10-Q 1 tge201933110q.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 March 31, 2019
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)
 
 
 
(913) 928-6060
(Registrant's Telephone Number, Including Area Code)
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)
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 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 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
Securities registered pursuant to Section 12(b) of the Act:
 
 
 
 
 
Title of each class
 
Trading Symbol
 
Name of each exchange on which registered
Class A Shares Representing Limited Partner Interests
 
TGE
 
New York Stock Exchange



On May 7, 2019, the Registrant had 179,197,416 Class A shares and 102,136,875 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.
Pipeline loss allowance (or PLA): Crude oil collected from customers under certain crude oil transportation arrangements.
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)
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
ASSETS
 
Current Assets:
 
 
 
Cash and cash equivalents
$
15,042

 
$
9,596

Accounts receivable, net
227,284

 
236,097

Inventories
27,954

 
34,316

Prepayments and other current assets
18,219

 
11,816

Total Current Assets
288,499

 
291,825

Property, plant and equipment, net
2,750,375

 
2,802,429

Goodwill
421,983

 
421,983

Intangible assets, net
223,707

 
227,103

Unconsolidated investments
1,988,797

 
1,861,686

Deferred tax asset
379,422

 
273,531

Deferred charges and other assets
16,442

 
14,952

Total Assets
$
6,069,225

 
$
5,893,509

LIABILITIES AND EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts payable
$
187,321

 
$
201,512

Accrued taxes
26,962

 
20,734

Accrued interest
12,534

 
39,217

Accrued liabilities
9,975

 
23,287

Deferred revenue
123,184

 
111,095

Other current liabilities
44,651

 
42,910

Total Current Liabilities
404,627

 
438,755

Long-term debt, net
3,331,716

 
3,205,958

Other long-term liabilities and deferred credits
33,118

 
31,688

Total Long-term Liabilities
3,364,834

 
3,237,646

Commitments and Contingencies

 

Equity:
 
 
 
Class A Shareholders (178,104,779 and 156,311,986 shares outstanding at March 31, 2019 and December 31, 2018, respectively)
1,890,345

 
1,725,537

Class B Shareholders (102,136,875 and 123,887,893 shares outstanding at March 31, 2019 and December 31, 2018, respectively)
—

 
—

Total Partners' Equity
1,890,345

 
1,725,537

Noncontrolling interests (a)
409,419

 
491,571

Total Equity
2,299,764

 
2,217,108

Total Liabilities and Equity
$
6,069,225

 
$
5,893,509

(a) 
See Note 10 - 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 March 31,
 
2019
 
2018
 
(in thousands, except per unit amounts)
Revenues:
 
 
 
Crude oil transportation services
$
95,156

 
$
84,738

Natural gas transportation services
33,516

 
32,196

Sales of natural gas, NGLs, and crude oil
38,864

 
38,145

Processing and other revenues
29,816

 
24,015

Total Revenues
197,352


179,094

Operating Costs and Expenses:
 
 
 
Cost of sales
19,285

 
26,351

Cost of transportation services
15,072

 
10,420

Operations and maintenance
18,046

 
16,399

Depreciation and amortization
31,001

 
26,123

General and administrative
32,272

 
18,426

Taxes, other than income taxes
10,998

 
8,879

Loss (gain) on disposal of assets
214

 
(9,417
)
Total Operating Costs and Expenses
126,888


97,181

Operating Income
70,464


81,913

Other Income (Expense):
 
 
 
Equity in earnings of unconsolidated investments
88,522

 
68,402

Interest expense, net
(39,705
)
 
(29,761
)
Other income, net
177

 
451

Total Other Income (Expense)
48,994


39,092

Net income before tax
119,458


121,005

Deferred income tax expense
(17,066
)
 
(6,692
)
Net income
102,392


114,313

Net income attributable to noncontrolling interests
(51,805
)
 
(97,578
)
Net income attributable to TGE
$
50,587


$
16,735

Net income per Class A share:
 
 
 
Basic net income per Class A share
$
0.31

 
$
0.29

Diluted net income per Class A share
$
0.31

 
$
0.29

Basic average number of Class A shares outstanding
161,425

 
58,085

Diluted average number of Class A shares outstanding
162,777

 
58,210




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


TALLGRASS ENERGY, LP
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)
 
Partners' Capital
 
Noncontrolling Interests
 
Total Equity
 
Class A Shares
 
Class B Shares
 
 
 
(in thousands)
Balance at January 1, 2019
$
1,725,537

 
$
—

 
$
491,571

 
$
2,217,108

Net income
50,587

 
—

 
51,805

 
102,392

Dividends paid to Class A shareholders
(81,304
)
 
—

 
—

 
(81,304
)
Distributions to noncontrolling interest
—

 
—

 
(66,625
)
 
(66,625
)
Contributions from noncontrolling interest
—

 
—

 
1,282

 
1,282

Noncash compensation expense
17,120

 
—

 
—

 
17,120

TGE LTIP shares tendered by employees to satisfy tax withholding obligations
(13,260
)
 
—

 
—

 
(13,260
)
Deferred tax asset
123,051

 
—

 
—

 
123,051

Conversion of Class B shares to Class A shares
68,614

 
—

 
(68,614
)
 
—

Balance at March 31, 2019
$
1,890,345

 
$
—

 
$
409,419

 
$
2,299,764

 
 
 
 
 
 
 
 
 
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
16,735

 
—

 
97,578

 
114,313

Issuance of TEP units to the public, net of offering costs
(5
)
 
—

 
(40
)
 
(45
)
Dividends paid to Class A shareholders
(21,346
)
 
—

 
—

 
(21,346
)
Noncash compensation expense
404

 
—

 
2,917

 
3,321

Acquisition of additional TEP common units from TD
(62,222
)
 
—

 
(189,520
)
 
(251,742
)
Issuance of Tallgrass Equity units
—

 
—

 
644,782

 
644,782

Acquisition of additional 2% membership interest in Pony Express
(5,268
)
 
—

 
(44,732
)
 
(50,000
)
Acquisition of 25.01% membership interest in Rockies Express
34,116

 
—

 
74,421

 
108,537

Consolidation of Deeprock North
—

 
—

 
31,843

 
31,843

Contributions from noncontrolling interest
—

 
—

 
183

 
183

Distributions to noncontrolling interest
—

 
—

 
(89,073
)
 
(89,073
)
Balance at March 31, 2018
$
15,615


$
—


$
2,240,468


$
2,256,083


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


TALLGRASS ENERGY, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Cash Flows from Operating Activities:
 
 
 
Net income
$
102,392

 
$
114,313

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
32,799

 
27,620

Equity in earnings of unconsolidated investments
(88,522
)
 
(68,402
)
Distributions from unconsolidated investments
87,940

 
67,059

Deferred income tax expense
17,066

 
6,692

Noncash compensation expense
17,120

 
2,814

Other noncash items, net
1,536

 
(12,024
)
Changes in components of working capital:
 
 
 
Accounts receivable and other
8,985

 
(12,013
)
Accounts payable and accrued liabilities
(46,186
)
 
16,354

Deferred revenue
12,125

 
10,750

Other current assets and liabilities
2,026

 
(1,671
)
Other operating, net
(3,533
)
 
108

Net Cash Provided by Operating Activities
143,748


151,600

Cash Flows from Investing Activities:
 
 
 
Capital expenditures
(62,802
)
 
(58,760
)
Formation of Powder River Gateway joint venture
(37,000
)
 
—

Contributions to unconsolidated investments
(29,797
)
 
(8,034
)
Distributions from unconsolidated investments in excess of cumulative earnings
27,158

 
20,774

Acquisition of BNN North Dakota, net of cash acquired
—

 
(95,000
)
Sale of Tallgrass Crude Gathering
—

 
50,046

Acquisition of 38% membership interest in Deeprock North
—

 
(19,500
)
Other investing, net
15

 
(12,439
)
Net Cash Used in Investing Activities
(102,426
)

(122,913
)
Cash Flows from Financing Activities:
 
 
 
Borrowings under revolving credit facilities, net
125,000

 
133,000

Dividends paid to Class A shareholders
(81,304
)
 
(21,346
)
Distributions to noncontrolling interests
(66,625
)
 
(89,073
)
TGE LTIP shares tendered by employees to satisfy tax withholding obligations
(13,260
)
 
—

Acquisition of Pony Express membership interest
—

 
(50,000
)
Other financing, net
313

 
394

Net Cash Used in Financing Activities
(35,876
)

(27,025
)
Net Change in Cash and Cash Equivalents
5,446

 
1,662

Cash and Cash Equivalents, beginning of period
9,596

 
2,593

Cash and Cash Equivalents, end of period
$
15,042

 
$
4,255

 
 
 
 

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


 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
 
 
 
 
Schedule of Noncash Investing and Financing Activities:
 
 
 
Assets contributed to Powder River Gateway joint venture
$
(86,891
)
 
$
—

Contribution of 75% membership interest in Iron Horse to Powder River Gateway joint venture
$
(35,613
)
 
$
—

Accruals for property, plant and equipment
$
18,874

 
$
1,336

Issuance of Tallgrass Equity units (a)
$
—

 
$
644,782

Acquisition of Rockies Express membership interest (a)
$
—

 
$
(393,039
)
Acquisition of additional TEP common units from TD (a)
$
—

 
$
(251,743
)
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
)
(a) 
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.

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"), 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 63.55% membership interest as of March 31, 2019, and Tallgrass Energy Partners, LP ("TEP"), a wholly-owned subsidiary of Tallgrass Equity and its subsidiaries. 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 FERC-regulated crude oil pipeline systems; 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 (1) 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") and (2) our 51% membership interest in Powder River Gateway, LLC ("Powder River Gateway"), which owns the Powder River Express Pipeline ("PRE Pipeline"), a 70-mile crude oil pipeline that transports crude oil from the Powder River Basin to Guernsey, Wyoming, the Iron Horse Pipeline ("Iron Horse Pipeline"), a 80-mile crude oil pipeline placed into service in May 2019 that transports crude oil from the Powder River Basin to Guernsey, Wyoming, and crude oil terminal facilities in Guernsey, Wyoming.
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.

6


Blackstone Acquisition
On March 11, 2019, pursuant to the terms of the previously announced definitive purchase agreement (the "Purchase Agreement"), dated January 30, 2019, entered into among acquisition vehicles controlled by affiliates of Blackstone Infrastructure Partners ("BIP" and, acquisition vehicles controlled by BIP, collectively, the "Sponsor Entities"), affiliates of Kelso & Co., affiliates of The Energy & Minerals Group, Tallgrass KC, LLC, an entity owned by certain members of our management, and the other sellers named therein (collectively, the "Sellers"), certain of the Sponsor Entities acquired from the Sellers (i) 100% of the membership interests in our general partner, (ii) 21,751,018 Class A shares representing limited partner interests ("Class A shares") in us, (iii) 100,655,121 units representing limited liability company interests ("TE Units") in Tallgrass Equity, and (iv) 100,655,121 Class B shares representing limited partner interests ("Class B shares") in us, in exchange for aggregate consideration of approximately $3.2 billion in cash, which was paid to the Sellers (the "Blackstone Acquisition").
As a result of the Blackstone Acquisition, BIP effectively controls our business and affairs through the ownership of 100% of the membership interests in our general partner and the exercise of the rights of such sole member. Additionally, the Sponsor Entities collectively held an approximate 43.8% economic interest in us as of March 31, 2019.
2. Summary of Significant Accounting Policies
Basis of Presentation
These condensed consolidated financial statements and related notes for the three months ended March 31, 2019 and 2018 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 months ended March 31, 2019 and 2018 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.
Our financial results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019. 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, 2018 ("2018 Form 10-K") filed with the SEC on February 8, 2019.
The condensed consolidated financial statements include the accounts of TGE and its subsidiaries and controlled affiliates. 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. We have no elements of other comprehensive income for the periods presented.
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.
Income Taxes
During the three months ended March 31, 2019, we recognized an additional deferred tax asset of $123.1 million upon exercise of the Exchange Right, as discussed in Note 10 – Partnership Equity, with respect to 21,751,018 Class B shares to Class A shares in connection with the Blackstone Acquisition discussed in Note 1 – Description of Business.
As a result of the increased income allocated to TGE resulting from our increased ownership in TEP following the merger transaction effective June 30, 2018 and the exercise of the Exchange Right effective March 11, 2019, our annual effective tax rate increased from 5.15% for the three months ended March 31, 2018 to 14.77% for the three months ended March 31, 2019.

