Date Paid
 
Dividends to Class A Shareholders
 
Dividend per Class A Share
 
 
 
 
(in thousands, except per share amounts)
September 30, 2018
 
November 14, 2018 (1)
 
$
79,717

 
$
0.5100

June 30, 2018
 
August 14, 2018
 
77,052

 
0.4975

March 31, 2018
 
May 15, 2018
 
28,316

 
0.4875

December 31, 2017
 
February 14, 2018
 
21,346

 
0.3675

September 30, 2017
 
November 14, 2017
 
20,617

 
0.3550

June 30, 2017
 
August 14, 2017
 
19,891

 
0.3425

March 31, 2017
 
May 15, 2017
 
16,697

 
0.2875

(1) 
The dividend announced on October 15, 2018 for the third quarter of 2018 will be paid on November 14, 2018 to Class A shareholders of record at the close of business on October 31, 2018.

19



Subsidiary Distributions
TEP Distributions. The following table shows the distributions for the periods indicated:
 
 
 
 
Distributions
 
Distribution
per Limited
Partner Common Unit
 
 
 
 
Limited Partner
Common Units
 
General Partner
 
 
 
Three Months Ended
 
Date Paid
 
Incentive Distribution Rights
 
General Partner Units
 
Total
 
 
 
 
 
(in thousands, except per unit amounts)
March 31, 2018
 
May 15, 2018
 
$
71,370

 
$
39,816

 
$
1,267

 
$
112,453

 
$
0.9750

December 31, 2017
 
February 14, 2018
 
70,638

 
39,125

 
1,251

 
111,014

 
0.9650

September 30, 2017
 
November 14, 2017
 
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

As a result of the TEP Merger, Tallgrass Equity and its wholly-owned subsidiary, Tallgrass Equity Investments, LLC, will receive all distributions paid by TEP for the second quarter of 2018 and subsequent periods.
Exchange Rights
Our current Class B shareholders (collectively, the "Exchange Right Holders") own an equal number of Tallgrass Equity units. The Exchange Right Holders, and any permitted transferees of their Tallgrass Equity units, each have the right to exchange all or a portion of their Tallgrass Equity units for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party. During the nine months ended September 30, 2018, 2,403,766 Class A shares were issued and an equal number of Class B shares were cancelled as a result of the exercise of the Exchange Right. During the period from October 1, 2018 to October 31, 2018, 417,566 Class A shares were issued and an equal number of Class B shares were cancelled as a result of the exercise of the Exchange Right.
Equity Distribution Agreements
Neither TGE or TEP currently have equity distribution agreements in place. TEP was previously a party to equity distribution agreements pursuant to which it sold from time to time through a group of managers, as its sales agents, TEP common units representing limited partner interests. Following the TEP Merger, these agreements were terminated effective July 2, 2018. During the nine months ended September 30, 2018, TEP did not issue any common units under its equity distribution agreements. 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).
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.
Noncontrolling Interests
As of September 30, 2018, noncontrolling interests in our subsidiaries consisted of a 44.36% interest in Tallgrass Equity held by the Exchange Right Holders and an approximate 40% membership interest in Deeprock Development. During the nine months ended September 30, 2018, we recognized contributions from and distributions to noncontrolling interests of $0.2 million and $262.9 million, respectively. Contributions from noncontrolling interests consisted primarily of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $160.6 million, distributions to TEP unitholders of $97.7 million, and distributions to Deeprock Development and Pony Express noncontrolling interests of $4.6 million.

20



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.
Other Contributions and Distributions
During the nine months ended September 30, 2018, TGE recognized the following other contributions and distributions:
TGE was deemed to have made a noncash capital distribution of $198.0 million, which represents the excess purchase price over the $53.8 million carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018; and
TGE was deemed to have received a noncash capital contribution of $108.5 million, which represents the excess carrying value of the 25.01% membership interest in Rockies Express acquired as of February 7, 2018 over the fair value of the consideration paid.
During the nine months ended September 30, 2017, TGE recognized the following other contributions and distributions:
TEP received contributions from TD of $2.3 million primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 15 – Legal and Environmental Matters.
12. Revenue from Contracts with Customers
Implementation of ASC Topic 606
As discussed in Note 2 – Summary of Significant Accounting Policies, we adopted the guidance in ASC Topic 606 effective January 1, 2018 using the modified retrospective method of adoption. As a result, revenue reported for the three and nine months ended September 30, 2017 has not been revised. The following tables provide the impact of ASC Topic 606 on our condensed consolidated balance sheet as of September 30, 2018 and the condensed consolidated statements of income for the three and nine months ended September 30, 2018:
 