7


Accounting Pronouncement Recently 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 right-of-use ("ROU") 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 has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2019. This approach allows us to (i) initially apply ASC 842 at the adoption date, January 1, 2019 and (ii) continue reporting comparative periods presented in the financial statements in the period of adoption under ASC 840. Accordingly, we will not recast comparative periods in the condensed consolidated financial statements. We have elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed us to carry forward the historical lease classification. We have also elected the practical expedients related to land easements, allowing us to carry forward our accounting treatment for existing land easements as property, plant and equipment, and short-term leases, allowing us to not recognize ROU assets or lease liabilities for leases with a term of 12 months or less.
Excluding ROU assets and lease liabilities relating to agreements between consolidated subsidiaries, adoption of the new standard resulted in the recognition of ROU assets of approximately $2.3 million, and current and non-current lease liabilities of approximately $0.6 million and $1.7 million, respectively, for operating leases as of January 1, 2019. Our accounting for finance leases remained substantially unchanged. The adoption of this guidance had no impact to our cash flows from operating, investing, or financing activities. For additional information see Note 12 – Leases.
3. Acquisitions
Joint Venture with Silver Creek
In February 2018, we entered into an agreement with Silver Creek Midstream, LLC ("Silver Creek") to form Iron Horse Pipeline, LLC ("Iron Horse"), which owns the Iron Horse Pipeline. Effective January 1, 2019, the joint venture between us and Silver Creek was expanded through contributions to Powder River Gateway, a newly formed entity. We contributed our 75% membership interest in Iron Horse, $37 million in cash, and various other assets, including terminal facilities under construction in Guernsey, Wyoming. Silver Creek contributed the PRE Pipeline and related terminal facilities in Guernsey, Wyoming, as well as their 25% membership interest in Iron Horse. Following the expansion of the joint venture, we own a 51% membership interest in Powder River Gateway and continue to operate the joint venture, while Silver Creek owns a 49% membership interest in Powder River Gateway. As the 51% membership interest does not represent a controlling interest in Powder River Gateway, our investment in Powder River Gateway is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the condensed consolidated balance sheets.
Acquisition of Plaquemines Liquids Terminal, LLC
In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly-own Plaquemines Liquids Terminal, LLC ("PLT"). PLT was formed with the intention of entering into agreements to develop a storage and terminalling facility. If developed, the facility is expected to be capable of offering up to 20 million barrels of storage for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers ("VLCC") vessels for international delivery. In connection with our acquisition of a 100% preferred membership interest and a 80% common membership interest in PLT, we recognized liabilities related to DHIF's right to receive special distributions totaling $35 million, of which $25 million is included in "Other current liabilities" and the remaining $10 million is included in "Other long-term liabilities and deferred credits" in the condensed consolidated balance sheets. The special distributions are contingent upon PLT reaching certain milestones in the development and construction of the project facilities. Also in November 2018, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT expects to construct the facilities.

8


4. Related Party Transactions
Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Processing and other revenues (1)
$
1,903

 
$
1,896

(1) 
Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline.
Details of balances with affiliates included in "Accounts receivable, net" in the condensed consolidated balance sheets are as follows:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Receivable from related parties:
 
 
 
Rockies Express Pipeline LLC
$
2,839

 
$
3,447

Powder River Gateway, LLC
512

 
—

Pawnee Terminal, LLC
129

 
115

Iron Horse Pipeline, LLC
—

 
186

Total receivable from related parties
$
3,480

 
$
3,748

Gas imbalances with affiliated shippers are as follows:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Affiliate gas imbalance receivables
$
19

 
$
19

Affiliate gas imbalance payables
$
2,309

 
$
742

5. Inventory
The components of inventory at March 31, 2019 and December 31, 2018 consisted of the following:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Crude oil
$
16,803

 
$
23,205

Materials and supplies
7,666

 
8,206

Gas in underground storage
2,413

 
2,740

Natural gas liquids
1,072

 
165

Total inventory
$
27,954

 
$
34,316


9


6. Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Crude oil pipelines
$
1,309,763

 
$
1,313,976

Gathering, processing and terminalling assets
895,552

 
889,168

Natural gas pipelines
615,495

 
607,343

General and other (1)
163,206

 
180,299

Construction work in progress
171,960

 
191,994

Accumulated depreciation and amortization
(405,601
)
 
(380,351
)
Total property, plant and equipment, net
$
2,750,375

 
$
2,802,429

(1) 
Includes approximately $30.7 million of land associated with the PLT capital lease as discussed in Note 12 – Leases.
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 three months ended March 31, 2019, we recognized equity in earnings associated with our 75% membership interest in Rockies Express of $86.2 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $113.4 million and $17.3 million, respectively.
Summarized financial information for Rockies Express is as follows:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Revenue
$
230,761

 
$
230,058

Operating income
$
132,410

 
$
128,678

Net income to Members
$
103,609

 
$
90,968

8. Risk Management
We enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We have a comprehensive risk management policy adopted by the board of directors of our general partner and a Risk Management Committee responsible for the overall management of credit risk and commodity risk, including establishing and monitoring exposure limits.
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.

10


Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets:
 
Balance Sheet Location
 
March 31, 2019
 
December 31, 2018
 
 
 
(in thousands)
Crude oil derivative contracts (1)
Prepayments and other current assets
 
$
1,761

 
$
3,526

Crude oil derivative contracts (2)
Other current liabilities
 
$
1,129

 
$
1,642

(1) 
As of March 31, 2019 and December 31, 2018, the amount shown represents the fair value of crude oil derivative contracts for the forward purchase of 2,135,700 and 2,105,146 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle throughout 2019.
(2) 
As of March 31, 2019 and December 31, 2018, the amount shown represents the fair value of crude oil derivative contracts for the forward sale of 1,793,000 and 1,274,500 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle throughout 2019.
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 months ended March 31, 2019 and 2018:
 
 
Location of gain recognized
in income on derivatives
 
Amount of gain recognized in income on derivatives
 
Three Months Ended March 31,
 
2019
 
2018
 
 
 
 
(in thousands)
Crude oil derivative contracts
 
Sales of natural gas, NGLs, and crude oil
 
$
11,473

 
$
4,295

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.
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 March 31, 2019 was:
 
Asset Position
 
(in thousands)
Gross
$
1,761

Netting agreement impact
—

Cash collateral held
—

Net exposure
$
1,761

As of March 31, 2019, we had $1.1 million of cash in margin accounts in support of our commodity derivative contracts. As of December 31, 2018, we did not have any cash in margin accounts in support of our commodity derivative contracts.

11


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 following table summarizes the fair value measurements of our derivative contracts as of March 31, 2019 and December 31, 2018, 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 March 31, 2019:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
1,761

 
$
—

 
$
1,761

 
$
—

As of December 31, 2018:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
3,526

 
$
—

 
$
3,526

 
$
—

 
 
 
Liability Fair Value Measurements Using
 
Total
 
Quoted prices in
active markets
for identical
assets
(Level 1)
 
Significant
other observable
inputs
(Level 2)
 
Significant
unobservable
inputs
(Level 3)
 
(in thousands)
As of March 31, 2019:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
1,129

 
$
—

 
$
1,129

 
$
—

As of December 31, 2018:
 
 
 
 
 
 
 
Crude oil derivative contracts
$
1,642

 
$
—

 
$
1,642

 
$
—

9. Long-term Debt
Our long-term debt is held at TEP and consisted of the following at March 31, 2019 and December 31, 2018:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Revolving credit facility
$
1,349,000

 
$
1,224,000

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

 
500,000

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

 
750,000

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

 
750,000

Less: Deferred financing costs, net (1)
(20,575
)
 
(21,421
)
Plus: Unamortized premium on 2028 Notes
3,291

 
3,379

Total long-term debt, net
$
3,331,716

 
$
3,205,958

(1) 
Deferred financing costs, net as presented above relate solely to the Senior Notes (as defined below). Deferred financing costs associated with our revolving credit facility is presented in noncurrent assets on our condensed consolidated balance sheets.

12


Senior Unsecured Notes
On February 27, 2019, TEP and Tallgrass Energy Finance Corp. (together, the "Issuers"), together with the TEP subsidiary guarantors party thereto (the "Guarantors") and U.S. Bank National Association, as trustee (the "Trustee"), entered into supplemental indentures (the "Supplemental Indentures") to amend certain provisions of each of (i) the Indenture governing the 4.75% Senior Notes due 2023, dated as of September 26, 2018, among the Issuers, the Guarantors and Trustee, (ii) the Indenture governing the 5.50% Senior Notes due 2024, dated as of September 1, 2016, among the Issuers, the Guarantors and the Trustee, and (iii) the Indenture governing the 5.50% senior notes due 2028, dated as of September 15, 2017, among the Issuers, the Guarantors and the Trustee (collectively, the "Indentures"). The Supplemental Indentures (a) amended the defined term "Change of Control" in each Indenture to provide that the Blackstone Acquisition did not constitute a Change of Control under such Indenture, (b) changed the definition of "Qualifying Owners" in the applicable Indenture to provide that Blackstone Infrastructure Partners L.P., Vencap Holdings (1992) Pte. Ltd. and their respective affiliates, funds, holding companies and investment vehicles, among others, are Qualifying Owners under such Indenture, and (c) added to, amended, supplemented or changed certain other defined terms contained in each Indenture related to the foregoing.
As of March 31, 2019, TEP was in compliance with the covenants required under the Indentures.
Revolving Credit Facility
The following table sets forth the available borrowing capacity under our revolving credit facility as of March 31, 2019 and December 31, 2018:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Total capacity under the revolving credit facility
$
2,250,000

 
$
2,250,000

Less: Outstanding borrowings under the revolving credit facility
(1,349,000
)
 
(1,224,000
)
Less: Letters of credit issued under the revolving credit facility
(94
)
 
(94
)
Available capacity under the revolving credit facility
$
900,906

 
$
1,025,906

On February 22, 2019, TEP and certain of its subsidiaries entered into a Consent and Amendment No. 2 to the Second Amended and Restated Credit Agreement (the "Consent and Amendment") with Wells Fargo Bank, National Association, as administrative agent, and the required lenders party thereto. The Consent and Amendment modified that certain Second Amended and Restated Credit Agreement dated as of June 2, 2017, as previously amended by that certain Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of July 26, 2018 (as amended, the "Credit Agreement"). The Credit Agreement governs our revolving credit facility.
In the Consent and Amendment, the required lenders under the Credit Agreement (i) consented to the Blackstone Acquisition pursuant to the terms and conditions of the Purchase Agreement, (ii) agreed that no Default (as defined in the Credit Agreement) under the Credit Agreement, if any, that may have resulted from a Change in Control (as defined in the Credit Agreement) caused by the consummation of the Blackstone Acquisition pursuant to the terms and conditions set forth in the Purchase Agreement will be deemed to have occurred, and (iii) agreed to modify the definition of "Permitted Holders" in Section 1.01 of the Credit Agreement (which is used in the definition of Change in Control) to reflect the change in ownership as a result of the Blackstone Acquisition.
As of March 31, 2019, TEP was in compliance with the covenants required under its revolving credit facility. As of March 31, 2019, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 4.00%. During the three months ended March 31, 2019, the weighted average effective interest rate under the revolving credit facility, including the interest on outstanding borrowings under the revolving credit facility, commitment fees, and amortization of deferred financing costs, was 4.52%.