September 30, 2018
 
 
As currently reported
 
Under previous guidance
 
Impact of ASC Topic 606
 
 
(in thousands)
 
Unconsolidated investments
$
1,872,879

 
$
1,796,606

 
$
76,273

(1) 
 
Three Months Ended September 30, 2018
 
 
As currently reported
 
Under previous guidance
 
Impact of ASC Topic 606
 
 
(in thousands)
 
Crude oil transportation services
$
100,226

 
$
100,348

 
$
(122
)
(2) 
Sales of natural gas, NGLs, and crude oil
$
44,072

 
$
45,225

 
$
(1,153
)
(3) 
Processing and other revenues
$
25,069

 
$
25,630

 
$
(561
)
(1)(3) 
Cost of sales
$
28,556

 
$
30,248

 
$
(1,692
)
(2)(3) 
Equity in earnings of unconsolidated investments
$
76,268

 
$
64,704

 
$
11,564

(1) 
Net income attributable to TGE
$
59,550

 
$
53,366

 
$
6,184

 
Basic net income per Class A share
$
0.38

 
$
0.34

 
$
0.04

 
Diluted net income per Class A share
$
0.38

 
$
0.34

 
$
0.04

 

21



 
Nine Months Ended September 30, 2018
 
 
As currently reported
 
Under previous guidance
 
Impact of ASC Topic 606
 
 
(in thousands)
 
Crude oil transportation services
$
286,130

 
$
286,136

 
$
(6
)
(2) 
Sales of natural gas, NGLs, and crude oil
$
119,467

 
$
122,834

 
$
(3,367
)
(3) 
Processing and other revenues
$
72,783

 
$
75,846

 
$
(3,063
)
(1)(3) 
Cost of sales
$
82,601

 
$
88,846

 
$
(6,245
)
(2)(3) 
Equity in earnings of unconsolidated investments
$
222,857

 
$
189,450

 
$
33,407

(1) 
Net income attributable to TGE
$
77,348

 
$
67,701

 
$
9,647

 
Basic net income per Class A share
$
0.85

 
$
0.74

 
$
0.11

 
Diluted net income per Class A share
$
0.85

 
$
0.74

 
$
0.11

 
(1) 
Reflects the impact on our investment in Rockies Express and the management fee collected by NatGas of the cumulative effect adjustment at Rockies Express, which arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas.
(2) 
Reflects the impact to revenue and cost of sales to value PLA barrels collected under certain crude oil transportation arrangements at their contract inception fair value in revenue and record an associated lower of cost or net realizable value adjustment in cost of sales.
(3) 
Reflects the reclassification of certain gathering and processing fees collected under arrangements determined to be supply arrangements, rather than customer arrangements under ASC 606, to cost of sales and the reclassification of certain commodities retained as consideration for processing services to processing fee revenue.
Disaggregated Revenue
A summary of our revenue by line of business is as follows:
 
Three Months Ended September 30, 2018
 
Natural Gas Transportation segment
 
Crude Oil Transportation segment
 
Gathering, Processing, & Terminalling segment
 
Corporate and Other
 
Total Revenue
 
(in thousands)
Crude oil transportation - committed shipper revenue
$

 
$
100,614

 
$

 
$

 
$
100,614

Natural gas transportation - firm service
31,070

 

 

 
(793
)
 
30,277

Water business services

 

 
12,837

 

 
12,837

Natural gas gathering & processing fees

 

 
6,631

 

 
6,631

All other (1)
2,551

 
13,321

 
6,709

 
(17,636
)
 
4,945

Total service revenue
33,621

 
113,935

 
26,177

 
(18,429
)
 
155,304

Natural gas liquids sales

 

 
26,201

 

 
26,201

Natural gas sales
456

 

 
5,517

 

 
5,973

Crude oil sales

 
2,315

 
147

 

 
2,462

Total commodity sales revenue
456

 
2,315

 
31,865

 

 
34,636

Total revenue from contracts with customers
34,077

 
116,250

 
58,042

 
(18,429
)
 