13


Fair Value
The following table sets forth the carrying amount and fair value of long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of March 31, 2019 and December 31, 2018, 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 March 31, 2019:
 
 
 
 
 
 
 
 
 
Revolving credit facility
$
—

 
$
1,349,000

 
$
—

 
$
1,349,000

 
$
1,349,000

2023 Notes
$
—

 
$
504,325

 
$
—

 
$
504,325

 
$
494,892

2024 Notes
$
—

 
$
771,923

 
$
—

 
$
771,923

 
$
741,565

2028 Notes
$
—

 
$
754,253

 
$
—

 
$
754,253

 
$
746,259

As of December 31, 2018:
 
 
 
 
 
 
 
 
 
Revolving credit facility
$
—

 
$
1,224,000

 
$
—

 
$
1,224,000

 
$
1,224,000

2023 Notes
$
—

 
$
485,285

 
$
—

 
$
485,285

 
$
494,603

2024 Notes
$
—

 
$
737,745

 
$
—

 
$
737,745

 
$
741,196

2028 Notes
$
—

 
$
726,503

 
$
—

 
$
726,503

 
$
746,159

The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of March 31, 2019 and December 31, 2018, the fair value of borrowings under the revolving credit facility 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 March 31, 2019.
10. 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
 
Dividends per Class A Share
 
 
 
 
(in thousands, except per share amounts)
March 31, 2019
 
May 15, 2019 (1)
 
$
94,975

 
$
0.5300

December 31, 2018
 
February 14, 2019
 
81,304

 
0.5200

September 30, 2018
 
November 14, 2018
 
79,717

 
0.5100

June 30, 2018
 
August 14, 2018
 
77,052

 
0.4975

March 31, 2018
 
May 15, 2018
 
28,316

 
0.4875

(1) 
The dividend announced on April 11, 2019 for the first quarter of 2019 will be paid on May 15, 2019 to Class A shareholders of record at the close of business on April 30, 2019.
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 three months ended March 31, 2019, 21,751,018 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.

14


Following the Blackstone Acquisition that closed on March 11, 2019 discussed in Note 1 – Description of Business, the Exchange Rights Holders currently consist of certain of the Sponsor Entities and certain members of our management.
Noncontrolling Interests
As of March 31, 2019, noncontrolling interests in our subsidiaries consisted of a 36.45% interest in Tallgrass Equity held by the Exchange Right Holders, as well as noncontrolling interests in certain subsidiaries held by unaffiliated third parties, including an approximate 40% membership interest in Deeprock Development, LLC ("Deeprock Development"), an approximate 25% membership interest in BNN West Texas, LLC ("West Texas"), and a 37% membership interest in BNN Colorado Water, LLC ("BNN Colorado"). During the three months ended March 31, 2019, we recognized contributions from and distributions to noncontrolling interests of $1.3 million and $66.6 million, respectively. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $64.4 million and distributions to Deeprock Development and West Texas noncontrolling interests of $2.2 million.
During the three months ended March 31, 2018, we recognized contributions from and made distributions to noncontrolling interests of $0.2 million and $89.1 million, respectively. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $51.3 million, Tallgrass Equity distributions to the Exchange Right Holders of $36.4 million and distributions to Deeprock Development and Pony Express noncontrolling interests of $1.3 million.
Other Contributions and Distributions
During the three months ended March 31, 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;
•
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; and
•
TEP was deemed to have made a noncash capital distribution of $16.2 million, which represents the excess purchase price over the $33.8 million carrying value of the additional 2% membership interest in Pony Express acquired as of February 1, 2018.
Share-Based Compensation
The Blackstone Acquisition discussed in Note 1 – Description of Business constituted a change in control event under certain Equity Participation Share agreements outstanding under the LTIP plan, resulting in the accelerated vesting of 1,092,637 Class A shares (net of tax withholding of approximately 543,909 Class A shares) with a weighted average grant date fair value of $18.82. These Class A shares were issued in April 2019. The accelerated vesting resulted in the recognition of equity-based compensation costs of $12.5 million in "General and administrative" costs in the condensed consolidated statements of income during the three months ended March 31, 2019. In addition, 1,767,100 Equity Participation Shares with a weighted average grant date fair value of $15.20 were granted during the three months ended March 31, 2019.

15


11. Revenue from Contracts with Customers
Disaggregated Revenue
A summary of our revenue by line of business is as follows:
 
Three Months Ended March 31, 2019
 
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
$
—

 
$
95,277

 
$
—

 
$
—

 
$
95,277

Natural gas transportation - firm service
32,521

 
—

 
—

 
(396
)
 
32,125

Water business services
—

 
—

 
18,286

 
—

 
18,286

Natural gas gathering & processing fees
—

 
—

 
6,080

 
—

 
6,080

All other (1)
3,321

 
14,507

 
3,520

 
(17,034
)
 
4,314

Total service revenue
35,842

 
109,784

 
27,886

 
(17,430
)
 
156,082

Natural gas liquids sales
—

 
—

 
16,871

 
—

 
16,871

Natural gas sales
—

 
—

 
10,401

 
—

 
10,401

Crude oil sales
—

 
—

 
119

 
—

 
119

Total commodity sales revenue
—

 
—

 
27,391

 
—

 
27,391

Total revenue from contracts with customers
35,842

 
109,784

 
55,277

 
(17,430
)
 
183,473

Other revenue (2)
—

 
—

 
18,757

 
(4,878
)
 
13,879

Total revenue (3)
$
35,842

 
$
109,784

 
$
74,034

 
$
(22,308
)
 
$
197,352

 
Three Months Ended March 31, 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
$
—

 
$
84,738

 
$
—

 
$
—

 
$
84,738

Natural gas transportation - firm service
33,334

 
—

 
—

 
(1,883
)
 
31,451

Water business services
—

 
—

 
13,204

 
—

 
13,204

Natural gas gathering & processing fees
—

 
—

 
5,044

 
—

 
5,044

All other (1)
2,630

 
3,319

 
5,706

 
(6,088
)
 
5,567

Total service revenue
35,964

 
88,057

 
23,954

 
(7,971
)
 
140,004

Natural gas liquids sales
—

 
—

 
23,609

 
—

 
23,609

Natural gas sales
238

 
—

 
7,847

 
—

 
8,085

Crude oil sales
—

 
1,909

 
247

 
—

 
2,156

Total commodity sales revenue
238

 
1,909

 
31,703

 
—

 
33,850

Total revenue from contracts with customers
36,202

 
89,966

 
55,657

 
(7,971
)
 
173,854

Other revenue (2)
—

 
—

 
8,181

 
(2,941
)
 
5,240

Total revenue (3)
$
36,202

 
$
89,966

 
$
63,838

 
$
(10,912
)
 
$
179,094

(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.

16


(3) 
Excludes revenue recognized at unconsolidated investments, including $230.8 million and $230.1 million of revenue recognized at Rockies Express for the three months ended March 31, 2019 and 2018, respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.
Performance Obligations
On March 31, 2019, 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 2019 and future periods as follows (in thousands):
Year
 
Estimated Revenue

2019 – remaining
 
$
439,404

2020
 
367,732

2021
 
175,919

2022
 
171,033

2023
 
150,810

Thereafter
 
240,961

Total
 
$
1,545,859

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.

17


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 were as follows:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Accounts receivable from contracts with customers
$
79,855

 
$
80,935

Other accounts receivable (1)
143,949

 
151,414

Receivable from related parties
3,480

 
3,748

Accounts receivable, net
$
227,284

 
$
236,097

 
 
 
 
Deferred revenue from contracts with customers (2)
$
123,184

 
$
111,095

(1) 
Other accounts receivable primarily consists of receivables under crude oil forward purchase and sale arrangements that are accounted for as derivatives under ASC 815.
(2) 
Revenue recognized during the three months ended March 31, 2019 that was included in the deferred revenue balance at the beginning of the period was $1.6 million. This revenue primarily represented the utilization of shipper deficiencies at Pony Express.
12. Leases
We account for leases in accordance with ASC Topic 842, Leases, which we adopted on January 1, 2019, applying the modified retrospective transition approach as of the effective date of adoption. See Note 2 – Summary of Significant Accounting Policies for additional information regarding the impacts of adoption.
We enter into operating leases as lessee for certain office space and equipment. We also have a capital lease agreement to lease the land site on which PLT expects to construct storage and terminalling facilities. In November 2018, we entered into an agreement to jointly-own PLT, an entity formed with the intention of developing a storage and terminalling facility. At the same time, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT expects to construct the facilities.
Under ASC 842, a contract is or contains a lease when, (1) the contract contains an explicitly or implicitly identified asset and (2) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. We assess whether an arrangement is or contains a lease at inception of the contract. For all leases (finance and operating leases), other than those that qualify for the short-term recognition exemption, we recognize as of the lease commencement date on the balance sheet a liability for our obligation related to the lease and a corresponding asset representing our right to use the underlying asset over the period of use. The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As most of our leases do not provide an implicit rate, we determine the appropriate discount rate using our incremental secured borrowing rate, with consideration given to the nature and term of the leased asset.
Our leases have remaining terms of up to approximately 40 years. Certain of our lease agreements contain options to extend or early terminate the agreement. The lease term used to calculate the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that we will exercise an option at commencement, we consider various economic factors, including operating strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, we generally determine that the exercise of renewal options would not be reasonably certain in determining the expected lease term.

18


For the three months ended March 31, 2019, operating lease cost and cash paid included in operating cash flows was $0.2 million. During this period the existing finance lease did not have any lease payments or variable lease cost.
Supplemental information related to our existing leases as of March 31, 2019 was as follows:
 
Balance Sheet Location
 
March 31, 2019
Operating Leases:
 
 
(in thousands, except lease term and discount rate)
Operating lease right-of-use assets
Deferred charges and other assets
 
$
2,171

Current operating lease liabilities
Other current liabilities
 
$
603

Non-current operating lease liabilities
Other long-term liabilities and deferred credits
 
$
1,568

 
 
 
 
Finance Leases:
 
 
 
Finance lease right-of-use asset (1)
Property, plant and equipment, net
 
$
30,704

 
 
 
 
Weighted Average Remaining Lease Term:
 
 
 
Operating leases
 
 
4.6 years

Finance leases
 
 
39.7 years

 
 
 
 
Weighted Average Discount Rate:
 
 
 
Operating leases
 
 
4.63
%
Finance leases
 
 
7.01
%
(1)
PLT satisfied the initial capital lease obligation of $30.7 million at lease inception and as a result has no outstanding liability or imputed interest on the future minimum rental commitments.
Maturities of lease liabilities as of March 31, 2019 were as follows:
Year
 
Operating Leases
 
Finance Leases (1)
 
 
(in thousands)
2019 – remaining
 
$
683

 
$
449

2020
 
956

 
449

2021
 
506

 
449

2022
 
240

 
449

2023
 
147

 
449

Thereafter
 
364

 
17,770

Total lease payments
 
2,896

 
20,015

Less: discounting for present value and other adjustments
 
(725
)
 
(20,015
)
Present value of lease liabilities
 
$
2,171

 
$
—

(1)
Future lease payments for finance leases consist of the annual payments under the PLT land site lease. At lease inception, the present value of the future lease payments exceeded the fair value of the leased property. As a result, the right of use asset and capital lease obligation were recorded at the $30.7 million fair value of land. On that date, PLT made a payment of $30.7 million, immediately relieving the capital lease obligation. As a result, PLT does not have an outstanding capital lease obligation or impute interest on the future minimum rental commitments and will recognize expense for the future lease payments in the period in which they are made.
Under various lease agreements, Tallgrass Midstream, LLC ("TMID"), as lessor, leases capacity on NGL pipelines that were constructed for third parties, and Deeprock Development, as lessor, leases capacity at certain of its storage facilities. Rental income for these arrangements was approximately $2.4 million for the three months ended March 31, 2019 and was recorded as "Processing and other revenues" in the condensed consolidated statements of income. Under a lease agreement initially effective November 13, 2012, Tallgrass Interstate Gas Transmission, LLC ("TIGT"), as lessor, leases a portion of its office space to a third party. Rental income was approximately $0.2 million for the three months ended March 31, 2019 and was recorded as "Other income, net" in the condensed consolidated statements of income.

19


At March 31, 2019, future minimum rental income under non-cancelable operating leases as the lessor were as follows:
Year
 
Total
 
 
(in thousands)
2019 - remaining
 
$
5,850

2020
 
3,952

2021
 
3,773

2022
 
3,773

2023
 
3,773

Thereafter
 
7,353

Total
 
$
28,474

Information as of December 31, 2018 under historical lease accounting guidance:
At December 31, 2018, our future minimum rental commitments under major, non-cancelable leases were as follows:
Year
 
Operating Leases
 
Capital Lease
 
 
(in thousands)
2019
 
$
1,074

 
$
449

2020
 
922

 
449

2021
 
483

 
449

2022
 
240

 
449

2023
 
147

 
449

Thereafter
 
364

 
17,770

Total
 
$
3,230

 
$
20,015

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. As of March 31, 2019, the Exchange Right Holders primarily consist of certain of the Sponsor Entities and certain members of our 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 months ended March 31, 2019 and 2018, the assumed issuance of TGE Equity Participation Shares would have had a dilutive effect on basic net income per Class A share as shown in the table below.

20


The following table illustrates the calculation of net income per Class A share for the three months ended March 31, 2019 and 2018:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands, except per unit amounts)
Basic Net Income per Class A Share
 
 
 
Net income attributable to TGE
$
50,587

 
$
16,735

Basic weighted average Class A Shares outstanding
161,425

 
58,085

Basic net income per Class A share
$
0.31

 
$
0.29

Diluted Net Income per Class A Share
 
 
 
Net income attributable to TGE
$
50,587

 
$
16,735

Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares
206

 
69

Net income attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares
$
50,793

 
$
16,804

Basic weighted average Class A Shares outstanding
161,425

 
58,085

Equity Participation Shares equivalent shares
1,352

 
125

Diluted weighted average Class A Shares outstanding
162,777

 
58,210

Diluted net income per Class A Share
$
0.31

 
$
0.29

14. Regulatory Matters
There are no regulatory proceedings challenging the rates of Pony Express and Rockies Express. On May 1, 2019, as further described below, TIGT filed with the FERC a pre–filing settlement that establishes, among other things, settlement rates for supporting/non–contesting participants as defined in the pre–filing settlement. On June 29, 2018, Trailblazer Pipeline Company LLC ("Trailblazer") filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), as further described below. We have also made certain regulatory filings with the FERC, including the following:
Rockies Express
Cheyenne Hub Enhancement Project - FERC Docket No. CP18-103-000
On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector, LLC ("Cheyenne Connector") for the Cheyenne Connector Pipeline Project further described below. The comment period for the Cheyenne Hub Enhancement Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Rockies Express has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. The application is pending before the FERC.
Rockies Express Form No. 501-G Filing - FERC Docket No. RP19-412-000
On December 6, 2018, Rockies Express submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. On March 20, 2019, the FERC issued an order finding that Rockies Express complied with the reporting requirement and terminated the proceeding.
2019 Annual FERC Fuel Tracking Filing - FERC Docket No. RP19-786-000
On February 28, 2019, in Docket No. RP19-786-000, Rockies Express made its annual fuel and power cost tracker filing. The FERC issued an order accepting the filing on March 29, 2019.

21


Cheyenne Connector
Cheyenne Connector Pipeline Project - FERC Docket No. CP18-102-000
On March 2, 2018, Cheyenne Connector, an indirect subsidiary of TGE, submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity to construct and operate a 70-mile 36 inch pipeline to transport natural gas from multiple gas processing plants in Weld County, Colorado to Rockies Express' Cheyenne Hub. The comment period for the Cheyenne Connector Pipeline Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Cheyenne Connector has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. The application is pending before the FERC.
TIGT
TIGT Form No. 501-G Filing - FERC Docket No. RP19-423-000
On December 6, 2018, TIGT submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. On December 18, 2018, one protest and one set of comments were filed by intervenors in the docket. The filing remains pending before the FERC.
2019 Annual Fuel Tracker Filing - FERC Docket No. RP19-715-000
On February 27, 2019, in Docket No. RP19-715-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2019. The FERC accepted the filing on March 22, 2019.
Pre-Filing Settlement - FERC Docket No. RP19-423-001
On May 1, 2019, TIGT filed a pre-filing settlement that, consistent with Article II.B.1 of the Docket No. RP16-137-000 settlement, satisfies TIGT's mandatory filing requirement under Article IIB.1 of such settlement. The pre-filing settlement establishes, inter alia, settlement rates reflecting an overall decrease to recourse rates, contract extensions for maximum recourse rate firm contracts through May 31, 2023, and a moratorium, as well as requires that TIGT file a new NGA Section 4 general rate case on June 1, 2023, provided that TIGT has not preempted this mandatory filing requirement by filing on or before June 1, 2023 for approval of a new pre-filing settlement.
Trailblazer
General Rate Case Filing - FERC Docket No. RP18-922-000, et seq.
On June 29, 2018, Trailblazer filed a general rate case with the FERC, which satisfies the requirement set forth in the settlement resolving Trailblazer's previous general rate case that Trailblazer file a new general rate case with rates to be effective no later than January 1, 2019. The June 29, 2018 filing reflects an overall increase to Trailblazer's cost of service. In the filing, Trailblazer is proposing to maintain its existing bifurcated firm transportation service rate design as well as its current tracking methodologies for the treatment of Fuel and Lost and Unaccounted For ("FL&U") gas and electric power costs. The proposed rates include an increase in rates on Trailblazer's Existing System Firm Transportation Service. The overall rate increase would be partially offset by a proposed decrease in rates for Expansion System Firm Transportation Service and interruptible services. Trailblazer is also proposing to include a cost recovery mechanism in its tariff to recover future eligible costs related to system safety, integrity, reliability, environmental and cybersecurity issues. Under the NGA and the FERC's regulations, Trailblazer's shippers and other interested parties, including the FERC's Trial Staff, have the right to challenge any aspect of Trailblazer's rate case filing. On July 11, 2018, four protests were filed that challenge various aspects of Trailblazer's rate case filing. FERC action remains pending.
On July 31, 2018, the FERC issued an Order accepting and suspending the rate case filing, and establishing hearing and settlement procedures. In the Order, the FERC approved the as-filed rate decreases for Expansion System Firm Transportation Service, as well as Trailblazer's interruptible services, effective August 1, 2018. The Commission also established a paper hearing to examine the extent to which Trailblazer is entitled to an income tax allowance. All remaining issues, including the proposed rate increases to Existing System Firm Transportation Service have been set for hearing and are accepted effective January 1, 2019, subject to refund. On August 30, 2018, Trailblazer and certain of Trailblazer's shippers filed a request for rehearing of the July 31, 2018 Order, which remains pending before the FERC. Consistent with the July 31, 2018 Order, on August 30, 2018, certain of Trailblazer's shippers and other interested parties filed initial briefs regarding the Income Tax Allowance issue. Trailblazer filed its reply brief regarding the same on September 14, 2018. On November 1, 2018, Trailblazer

22


filed a supplement to its reply brief addressing a recent FERC order regarding the appropriate methodology used to calculate return on equity and discussing the impact of such order on Trailblazer's proposed Income Tax Allowance.
On February 21, 2019, the FERC issued an Order stating a preliminary finding that a double recovery appears to result from permitting an income tax allowance for the income tax liability attributable to certain private owners' ownership share in Trailblazer in addition to a discounted cash flow return on equity. The FERC also preliminary found that no double recovery resulted from permitting an income tax allowance for the corporate income tax liability attributable to TGE's ownership share in Trailblazer in addition to a discounted cash flow return on equity. The FERC emphasized that the findings are preliminary and may change based upon subsequent evidence and argument. The FERC ordered that the income tax allowance be addressed at the hearing with the other remaining issues. On February 22, 2019, the Chief Administrative Law Judge issued an order directing the ongoing settlement judge procedures and any subsequent hearing in the proceeding to address all income tax allowance issues. 
On August 28, 2018, the participants attended an initial settlement conference. On November 15, 2018, the participants attended a second settlement conference. On December 31, 2018, Trailblazer filed a motion with the FERC to move the suspended tariff records into effect as of January 1, 2019. In January 2019, the participants attended a third settlement conference. In February 2019, the participants attended a fourth settlement conference. On February 14, 2019, Trailblazer filed its 45-day update. On March 14, 2019, the Chief Administrative Law Judge issued an order terminating settlement judge procedures, designating a Presiding Judge for the purpose of conducting a hearing and issuing an initial decision, establishing Track III procedural time standards for the hearing and directing that a prehearing conference be convened within 15 days of the date of the order. On March 19, 2019, the Presiding Judge issued an order to convene the prehearing conference on March 26, 2019. Following the prehearing conference, on March 28, 2019, the Presiding Judge issued an order establishing a procedural schedule and hearing rules in connection with the Chief Administrative Law Judge's March 28, 2019 order extending the Track III procedural deadlines.
2019 Annual Fuel Tracker Filing - FERC Docket No. RP19-888-000
On March 25, 2019, in Docket No. RP19-888-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2018. The FERC accepted the filing on April 18, 2019.
Pony Express
On January 11, 2019, Pony Express filed with the FERC in Docket No. IS19-145-000 certain changes to its tariffs to incorporate the Sterling origin point in Logan County, Colorado in the published rate schedules, to establish a line fill return rate from the Natoma origin point, and to make minor clarifying edits.
Iron Horse
Petition for Declaratory Order - FERC Docket No. OR19-9-000
On November 9, 2018, Iron Horse filed a Petition for Declaratory Order with the FERC, requesting approval of Iron Horse's proposed rate structures, Committed Shipper rights, and prorationing provisions for shippers and various other aspects of the Transportation Service Agreement for service on the pipeline. The FERC granted the Petition on April 11, 2019.
Baseline Tariff Filing - FERC Docket No. IS19-274-000
On April 1, 2019, Iron Horse filed certain baseline tariffs with the FERC, each with an effective date of May 1, 2019.
15. Legal and Environmental Matters
Legal
In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such matters will not have a material adverse impact on our business, financial position, results of operations, or cash flows.
We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, have recorded no reserve for legal claims as of March 31, 2019 or December 31, 2018.

23


Rockies Express
Ohio Public Utility Excise Tax
The Ohio Tax Commissioner has assessed Rockies Express a public utility excise tax on transactions concerning product that entered and exited Rockies Express within the state of Ohio. This tax applies to gross receipts from all business conducted within the state, but exempts all receipts derived wholly from interstate business. Rockies Express has disputed any obligation to pay Ohio's public utility excise tax, but has paid the taxes as assessed in order to preserve its right to appeal. The dispute is currently pending before the Ohio Supreme Court, with a final decision possible by the end of 2019. It is Rockies Express' position that the relevant statute exempts receipts derived wholly from interstate business from the public utility excise tax. The Ohio Supreme Court and the United States Supreme Court have both held that, once it enters an interstate pipeline, natural gas is moving in "interstate commerce" for the duration of its journey until it is delivered to a local distribution system.
As of March 31, 2019, Rockies Express has paid public utility excise taxes to the state of Ohio totaling $7.1 million and has accrued an additional $4.6 million for amounts expected to be assessed for the period from May 1, 2018 through March 31, 2019. While it is difficult to accurately predict how the Ohio Supreme Court will decide the case, Rockies Express is optimistic about the ultimate outcome and has recorded a $11.7 million asset representing the anticipated refund of the public utility excise taxes paid.
Environmental, Health and Safety
We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We currently believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $6.8 million and $7.4 million at March 31, 2019 and December 31, 2018, respectively.
Rockies Express
Seneca Lateral
On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations. The release required Rockies Express to shut off the flow through the segment until February 27, 2018, when temporary repairs were completed allowing the segment to be placed back into service. Permanent repairs were completed in September 2018. Total cost of remediation was approximately $6.1 million, $5.1 million of which Rockies Express has recovered through insurance.
TMID and TIGT
Casper Plant, EPA Notice of Violation
In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, TMID received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. TMID and TIGT entered into a Consent Agreement and Final Order to settle this matter with the EPA on February 21, 2019 and made an approximately $0.1 million penalty payment to the EPA.
Casper Gas Plant
On November 25, 2014, the WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. TMID and TIGT entered into a Consent Decree to settle this matter with the WDEQ on March 8, 2019 and made an approximately $0.1 million penalty payment to the WDEQ.