189,940

Other revenue (2)

 

 
13,570

 
(3,190
)
 
10,380

Total revenue (3)
$
34,077

 
$
116,250

 
$
71,612

 
$
(21,619
)
 
$
200,320


22



 
Nine Months Ended September 30, 2018
 
Natural Gas Transportation segment
 
Crude Oil Transportation segment
 
Gathering, Processing, & Terminalling segment
 
Corporate and Other
 
Total Revenue
 
(in thousands)
Crude oil transportation - committed shipper revenue
$

 
$
286,594

 
$

 
$

 
$
286,594

Natural gas transportation - firm service
96,166

 

 

 
(4,074
)
 
92,092

Water business services

 

 
38,246

 

 
38,246

Natural gas gathering & processing fees

 

 
17,429

 

 
17,429

All other (1)
8,240

 
26,124

 
18,809

 
(36,832
)
 
16,341

Total service revenue
104,406

 
312,718

 
74,484

 
(40,906
)
 
450,702

Natural gas liquids sales

 

 
77,287

 

 
77,287

Natural gas sales
802

 

 
17,907

 

 
18,709

Crude oil sales

 
6,290

 
515

 

 
6,805

Total commodity sales revenue
802

 
6,290

 
95,709

 

 
102,801

Total revenue from contracts with customers
105,208

 
319,008

 
170,193

 
(40,906
)
 
553,503

Other revenue (2)

 

 
28,869

 
(9,369
)
 
19,500

Total revenue (3)
$
105,208

 
$
319,008

 
$
199,062

 
$
(50,275
)
 
$
573,003

(1) 
Includes revenue from crude oil transportation walk up shippers, crude oil terminal services, interruptible natural gas transportation and storage, and natural gas park and loan service.
(2) 
Includes lease and derivative revenue not subject to ASC 606.
(3) 
Excludes $225.8 million and $683.4 million of revenue recognized at Rockies Express for the three and nine months ended September 30, 2018, respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.
Performance Obligations
A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of account in ASC Topic 606. A contract's transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The majority of our contracts have a single performance obligation and are billed and collected monthly.
All of our segments engage in commodity sales, in which our performance obligations include an obligation to deliver the specified volume of a commodity to the designated receipt point. Revenue from commodity sales is recognized at a point in time when the customer obtains control of the commodity, typically upon delivery to the designated delivery point when the customer accepts and takes possession of the commodity.
In the Natural Gas Transportation segment, our performance obligations typically include an obligation to stand ready to provide natural gas transportation, storage, or an integrated transportation and storage service over the life of the contract, which is a series. These performance obligations are satisfied over time using each day of service to measure progress toward satisfaction of the performance obligation.
In the Crude Oil Transportation segment, our performance obligations typically include an obligation to provide crude oil transportation services over the life of the contract, which is a series. These performance obligations are satisfied over time using barrels delivered to measure progress toward satisfaction of the performance obligation.

23



In the Gathering, Processing & Terminalling segment, the performance obligations vary based on the operating asset and type of contract. In our natural gas gathering and processing arrangements, performance obligations typically include an obligation to provide an integrated processing service over the life of the contract, which is a series. These performance obligations are satisfied over time using each unit of gas processed to measure progress toward satisfaction of the performance obligation. In our freshwater supply arrangements, performance obligations typically include an obligation to deliver a specified volume of water to the designated receipt point. These performance obligations are satisfied at a point in time when the customer obtains control of the water. In our produced water gathering and disposal arrangements, performance obligations typically include an obligation to provide an integrated produced water gathering and disposal service over the life of the contract, which is a series. These performance obligations are satisfied over time using barrels disposed to measure progress toward satisfaction of the performance obligation.
On September 30, 2018, we had $1.5 billion of remaining performance obligations at our consolidated subsidiaries, which we refer to as total backlog. Total backlog includes performance obligations under long-term crude oil transportation contracts with committed shippers, natural gas firm transportation and firm storage contracts, and certain water business service contracts with minimum volume commitments, and excludes variable consideration that is not estimated at contract inception, as discussed further below. We expect to recognize the total backlog during the remainder of 2018 and future periods as follows (in thousands):
Year
 