24


TMG
Archibald Booster Station
Tallgrass Midstream Gathering, LLC ("TMG") is currently a party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Archibald Booster Station located in Campbell County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling, and quarterly recovery activities at monitoring wells. The facility is currently in compliance with the WDEQ under the remedy agreement.
Irwin Booster Station
TMG is also party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Irwin Booster Station located in Converse County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling. The facility is currently in compliance with the WDEQ under the remedy agreement.
16. Reportable Segments
Our operations are located in the United States. We are organized into three reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & Terminalling. Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit facility and the Senior Notes, public company costs, equity-based compensation expense, and eliminations of intersegment activity.
Natural Gas Transportation. The Natural Gas Transportation segment is engaged in the ownership and operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facility that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. The Natural Gas Transportation segment includes our 75% membership interest in Rockies Express.
Crude Oil Transportation. The Crude Oil Transportation segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, and other nearby oil producing basins. The Crude Oil Transportation segment includes our 51% membership interest in Powder River Gateway.
Gathering, Processing & Terminalling. The Gathering, Processing & Terminalling segment is engaged in the ownership and operation of natural gas gathering and processing facilities that produce NGLs and residue gas sold in local wholesale markets or delivered into pipelines for transportation to additional end markets; our crude oil terminal services; water business services provided primarily to the oil and gas exploration and production industry; the transportation of NGLs; and Stanchion.
These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations.
We consider Adjusted EBITDA to be our primary segment performance measure as we believe it is the most meaningful measure to assess our financial condition and results of operations as a public entity. We define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments and deficiency payments received from or utilized by our customers. Adjusted EBITDA is calculated and presented at the Tallgrass Equity level, before consideration of noncontrolling interest associated with the Exchange Right Holders, which we believe provides investors the most complete and comparable picture of our overall financial and operational results.

25


The following tables set forth our segment information for the periods indicated:
 
Three Months Ended March 31, 2019
 
Three Months Ended March 31, 2018
Revenue:
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
Total
Revenue
 
Inter-
Segment
 
External
Revenue
 
(in thousands)
Natural Gas Transportation
$
35,842

 
$
(414
)
 
$
35,428

 
$
36,202

 
$
(1,858
)
 
$
34,344

Crude Oil Transportation
109,784

 
(14,422
)
 
95,362

 
89,966

 
(3,319
)
 
86,647

Gathering, Processing & Terminalling
74,034

 
(7,472
)
 
66,562

 
63,838

 
(5,735
)
 
58,103

Total revenue
$
219,660

 
$
(22,308
)
 
$
197,352

 
$
190,006

 
$
(10,912
)
 
$
179,094

 
Three Months Ended March 31, 2019
 
Three Months Ended March 31, 2018
Tallgrass Equity Adjusted EBITDA:
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
Total
Adjusted
EBITDA
 
Inter-
Segment
 
External
Adjusted
EBITDA
 
(in thousands)
Natural Gas Transportation
$
138,868

 
$
(905
)
 
$
137,963

 
$
70,652

 
$
(735
)
 
$
69,917

Crude Oil Transportation
80,741

 
(6,160
)
 
74,581

 
34,871

 
1,386

 
36,257

Gathering, Processing & Terminalling
27,910

 
7,065

 
34,975

 
10,156

 
(651
)
 
9,505

Corporate and Other
(1,794
)
 
—

 
(1,794
)
 
(12,269
)
 
—

 
(12,269
)
Reconciliation to Net Income:
 
 
 
 
 
 
 
 
 
 
 
Add:
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated investments (1)
 
 
 
 
88,522

 
 
 
 
 
32,413

Gain on disposal of assets (1)
 
 
 
 
—

 
 
 
 
 
3,212

Less:
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net (1)
 
 
 
 
(39,710
)
 
 
 
 
 
(10,786
)
Depreciation and amortization expense (1)
 
 
 
 
(30,728
)
 
 
 
 
 
(8,496
)
Distributions from unconsolidated investments (1)
 
 
 
 
(115,098
)
 
 
 
 
 
(43,491
)
Non-cash compensation expense (1)
 
 
 
 
(17,120
)
 
 
 
 
 
(962
)
Deficiency payments, net (1)
 
 
 
 
(12,144
)
 
 
 
 
 
(3,780
)
Non-cash (loss) gain related to derivative instruments (1)
 
 
 
 
(1,252
)
 
 
 
 
 
872

Deferred income tax expense
 
 
 
 
(17,066
)
 
 
 
 
 
(6,692
)
Net income attributable to Exchange Right Holders
 
 
 
 
(50,542
)
 
 
 
 
 
(48,965
)
Net income attributable to TGE
 
 
 
 
$
50,587

 
 
 
 
 
$
16,735

(1) 
Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.
 
Three Months Ended March 31,
Capital Expenditures:
2019
 
2018
 
(in thousands)
Natural Gas Transportation
$
16,346

 
$
9,885

Crude Oil Transportation
17,016

 
16,952

Gathering, Processing & Terminalling
27,814

 
31,139

Corporate and Other
1,626

 
784

Total capital expenditures
$
62,802

 
$
58,760


26


Assets:
March 31, 2019
 
December 31, 2018
 
(in thousands)
Natural Gas Transportation
$
2,608,355

 
$
2,606,696

Crude Oil Transportation
1,711,706

 
1,423,740

Gathering, Processing & Terminalling
1,471,995

 
1,522,559

Corporate and Other
277,169

 
340,514

Total assets
$
6,069,225

 
$
5,893,509


27


17. Subsequent Events
Rockies Express Senior Notes Offering
On April 12, 2019, Rockies Express and U.S. Bank, National Association, as trustee, entered into an Indenture pursuant to which Rockies Express issued $550 million in aggregate principal amount of 4.95% senior notes due 2029. Substantially all of the net proceeds received by Rockies Express from the senior notes offering were used to repay Rockies Express' $525 million term loan facility.
Acquisition of Central Environmental Services
On April 24, 2019, BNN Eastern, LLC ("BNN Eastern"), an indirect subsidiary of TGE, entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of K & H Partners LLC (a company doing business as Central Environmental Services, or CES). CES owns a salt water disposal facility located in the Utica and Marcellus area of Ohio. On May 1, 2019, the acquisition closed for total purchase consideration of approximately $52 million paid at closing, and a seller in the transaction received a 7.65% membership interest in BNN Eastern. In addition to the consideration paid at closing, the transaction includes a potential earn out payment to the sellers of approximately $3 million, which is payable in cash or in additional membership interests in BNN Eastern. The initial accounting for the transaction is not yet complete as management does not have the information necessary to prepare pro forma financial information or value the assets acquired and liabilities assumed.

28


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
As used in this Quarterly Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TGE" and similar terms refer to Tallgrass Energy, LP, in its individual capacity or to Tallgrass Energy, LP and its consolidated subsidiaries collectively (including Tallgrass Equity, LLC, Tallgrass Energy Partners, LP and their respective subsidiaries), as the context requires. References to "Tallgrass Equity" refer to Tallgrass Equity, LLC. References to "TEP" refer to Tallgrass Energy Partners, LP. The term our "general partner" refers to Tallgrass Energy GP, LLC. References to "Tallgrass Development" or "TD" refer to Tallgrass Development, LP. 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report. Additionally, the following discussion and analysis should be read in conjunction with our audited financial statements and notes thereto, the related "Management's Discussion and Analysis of Financial Condition and Results of Operations," the discussion of "Risk Factors" and the discussion of TGE's "Business" in our Annual Report on Form 10-K for the year ended December 31, 2018 (our "2018 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 8, 2019.
A reference to a "Note" herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1.—Financial Statements. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.
Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report and the documents incorporated by reference herein contain forward-looking statements concerning our operations, economic performance and financial condition. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "could," "will," "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this Quarterly Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
•
our ability to pay dividends to our Class A shareholders;
•
our expected receipt of, and amounts of, distributions from Tallgrass Equity;
•
our ability to complete and integrate acquisitions, including integrating the acquisitions discussed in Note 3 – Acquisitions;
•
the demand for our services, including natural gas transportation and storage; crude oil transportation; and natural gas gathering and processing, crude oil storage and terminalling services, and water business services;
•
our ability to successfully contract or re-contract with our customers;
•
large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;
•
our ability to successfully implement our business plan;
•
changes in general economic conditions;
•
competitive conditions in our industry;
•
the effects of existing and future laws and governmental regulations;
•
actions taken by governmental regulators of our assets, including the FERC;
•
actions taken by third-party operators, processors and transporters;

29


•
our ability to complete internal growth projects on time and on budget;
•
the price and availability of debt and equity financing;
•
the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil, natural gas, natural gas liquids, and other hydrocarbons;
•
the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the price of alternative and competing fuels;
•
competition from the same and alternative energy sources;
•
energy efficiency and technology trends;
•
operating hazards and other risks incidental to transporting, storing, and terminalling crude oil; transporting, storing, gathering and processing natural gas; and transporting, gathering and disposing of water produced in connection with hydrocarbon exploration and production activities;
•
environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
•
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
•
interest rates;
•
labor relations;
•
changes in tax laws, regulations and status;
•
the effects of existing and future litigation; and
•
certain factors discussed elsewhere in this Quarterly Report.
Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.
Overview
TGE 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.
Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity in which we directly own an approximate 63.70% membership interest as of May 7, 2019. 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 FERC-regulated crude oil pipeline systems; 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.
Recent Developments
TGE Dividend Announced
On April 11, 2019, the Board of Directors of our general partner declared a cash dividend for the quarter ended March 31, 2019 of $0.5300 per Class A share. The distribution will be paid on May 15, 2019, to Class A shareholders of record on April 30, 2019.
Rockies Express Senior Notes Offering
On April 12, 2019, Rockies Express and U.S. Bank, National Association, as trustee, entered into an Indenture pursuant to which Rockies Express issued $550 million in aggregate principal amount of 4.95% senior notes due 2029. Substantially all of the net proceeds received by Rockies Express from the senior notes offering were used to repay Rockies Express' $525 million term loan facility.

30


Acquisition of Central Environmental Services
On April 24, 2019, BNN Eastern, LLC ("BNN Eastern"), an indirect subsidiary of TGE, entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of K & H Partners LLC (a company doing business as Central Environmental Services, or CES). CES owns a salt water disposal facility located in the Utica and Marcellus area of Ohio. On May 1, 2019, the acquisition closed for total purchase consideration of approximately $52 million paid at closing, and a seller in the transaction received a 7.65% membership interest in BNN Eastern. In addition to the consideration paid at closing, the transaction includes a potential earn out payment to the sellers of approximately $3 million, which is payable in cash or in additional membership interests in BNN Eastern.
How We Evaluate Our Operations
We evaluate our results using, among other measures, contract profile and volumes, operating costs and expenses, Adjusted EBITDA and Cash Available for Dividends. Adjusted EBITDA and Cash Available for Dividends are non-GAAP measures and are defined below.
Contract Profile and Volumes
Our results are driven primarily by the volume of natural gas transportation and storage capacity, crude oil transportation, storage, and terminalling capacity, NGL transportation capacity, and water transportation, gathering, recycling and disposal capacity under firm fee contracts, as well as the volume of natural gas that we gather and process and the fees assessed for such services.
Operating Costs and Expenses
The primary components of operating costs and expenses that we evaluate include cost of sales, cost of transportation services, operations and maintenance and general and administrative costs. Operating expenses are driven primarily by expenses related to the operation, maintenance and growth of our asset base.
Adjusted EBITDA and Cash Available for Dividends
Adjusted EBITDA and Cash Available for Dividends are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
•
our operating performance as compared to other publicly traded midstream infrastructure companies, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;
•
the ability of our assets to generate sufficient cash flow to make dividends to our shareholders;
•
our ability to incur and service debt and fund capital expenditures; and
•
the viability of acquisitions and other capital expenditure projects and the returns on investment of various expansion and growth opportunities.
We believe that the presentation of Adjusted EBITDA and Cash Available for Dividends provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and Cash Available for Dividends should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, nor should Adjusted EBITDA and Cash Available for Dividends be considered alternatives to available cash or other definitions in our partnership agreement. Adjusted EBITDA and Cash Available for Dividends have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and Cash Available for Dividends may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and Cash Available for Dividends may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

31


Non-GAAP Financial Measures
We generally define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments and deficiency payments received from or utilized by our customers. We also use Cash Available for Dividends, which we generally define as Adjusted EBITDA, less cash interest costs, maintenance capital expenditures, and certain cash reserves permitted by our governing documents. Adjusted EBITDA and Cash Available for Dividends are both calculated and presented at the Tallgrass Equity level, before consideration of noncontrolling interest associated with the Exchange Right Holders or calculating distributions from Tallgrass Equity to us, on one hand, and to the Exchange Right Holders, on the other. We believe calculating these measures at Tallgrass Equity provides investors the most complete and comparable picture of our overall financial and operational results and provides a consistent metric for period over period comparisons that is not impacted by any future exercises by the Exchange Right Holders of the Exchange Right, which does not have a dilutive effect on TGE's net income per share.
Maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements, and are presented net of noncontrolling interest and reimbursements. We collect deficiency payments for volumes committed by our customers to be transported in a month but not physically received for transport or delivered to the customers' agreed upon destination point. These deficiency payments are recorded as a deferred liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote.

32


Adjusted EBITDA and Cash Available for Dividends are not presentations made in accordance with GAAP. The following table presents a reconciliation of Adjusted EBITDA to Net income attributable to TGE and net cash provided by operating activities and a reconciliation of Cash Available for Dividends to net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Reconciliation of Tallgrass Equity Adjusted EBITDA to Net income attributable to TGE
 
 
 
Net income attributable to TGE
$
50,587

 
$
16,735

Add:
 
 
 
Interest expense, net (1)
39,710

 
10,786

Depreciation and amortization expense (1)
30,728

 
8,496

Distributions from unconsolidated investments (1)
115,098

 
43,491

Deficiency payments, net (1)
12,144

 
3,780

Non-cash compensation expense (1)(2)
17,120

 
962

Non-cash loss (gain) related to derivative instruments (1)
1,252

 
(872
)
Deferred income tax expense
17,066

 
6,692

Net income attributable to Exchange Right Holders
50,542

 
48,965

Less:
 
 
 
Equity in earnings of unconsolidated investments (1)
(88,522
)
 
(32,413
)
Gain on disposal of assets (1)
—

 
(3,212
)
Tallgrass Equity Adjusted EBITDA
$
245,725

 
$
103,410

Reconciliation of Tallgrass Equity Adjusted EBITDA and Cash Available for Dividends to Net Cash Provided by Operating Activities
 
 
 
Net cash provided by operating activities
$
143,748

 
$
151,600

Add:
 
 
 
Interest expense, net (1)
39,710

 
10,786

Other, including changes in operating working capital (1)
62,267

 
(58,976
)
Tallgrass Equity Adjusted EBITDA
$
245,725

 
$
103,410

Less:
 
 
 
Cash interest cost (1)
(38,139
)
 
(10,282
)
Maintenance capital expenditures, net (1)
(6,988
)
 
(1,026
)
Tallgrass Equity Cash Available for Dividends
$
200,598

 
$
92,102

(1) 
Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.
(2) 
Represents TGE's portion of non-cash compensation expense related to Equity Participation Shares and TEP's Equity Participation Units, excluding amounts allocated to TD prior to the merger of TD into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity, on February 7, 2018.

33


The following table presents a reconciliation of Adjusted EBITDA by segment to segment operating income, the most directly comparable GAAP financial measure, for each of the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Natural Gas Transportation Segment (1)
 
 
 
Operating income
$
19,936

 
$
19,384

Add:
 
 
 
Depreciation and amortization expense (2)
4,948

 
1,571

Distributions from unconsolidated investment (2)
113,395

 
43,491

Other, net (2)
589

 
576

Less:
 
 
 
Adjusted EBITDA attributable to noncontrolling interests
—

 
5,630

Tallgrass Equity Segment Adjusted EBITDA
$
138,868

 
$
70,652

Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Crude Oil Transportation Segment (1)
 
 
 
Operating income
$
61,437

 
$
46,527

Add:
 
 
 
Depreciation and amortization expense (2)
13,699

 
4,348

Deficiency payments, net (2)
5,605

 
2,641

Less:
 
 
 
Adjusted EBITDA attributable to noncontrolling interests
—

 
(18,645
)
Tallgrass Equity Segment Adjusted EBITDA
$
80,741

 
$
34,871

Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Gathering, Processing & Terminalling Segment (1)
 
 
 
Operating income
$
8,609

 
$
23,305

Add:
 
 
 
Depreciation and amortization expense (2)
11,477

 
2,354

Non-cash loss (gain) related to derivative instruments (2)
1,252

 
(872
)
Distributions from unconsolidated investments (2)
1,703

 
—

Deficiency payments, net (2)
6,147

 
1,014

Other, net (2)
(20
)
 
—

Less:
 
 
 
Gain on disposal of assets (2)
—

 
(3,212
)
Adjusted EBITDA attributable to noncontrolling interests
(1,258
)
 
(12,433
)
Tallgrass Equity Segment Adjusted EBITDA
$
27,910

 
$
10,156

Total Tallgrass Equity Segment Adjusted EBITDA
$
247,519

 
$
115,679

Corporate general and administrative costs
(1,794
)
 
(12,269
)
Total Tallgrass Equity Adjusted EBITDA
$
245,725

 
$
103,410

(1) 
Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for the Natural Gas Transportation, Crude Oil Transportation, and Gathering, Processing & Terminalling segments. For reconciliations to the consolidated financial data, see Note 16 – Reportable Segments.
(2) 
Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.

34


Results of Operations
The following provides a summary of our operating metrics for the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
Natural Gas Transportation Segment:
 
 
 
TIGT and Trailblazer average firm contracted volumes (MMcf/d) (1)
1,914

 
1,842

Rockies Express average firm contracted volumes (MMcf/d) (2)
4,204

 
4,107

Crude Oil Transportation Segment:
 
 
 
Crude oil transportation average contracted capacity (Bbls/d)
308,580

 
303,580

Crude oil transportation average throughput (Bbls/d)
335,749

 
289,739

Gathering, Processing & Terminalling Segment:
 
 
 
Natural gas processing inlet volumes (MMcf/d)
109

 
117

Freshwater average volumes (Bbls/d)
27,418

 
45,512

Produced water gathering and disposal average volumes (Bbls/d)
160,431

 
85,406

(1) 
Volumes transported under firm fee contracts, excluding Rockies Express.
(2) 
Volumes transported under long-term firm fee contracts.

35


The following provides a summary of our consolidated results of operations for the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Revenues:
 
 
 
Crude oil transportation services
$
95,156

 
$
84,738

Natural gas transportation services
33,516

 
32,196

Sales of natural gas, NGLs, and crude oil
38,864

 
38,145

Processing and other revenues
29,816

 
24,015

Total Revenues
197,352

 
179,094

Operating Costs and Expenses:
 
 
 
Cost of sales
19,285

 
26,351

Cost of transportation services
15,072

 
10,420

Operations and maintenance
18,046

 
16,399

Depreciation and amortization
31,001

 
26,123

General and administrative
32,272

 
18,426

Taxes, other than income taxes
10,998

 
8,879

Loss (gain) on disposal of assets
214

 
(9,417
)
Total Operating Costs and Expenses
126,888

 
97,181

Operating Income
70,464

 
81,913

Other Income (Expense):
 
 
 
Equity in earnings of unconsolidated investments
88,522

 
68,402

Interest expense, net
(39,705
)
 
(29,761
)
Other income, net
177

 
451

Total Other Income (Expense)
48,994

 
39,092

Net income before tax
119,458

 
121,005

Deferred income tax expense
(17,066
)
 
(6,692
)
Net income
102,392

 
114,313

Net income attributable to noncontrolling interests
(51,805
)
 
(97,578
)
Net income attributable to TGE
$
50,587

 
$
16,735

Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018
Revenues. Total revenues were $197.4 million for the three months ended March 31, 2019, compared to $179.1 million for the three months ended March 31, 2018, which represents an increase of $18.3 million, or 10%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $19.8 million and $10.2 million in the Crude Oil Transportation and Gathering, Processing & Terminalling segments, respectively, partially offset by a $11.3 million increase in eliminations of intersegment revenue and decreased revenues of $0.4 million in the Natural Gas Transportation segment, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $126.9 million for the three months ended March 31, 2019 compared to $97.2 million for the three months ended March 31, 2018, which represents an increase of $29.7 million, or 31%. The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $24.9 million, $4.9 million, and $0.8 million in the Gathering, Processing & Terminalling, Crude Oil Transportation, and Corporate and Other segments, respectively, partially offset by decreased operating costs and expenses of $0.9 million in the Natural Gas Transportation segment, as discussed further below. The increase in Corporate and Other expenses was primarily driven by a $12.1 million increase in corporate general and administrative costs, partially offset by a $11.3 million increase in eliminations of intersegment operating costs and expenses. The increase in corporate general and administrative costs was primarily due to an increase in equity-based compensation costs related to the accelerated vesting of certain Equity Participation Shares as a result of the change in control triggered by the Blackstone Acquisition.

36


Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $88.5 million and $68.4 million for the three months ended March 31, 2019 and 2018, respectively. Equity in earnings of unconsolidated investments of $88.5 million for the three months ended March 31, 2019 primarily reflects our portion of earnings and the $8.5 million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies Express, as well as equity in earnings of $1.4 million and $0.9 million, respectively, related to our 51% membership interests in Pawnee Terminal, LLC ("Pawnee Terminal") and Powder River Gateway. Equity in earnings of unconsolidated investments of $68.4 million for the three months ended March 31, 2018 primarily reflects our portion of earnings and the $8.4 million of amortization of a negative basis difference associated with our 75% membership interest in Rockies Express, inclusive of Tallgrass Equity's additional 25.01% membership interest acquired in February 2018, as well as $1.3 million of equity in earnings related to our 63% membership interest in BNN Colorado. The overall increase was primarily driven by a $19.2 million increase in equity in earnings from Rockies Express as a result of the additional 25% membership interest acquired in February 2018, as well as lower interest expense at Rockies Express due to the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018.
Interest expense, net. Interest expense of $39.7 million for the three months ended March 31, 2019 was primarily composed of interest and fees associated with the TEP revolving credit facility and Senior Notes. Interest expense of $29.8 million for the three months ended March 31, 2018 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities and the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017 and December 11, 2017. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our 2018 and 2019 acquisitions and a special contribution to Rockies Express to fund our pro rata portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018, as well as the higher borrowing rate on the Senior Notes, the proceeds of which were used to repay borrowings under the revolving credit facility.
Other income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income for the three months ended March 31, 2019 was $0.2 million compared to $0.5 million of other income for the three months ended March 31, 2018.
Deferred income tax expense. Deferred income tax expense for the three months ended March 31, 2019 was $17.1 million, compared to deferred income tax expense of $6.7 million for the three months ended March 31, 2018. The increase in deferred income tax expense was primarily due to our increased ownership in TEP effective June 30, 2018 as a result of the merger transaction with TEP and the exercise of the Exchange Right effective March 11, 2019 and the resulting increase in income allocated to TGE.
The following provides a summary of our Natural Gas Transportation segment results of operations for the periods indicated:
Segment Financial Data – Natural Gas Transportation (1)
Three Months Ended March 31,
2019
 