Estimated Revenue

2018
 
$
129,104

2019
 
496,227

2020
 
328,066

2021
 
148,967

2022
 
136,316

Thereafter
 
271,512

Total
 
$
1,510,192

Contract Estimates
Accounting for long-term contracts involves the use of various techniques to estimate total contract revenue. Contract estimates are based on various assumptions to project the outcome of future events that often span several years. These assumptions include the anticipated volumes of crude oil expected to be delivered by our customers for transport in future periods.
The nature of our contracts gives rise to several types of variable consideration, including PLA, volumetric charges for actual volumes delivered, overrun charges, and other fees that are contingent on the actual volumes delivered by our customers. As the amount of variable consideration is allocable to each distinct performance obligation within the series of performance obligations that comprise the single performance obligation and the uncertainty related to the consideration is resolved each month as the distinct service is provided, we do not estimate the total variable consideration for the single overall performance obligation. Consequently, we are able to include in the transaction price each month the actual amount of variable consideration because no uncertainty exists surrounding the services provided that month.
Certain of our contracts include provisions in which a portion of the consideration is noncash. In our Crude Oil Transportation segment, we collect PLA from our customers. As crude oil is transported, we earn, and take title to, a portion of the oil transported for our services. Any PLA that remains after replacing losses in transit can be sold. Where PLA is determined to be a component of compensation for the transportation services provided, crude oil retained is recognized in revenue at its contract inception fair value. In our Gathering, Processing & Terminalling segment, we retain commodity products as consideration under certain of our gathering and processing arrangements. Processing fee revenue is recorded when the performance obligation is completed based on the value of the product received at the time services are performed. At this time, the variability of the non-cash consideration related to both form (price) and other-than-form (volume and product mix), which are interrelated, is resolved.
As a significant change in one or more of these estimates could affect the amount and timing of revenue recognized under our customer contracts, we review and update our contract-related estimates regularly.

24



Contract Balances
The timing of revenue recognition, billings, and cash collections may result in billed accounts receivable, unbilled receivables (contract assets), and deferred revenue (contract liabilities) on our condensed consolidated balance sheets. Revenue is generally billed and collected monthly based on services provided or commodity volumes sold. In our Crude Oil Transportation segment, we recognize shipper deficiencies, or deferred revenue, for barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers' agreed upon destination point. These shipper deficiencies are charged at the committed tariff rate per barrel and recorded as a contract liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote. We also recognize contract liabilities, in the form of deferred revenue, under certain water business services contracts in the Gathering, Processing & Terminalling segment. Contract balances as of September 30, 2018 were as follows:
 
September 30, 2018
 
January 1, 2018
 
(in thousands)
Accounts receivable from contracts with customers
$
67,603

 
$
61,888

Other accounts receivable
168,097

 
56,727

Accounts receivable, net
$
235,700

 
$
118,615

 
 
 
 
Deferred revenue from contracts with customers (1)
$
103,652

 
$
88,471

(1) 
Revenue recognized during the three and nine months ended September 30, 2018 that was included in the deferred revenue balance at the beginning of the period was $2.0 million and $9.3 million, respectively. This revenue primarily represented the utilization of shipper deficiencies at Pony Express.
13. Net Income per Class A Share
Basic net income per Class A share is determined by dividing net income attributable to TGE by the weighted average number of outstanding Class A shares during the period. Class B shares do not share in the earnings of TGE. 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 TGE 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 TGE 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 TGE'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 TGE Class B shares) for TGE Class A shares at an exchange ratio of one TGE 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 TGE's management.
Pursuant to the TGE 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 three and nine months ended September 30, 2018 and 2017, the potential issuance of TGE Equity Participation Shares would have had a dilutive effect on basic net income per Class A share. Effective June 30, 2018 with the completion of the TEP Merger, as discussed in Note 1 – Description of Business, TEP's outstanding Equity Participation Units were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit. As of September 30, 2018, TGE has 1,968,908 outstanding Equity Participation Shares with a weighted average grant date fair value of $18.93, and expects to recognize $19.6 million of total compensation cost related to non-vested Equity Participation Shares over a weighted average period of 2.9 years.

25



The following table illustrates the calculation of net income per Class A share for the three and nine months ended September 30, 2018 and 2017:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except per unit amounts)
Basic Net Income per Class A Share
 
 
 
 
 
 
 
Net income attributable to TGE
$
59,550

 
$
15,866

 
$
77,348

 
$