2018
 
(in thousands)
Revenues:
 
 
 
Natural gas transportation services
$
33,930

 
$
34,054

Sales of natural gas, NGLs, and crude oil
—

 
237

Processing and other revenues
1,912

 
1,911

Total revenues
35,842

 
36,202

Operating costs and expenses:
 
 
 
Cost of sales
—

 
343

Cost of transportation services
(262
)
 
132

Operations and maintenance
6,040

 
6,163

Depreciation and amortization
4,948

 
4,827

General and administrative
3,880

 
3,934

Taxes, other than income taxes
1,300

 
1,419

Total operating costs and expenses
15,906

 
16,818

Operating income
$
19,936

 
$
19,384

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

37


Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018
Revenues. Natural Gas Transportation segment revenues were $35.8 million for the three months ended March 31, 2019, compared to $36.2 million for the three months ended March 31, 2018, which represents a decrease of $0.4 million in segment revenues primarily due to a $0.2 million decrease in sales of natural gas driven by decreased volumes of natural gas sold.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $15.9 million for the three months ended March 31, 2019, compared to $16.8 million for the three months ended March 31, 2018, which represents a decrease of $0.9 million, or 5%. The overall decrease in operating costs and expenses was primarily due to a $0.4 million decrease in cost of transportation services driven by increased cash settlements of shipper imbalances at TIGT during the three months ended March 31, 2019 and a $0.3 million decrease in cost of sales driven by decreased volumes of natural gas sold.
The following provides a summary of our Crude Oil Transportation segment results of operations for the periods indicated:
Segment Financial Data – Crude Oil Transportation (1)
Three Months Ended March 31,
2019
 
2018
 
(in thousands)
Revenues:
 
 
 
Crude oil transportation services
$
109,578

 
$
88,057

Sales of natural gas, NGLs, and crude oil
—

 
1,909

Processing and other revenues
206

 
—

Total revenues
109,784

 
89,966

Operating costs and expenses:
 
 
 
Cost of sales
521

 
1,966

Cost of transportation services
16,898

 
14,387

Operations and maintenance
3,050

 
2,870

Depreciation and amortization
13,699

 
13,366

General and administrative
5,456

 
4,492

Taxes, other than income taxes
8,723

 
6,358

Total operating costs and expenses
48,347

 
43,439

Operating income
$
61,437

 
$
46,527

(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 16 – Reportable Segments.
Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018
Revenues. Crude Oil Transportation segment revenues were $109.8 million for the three months ended March 31, 2019, compared to $90.0 million for the three months ended March 31, 2018, which represents an increase of $19.8 million, or 22%, in segment revenues driven by a $21.5 million increase in crude oil transportation services, partially offset by a $1.9 million decrease in sales of crude oil primarily due to decreased volumes sold during the three months ended March 31, 2019. The increase in crude oil transportation services revenue was primarily driven by a $10.6 million increase in walk-up barrels shipped, a $5.7 million increase in committed volume shipments, and a $4.1 million increase due to the FERC annual index adjustments effective July 1, 2018.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $48.3 million for the three months ended March 31, 2019 compared to $43.4 million for the three months ended March 31, 2018, which represents an increase of $4.9 million, or 11%. The overall increase in operating costs and expenses was primarily driven by a $2.5 million increase in cost of transportation services driven by higher throughput volumes during the three months ended March 31, 2019 compared to the three months ended March 31, 2018 and a $2.4 million increase in taxes, other than income taxes driven by an increase in property tax assessment estimates.

38


The following provides a summary of our Gathering, Processing & Terminalling segment results of operations for the periods indicated:
Segment Financial Data – Gathering, Processing & Terminalling (1)
Three Months Ended March 31,
2019
 
2018
 
(in thousands)
Revenues:
 
 
 
Sales of natural gas, NGLs, and crude oil
$
38,864

 
$
35,999

Processing and other revenues
35,170

 
27,839

Total revenues
74,034

 
63,838

Operating costs and expenses:
 
 
 
Cost of sales
18,879

 
24,566

Cost of transportation services
20,629

 
6,289

Operations and maintenance
8,956

 
7,366

Depreciation and amortization
11,750

 
7,294

General and administrative
4,022

 
3,333

Taxes, other than income taxes
975

 
1,102

Loss (gain) on disposal of assets
214

 
(9,417
)
Total operating costs and expenses
65,425

 
40,533

Operating income
$
8,609

 
$
23,305

(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 16 – Reportable Segments.
Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018
Revenues. Gathering, Processing & Terminalling segment revenues were $74.0 million for the three months ended March 31, 2019, compared to $63.8 million for the three months ended March 31, 2018, which represents a $10.2 million, or 16%, increase in segment revenues. The increase in segment revenues was due to a $7.3 million increase in processing and other revenues and a $2.9 million increase in sales of natural gas, NGLs, and crude oil. The increase in processing and other revenues was driven by (i) increased water business services revenue of $5.1 million driven by the acquisition of NGL Water Solutions Bakken, LLC ("NGL Water Solutions Bakken") in November 2018 and increased produced water disposal volumes, partially offset by decreased fresh water transportation volumes and (ii) increased terminal services revenue of $2.2 million driven by the Buckingham Terminal expansion and the Natoma Terminal placed into service in April 2018. The increase in sales of natural gas, NGLs, and crude oil was driven by (i) increased crude oil sales of $7.2 million at Stanchion and (ii) increased sales of natural gas of $2.6 million due to sales of residue gas from the Douglas Gathering System; partially offset by decreased sales of NGLs of $6.7 million primarily due to lower NGL prices.
Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $65.4 million for the three months ended March 31, 2019 compared to $40.5 million for the three months ended March 31, 2018, which represents an increase of $24.9 million, or 61%. The increase in operating costs and expenses was primarily driven by (i) an increase of $14.3 million in the cost of transportation services due to crude oil transportation fees paid by Stanchion and increased water gathering and disposal volumes at Water Solutions, (ii) $0.2 million loss on the disposal of assets during the three months ended March 31, 2019, compared to the $9.4 million gain on disposal of assets on the disposal of Tallgrass Crude Gathering, LLC ("TCG") during the three months ended March 31, 2018, and (iii) increased depreciation and amortization expense of $4.5 million primarily due to acquisitions and assets placed into service in 2018 and 2019 at Water Solutions and Terminals. These increases were partially offset by a $5.7 million decrease in cost of sales primarily due to lower NGL prices as discussed above.

39


Liquidity and Capital Resources Overview
Our primary sources of liquidity for the three months ended March 31, 2019 were cash generated from operations and borrowings under our revolving credit facility. We expect our sources of liquidity in the future to include:
•
cash generated from our operations;
•
borrowing capacity available under our revolving credit facility; and
•
future issuances of additional equity and/or debt securities.
We believe that cash on hand, cash generated from operations, and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements, and our planned cash dividends to shareholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of cash generated from operations, borrowings under our revolving credit facility and issuances of debt and/or equity securities. For additional information regarding our revolving credit facilities and senior unsecured notes, see Note 9 – Long-term Debt. For additional information regarding our equity transactions, see Note 10 – Partnership Equity.
Our total liquidity as of March 31, 2019 and December 31, 2018 was as follows:
 
March 31, 2019
 
December 31, 2018
 
(in thousands)
Cash on hand (1)
$
15,042

 
$
9,596

Total capacity under the revolving credit facility
2,250,000

 
2,250,000

Less: Outstanding borrowings under the revolving credit facility
(1,349,000
)
 
(1,224,000
)
Less: Letters of credit issued under the revolving credit facility
(94
)
 
(94
)
Available capacity under the revolving credit facility
900,906

 
1,025,906

Total liquidity
$
915,948

 
$
1,035,502

(1) 
Includes cash on hand at TGE and its consolidated subsidiaries.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. While various other factors may impact our working capital requirements from period to period, our working capital requirements have typically been, and we expect will continue to be, driven by changes in accounts receivable, accounts payable and deferred revenue. We manage our working capital needs through borrowings and repayments of borrowings under our revolving credit facility. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, and the level of spending for capital expenditures. Changes in the market prices of energy commodities that we buy and sell in the normal course of business can also impact the timing of changes in accounts receivable and accounts payable. Factors impacting deferred revenue include the volume of barrels transported, the amount of deficiency payments received, and the volume of prior deficiencies utilized during the period.
As of March 31, 2019, we had a working capital deficit of $116.1 million compared to a working capital deficit of $146.9 million at December 31, 2018, which represents a decrease in the working capital deficit of $30.8 million. The overall decrease in the working capital deficit was primarily attributable to changes in the following components:
•
a decrease in accrued interest of $26.7 million primarily due to timing of interest payments during the first quarter of 2019, partially offset by increased borrowings;
•
a decrease in accounts payable of $14.2 million primarily due to a decrease in crude oil purchases at Stanchion, a decrease in capital expenditures at Terminals, and a decrease in producer settlements at TMID, partially offset by an increase in capital expenditures at Pony Express; and
•
a decrease in accrued liabilities of $13.3 million primarily due to annual incentive payments made during the quarter.
These working capital decreases were partially offset by:
•
an increase in deferred revenue of $12.1 million primarily from deficiency payments collected by Pony Express and Water Solutions; and
•
a decrease in accounts receivable of $8.8 million primarily due to a decrease in crude oil sales at Stanchion and lower processed volumes at TMID, partially offset by increased accounts receivable at Water Solutions.

40


A material adverse change in operations, available financing under our revolving credit facility, or available financing from the equity or debt capital markets could impact our ability to fund our requirements for liquidity and capital resources in the future.
Cash Flows
The following table and discussion presents a summary of our cash flow for the periods indicated:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Net cash provided by (used in):
 
 
 
Operating activities
$
143,748

 
$
151,600

Investing activities
$
(102,426
)
 
$
(122,913
)
Financing activities
$
(35,876
)
 
$
(27,025
)
Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018
Operating Activities. Cash flows provided by operating activities were $143.7 million and $151.6 million for the three months ended March 31, 2019 and 2018, respectively. The decrease in net cash flows provided by operating activities of $7.9 million was primarily driven by a net decrease in cash flows from changes in working capital driven by a $62.5 million increase in net cash outflows from accounts payable and accrued liabilities, primarily due to higher crude oil purchases at Stanchion and timing of interest payments, partially offset by a $21.0 million increase in net cash inflows from accounts receivable, primarily due to higher crude oil sales at Stanchion. The decrease in cash flows from changes in working capital was partially offset by a $20.9 million increase in distributions received from unconsolidated affiliates, primarily Rockies Express, as a result of our increased membership interest effective February 7, 2018, as well as lower interest expense at Rockies Express due to the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018.
Investing Activities. Cash flows used in investing activities were $102.4 million for the three months ended March 31, 2019, primarily driven by:
•
capital expenditures of $62.8 million, primarily due to spending on construction of the Guernsey and Grasslands Terminals, Pony Express expansion, and a new 70-mile natural gas pipeline located in Colorado ("Cheyenne Connector");
•
cash outflows of $37.0 million for the initial capital contribution and formation of the Powder River Gateway joint venture; and
•
contributions to unconsolidated investments in the amount of $29.8 million, primarily to fund our share of capital projects at Rockies Express and Powder River Gateway.
These cash outflows were partially offset by $27.2 million of distributions received from Rockies Express in excess of cumulative earnings recognized.
Cash flows used in investing activities were $122.9 million for the three months ended March 31, 2018, primarily driven by:
•
cash outflows of $95.0 million for the acquisition of BNN North Dakota;
•
capital expenditures of $58.8 million, primarily due to spending on a 55-mile extension on the Pony Express System, construction of the Buckingham Terminal expansion, the Cheyenne Connector, additional water gathering infrastructure located in North Dakota, and construction of the Grasslands and Natoma Terminals; and
•
cash outflows of $19.5 million for the acquisition of a 38% membership interest in Deeprock North, LLC.
These cash outflows were partially offset by cash inflows of:
•
$50.0 million from the sale of TCG; and
•
$20.8 million of distributions received from Rockies Express in excess of cumulative earnings recognized.
Financing Activities. Cash flows used in financing activities were $35.9 million for the three months ended March 31, 2019, primarily driven by:
•
dividends paid to Class A shareholders of $81.3 million; and

41


•
distributions to noncontrolling interests of $66.6 million, consisting of Tallgrass Equity distributions to the Exchange Right Holders of $64.4 million and distributions to Deeprock Development and West Texas noncontrolling interests of $2.2 million; and
•
tax payments funded by shares tendered by employees to satisfy tax withholding obligations of $13.3 million related to the issuance of Class A shares under LTIP plan.
These cash outflows were partially offset by net borrowings under the revolving credit facility of $125.0 million.
Cash flows used in financing activities were $27.0 million for the three months ended March 31, 2018, primarily driven by:
•
distributions to noncontrolling interests of $89.1 million, which consisted of distributions to TEP unitholders of $51.3 million, Tallgrass Equity distributions to the Exchange Right Holders of $36.4 million, and distributions to Deeprock Development and Pony Express noncontrolling interests of $1.3 million;
•
cash outflows of $50.0 million for the acquisition of an additional 2% membership interest in Pony Express; and
•
dividends paid to Class A shareholders of $21.3 million.
These cash outflows were partially offset by net borrowings of $133.0 million under the revolving credit facility and the Tallgrass Equity credit facility that was terminated in July 2018.
Dividends
Dividends to our Class A shareholders. We distribute 100% of TGE's available cash at the end of each quarter to Class A shareholders of record beginning with the quarter ended June 30, 2015. Available cash at TGE is generally defined in our partnership agreement as all cash and cash equivalents on hand at the date of determination in respect of such quarter less reserves established in the discretion of our general partner for future requirements. For a discussion of factors and trends impacting our business, which in turn impacts our ability to pay dividends to our Class A shareholders, please see "—Factors and Trends Impacting Our Business" in our 2018 Form 10-K.
Our dividend for the three months ended March 31, 2019, in the amount of $0.5300 per Class A share, or $95.0 million in the aggregate, was announced on April 11, 2019 and will be paid on May 15, 2019 to Class A shareholders of record on April 30, 2019.
Capital Requirements
The midstream energy business can be capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of, the following:
•
maintenance capital expenditures, which are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements; and
•
expansion capital expenditures, which are cash expenditures we expect will increase our operating income or operating capacity over the long-term. Expansion capital expenditures include acquisitions or capital improvements (such as additions to or improvements on the capital assets owned, or acquisition or construction of new capital assets).
The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. We expect to incur approximately $290 million for expansion capital projects and approximately $40 million for maintenance capital expenditures in 2019. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:
 
Three Months Ended March 31,
 
2019
 
2018
 
(in thousands)
Maintenance capital expenditures
$
6,988

 
$
3,030

Expansion capital expenditures
54,141

 
57,067

Total capital expenditures incurred
$
61,129

 
$
60,097

Capital expenditures incurred represent capital expenditures paid and accrued during the period. Capital expenditures are presented net of noncontrolling interest, and contributions and reimbursements received. The increase in maintenance capital expenditures to $7.0 million for the three months ended March 31, 2019 from $3.0 million for the three months ended March

42


31, 2018 is primarily driven by increased expenditures in the Natural Gas Transportation and Corporate and Other segments. Maintenance capital expenditures for the three months ended March 31, 2019 in the Corporate and Other segment consisted primarily of spending on information technology assets as a result of our acquisition of these assets from TD in February 2018. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. Expansion capital expenditures were $54.1 million for the three months ended March 31, 2019 compared to $57.1 million for the three months ended March 31, 2018. Expansion capital expenditures for the three months ended March 31, 2019 consisted primarily of spending on the construction of the Guernsey and Grasslands Terminals, Pony Express expansion, and Cheyenne Connector. Expansion capital expenditures of $57.1 million for the three months ended March 31, 2018 consisted primarily of spending on a 55-mile extension on the Pony Express System, construction of the Buckingham Terminal expansion, the Cheyenne Connector, additional water gathering infrastructure located in North Dakota, and construction of the Grasslands Terminal and the Natoma Terminal.
During the three months ended March 31, 2019 and 2018, we invested cash of $29.8 million and $8.0 million, respectively, in unconsolidated affiliates, including Rockies Express, Powder River Gateway, and BNN Colorado, prior to our consolidation of BNN Colorado in December 2018, to fund our share of capital projects.
We intend to pay dividends to our Class A shareholders. Due to our cash distribution policy, we expect that we will distribute available cash to our Class A shareholders on a quarterly basis. We expect to fund future capital expenditures with funds generated from operations, borrowings under our revolving credit facility, and/or the issuance of equity or long-term debt. If these sources are not sufficient, we may reduce our discretionary spending.
Contractual Obligations
There have been no material changes in our contractual obligations as reported in our 2018 Form 10-K.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our 2018 Form 10-K and have not changed.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Historically, we have had a limited amount of direct commodity price exposure related to natural gas used at TMID and crude oil collected as part of our contractual pipeline loss allowance at Pony Express and Terminals. Accordingly, we have historically entered into derivative contracts with third parties for all or a portion of these volumes for the purpose of hedging our commodity price exposures. In addition, Stanchion transacts in crude oil and enters into physical and financial derivative contracts in connection with these, and other, transactions.
The majority of TMID's Adjusted EBITDA comes from volumetric fee or commodity sensitive contracts. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. During the three months ended March 31, 2019, TMID represented 4% of our consolidated Adjusted EBITDA.
We measure the risk of price changes in our crude oil and natural gas derivatives utilizing a sensitivity analysis model. The sensitivity analysis measures the potential income or loss (i.e., the change in fair value of the derivative instruments) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. We enter into derivative contracts that accompany certain of our business activities and, therefore, both the sensitivity analysis model and the change in the market value of our outstanding derivative contracts are offset largely by changes in the value of the underlying physical commodity prices.

43


The following table summarizes our commodity derivatives and the change in fair value that would be expected from a 10% price increase or decrease as of March 31, 2019, assuming a parallel shift in the forward curve through the end of 2019:
 
Fair Value
 
Effect of 10% Price Increase
 
Effect of 10% Price Decrease
 
(in thousands)
Crude oil derivative contract assets(1)
$
1,761

 
$
—

 
$
—

Crude oil derivative contract liabilities(1)
$
(1,129
)
 
$
(1,481
)
 
$
1,481

(1) 
Represents the net forward sale of 246,000 barrels of crude oil in our Gathering, Processing & Terminalling segment which will settle throughout 2019.
Interest Rate Risk
As of March 31, 2019, TEP has issued $2.0 billion of Senior Notes and has a $2.25 billion revolving credit facility with outstanding borrowings of $1.35 billion. Borrowings under TEP's revolving credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. The applicable margin ranges from 0.25% to 1.25% for base rate borrowings and 1.25% to 2.25% for reserve adjusted Eurodollar rate borrowings, based upon TEP's total leverage ratio.
We do not currently hedge the interest rate risk on TEP's borrowings under the revolving credit facility. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the debt by $0.7 million based on our outstanding debt under TEP's revolving credit facility as of March 31, 2019.
Credit Risk
We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through a credit approval process which includes credit analysis, the establishment of credit limits and ongoing monitoring procedures. We may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support.
A substantial majority of our revenue is produced under long-term firm fee contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with a majority of our revenues derived from customers who have BBB- or Baa3 and better credit ratings or are part of corporate families with such credit ratings as of March 31, 2019.
We also have indirect credit risk exposure with respect to our investment in Rockies Express. See Item 1A.—Risk Factors in our 2018 Form 10-K for additional information.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a- 15(e) or Rule 15d- 15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.
Changes in Internal Control over Financial Reporting
There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

44


PART II - OTHER INFORMATION
Item 1. Legal Proceedings
See Note 15 – Legal and Environmental Matters to the condensed consolidated financial statements included in Part I—Item 1.—Financial Statements of this Quarterly Report, which is incorporated herein by reference.
Item 1A. Risk Factors
Item 1A of our 2018 Form 10-K sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended March 31, 2019. There have been no material changes to the risk factors contained in our 2018 Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Recent Sales of Unregistered Securities
None.
Repurchases of Registered Equity Securities by Tallgrass Energy, LP or Affiliated Purchasers
We have not engaged, alone or in concert with an "affiliated purchaser," in any repurchases of our registered securities during the period covered by this report and do not have a repurchase plan or program in place. However, following the closing of the Blackstone Acquisition on March 11, 2019, we are under common control with the Sponsor Entities.
On March 11, 2019, BIP announced that in connection with the closing of the Blackstone Acquisition, the Sponsor Entities had pre-funded Prairie Secondary Acquiror LP, a Delaware limited partnership ("Secondary Acquiror 1"), and Prairie Secondary Acquiror E LP, a Delaware limited partnership ("Secondary Acquiror 2" and, collectively with Secondary Acquiror 1, "Prairie Secondary Acquirors"), each of which are managed by BIP Holdings Manager L.L.C., a Delaware limited liability company, with an aggregate of $400 million for the purpose of making potential future acquisitions of additional Class A shares and that the Prairie Secondary Acquirors intended to enter into a 10b5-1(c) purchase plan (the "Blackstone Plan"). The Blackstone Plan commenced on March 14, 2019. See Schedule 13D filed by BIP and certain of its affiliates with the SEC on March 11, 2019, together with all amendments, for more information on the Blackstone Plan.
The table set forth below reflects the purchases of the Sponsor Entities during the period covered by this report, and subsequent to the closing of the Blackstone Acquisition on March 11, 2019.
Period
 
Total number of Class A shares purchased
 
Average price paid per Class A share
 
Total number of Class A shares purchased as part of publicly announced plans or programs
 
Maximum number (or approximate dollar value) of Class A shares that may yet be purchased under the plans or programs
 
January 1 to January 31, 2019
 
—

 
$
—

 
—

 
$
—

 
February 1 to February 28, 2019
 
—

 
$
—

 
—

 
$
—

 
March 1 to March 31, 2019
 
286,783

(1) 
$
24.0776

 
286,783

(1) 
$
143,089,219

(2) 
Total
 
286,783

 
$
24.0776

 
286,783

 
$
143,089,219

 
(1) 
Includes (i) 116,664 Class A shares purchased by Secondary Acquiror 1 and (ii) 170,119 Class A shares purchased by Secondary Acquiror 2 pursuant to the Blackstone Plan.
(2) 
Represents the approximate dollar value of Class A shares that may yet be purchased under the Blackstone Plan, which provides for purchases up to $150 million of Class A shares, subject to certain volume and pricing thresholds and other conditions set forth therein.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.

45


Item 5. Other Information
On May 3, 2019, our general partner, Tallgrass Management, LLC ("Tallgrass Management") and Gary Brauchle modified the non-compete and non-solicitation provisions of Mr. Brauchle's employment agreement. Mr. Brauchle has agreed not to (i) compete with Tallgrass Management or certain of its affiliates through certain specified competitors or acquirors during the term of his employment and for a period of one year thereafter, or (ii) solicit Tallgrass Management's or any of its affiliates' employees or interfere with certain business relationships during the term of his employment and for a period of one year thereafter.
Item 6. Exhibits
Exhibit No.
 
Description
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.INS*
 
XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
 
 
 
101.SCH*
 
XBRL Taxonomy Extension Schema Document.
 
 
 
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
 
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
 
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase Document.
 
 
 
101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document.
* -
filed herewith

46


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
Tallgrass Energy, LP
 
 
 
(registrant)
 
 
 
By:
Tallgrass Energy GP, LLC, its general partner
 
 
 
 
 
 
 
 
Date:
May 7, 2019
By:
/s/ Gary J. Brauchle
 
 
 
 
 
Name:
Gary J. Brauchle
 
 
 
 
 
Title:
Executive Vice President and Chief Financial Officer
 
 
 
 
 
(Duly Authorized Officer and Principal Financial Officer)


47