2018 ANNUAL REPORT
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Welcome to Tallgrass Energy.
We’re a midstream infrastructure company, transporting crude oil and natural gas
from some of the nation’s most prolific basins in the Rocky Mountains, Upper Midwest
and Appalachian regions with access to major demand markets in the Rockies, the
Midwest, eastern Ohio and points in between. Since our inception, we’ve built a strong
portfolio of integrated transportation, storage, terminal, water management, gathering,
processing and treating assets to support our customers, increase value and deliver
outstanding long-term returns for our investors.
In June 2018, Tallgrass closed on the merger of TEP and TEGP, consolidating from two public companies to one.
BENEFITS OF TALLGRASS COMBINATION
Reduced Complexity &
Increased Alignment
Reduced Cost
of Capital
Increased Equity
Market Depth
» Tallgrass Energy has moved
from 2 public companies to 1
» Full alignment among all
equity owners
» 1099 Dividends
(expect < 10% taxable)
» Elimination of IDRs provided
immediate cost of capital
improvement, enhancing the
ability to grow through large
projects and/or acquisitions
» Increased scale and reduced
complexity could potentially
improve Tallgrass’ credit
ratings, which would reduce
cost of debt (positive watch
from S&P and Investment
Grade rating from Fitch)
» No cash federal taxes expected
at TGE for at least 10 years
» TGE is a partnership taxed as
a C-corp (1099 instead of K1)
» Larger pro forma market
capitalization has increased
liquidity and will likely appeal
to a broader group of investors
» Will make future equity
raises (if any) more efficient
and cost-effective
TALLGRASS SYSTEM MAP
CRUDE OIL
NATURAL GAS
NATURAL GAS
NATURAL GAS LIQUIDS
WATER
TALLGRASS ENERGY, LP 1
L E T T E R T O T G E S H A R E H O L D E R S
2018 Key Accomplishments
M E R G E R
TEP and TEGP merger
ACQ U I S I T I O N S
Completed remaining dropdowns from Tallgrass Development
Expanded oil footprint into the Powder River Basin
Expanded terminal footprint
Expanded water footprint into the Bakken
F I N A N C I N G
Rockies Express Pipeline repaid debt and achieved investment grade credit ratings
THE YEAR IN REVIEW
With 2018 behind us, I want to take this opportunity to thank
the truly outstanding employees at Tallgrass for delivering
another remarkable year. Every day, the talented men and
women at Tallgrass bring their passion and dedication to safely
and reliably operating some of our nation’s most critical energy
infrastructure and executing the day-to-day activities that enable
us to do the things we say we’re going to do. It’s humbling to
lead this team.
In many ways, 2018 marked a brand-new chapter in
Tallgrass’ growth trajectory. We simplified our corporate struc-
ture to position Tallgrass for even greater long-term success. By
closing on the merger of TEP and TEGP—a transaction that was
overwhelmingly supported by TEP unitholders—we realized a
number of important benefits and opened the door to an even
more promising future.
We believe the combination reduced complexity, increased
alignment among equity owners, reduced our cost of capital and
increased equity market depth. Achieving these goals further
strengthens our position as one of the nation’s leading infra-
structure companies.
Shortly after the merger, Tallgrass received an investment
grade credit rating from Fitch. We believe Tallgrass has main-
tained investment grade credit metrics for several years, and it
was gratifying to see that validated by Fitch. Rockies Express
Pipeline, which continues its transformation into the nation’s
northernmost bi-directional natural gas header system, also
received investment grade credit ratings from S&P and Fitch in 2018.
Our successful business development efforts and contin-
ued operational excellence translated into another year of strong
financial results. In 2018, we covered our dividend by more than
1.25 times, generating almost $150 million of cash in excess of
dividends paid. We exceeded the high end of the Adjusted
EBITDA and met the high end of dividend growth guidance we
provided in March 2018. At that time, we said we expected
Adjusted EBITDA to be $755–$835 million1 and dividend growth
to be 38–42 percent for TGE. Pro Forma 2018 Adjusted EBITDA
was $860 million and dividend growth for the year was 41.5 percent.
For Q4 2018, Tallgrass paid a quarterly cash dividend of
$0.52 per Class A share, or $2.08 on an annualized basis.
That marked Tallgrass’ 14th consecutive increase since its
May 2015 IPO. Moving forward, we expect to grow dividends
(1) Excluding deficiency payments.
2
by 6–8 percent on an annualized basis and grow free cash flow
at a rate of 13–15 percent.
Now, let’s take a look at some noteworthy accomplishments
from 2018.
2018 HIGHLIGHTS
Corporate
» Acquired remaining drop-down assets from Tallgrass
Development: 25 percent of REX bringing Tallgrass’ ownership
to 75 percent, and the remaining 2 percent of Pony Express.
» Tallgrass received an investment grade credit rating from Fitch.
» REX received investment grade credit ratings from S&P and Fitch.
Crude Oil Transportation Segment
» Reinforced our presence in the heart of the Powder River
Basin through our Powder River Gateway joint venture, which
owns the Iron Horse Pipeline, the Powder River Express
Pipeline and crude oil terminal in Guernsey, Wyo., enabling
Wyoming production to get onto Pony Express.
» Further strengthened our footprint in the D-J Basin by placing
in service the Platteville Extension, which connects D-J pro-
ducers to Pony Express via our Buckingham terminal and
Northeast Colorado Lateral. We also began working on a sep-
arate extension to allow producers to connect to Pony Express
via the Pawnee terminal.
» Increased Pony Express capacity to about 400,000 barrels per
day through pump enhancements and in January 2019
announced plans for an additional 550,000 barrels per day
through a joint venture with Kinder Morgan that includes con-
verting portions of the Wyoming Intrastate and Cheyenne
Plains natural gas pipeline systems and constructing approxi-
mately 200 miles of new pipeline.
Natural Gas Transportation Segment
» Tallgrass Interstate Gas Transmission and Trailblazer Pipeline
continue to act as a solid foundation for the natural gas trans-
portation segment from both a revenue and market presence
perspective by serving key on-system markets and operating as
the most economic route out of the Rockies, respectively. Both
pipeline systems continue to optimize their capacity and reve-
nue while pursuing opportunities associated with increased
Rockies production.
REX continues its evolution into the nation’s northernmost
header system with the Cheyenne Hub Enhancement (in-service
anticipated Q4 2019), which will allow significant volumes to
enter the pipeline at Cheyenne and flow to demand markets
across the nation. In 2018, REX realized its longest duration of
full utilization of west-to-east transport—emphasizing its
value as an essential Rockies production takeaway.
» REX connected its first two natural gas-fired power plants to the
system, increasing the direct connected load to more than
1.4 Bcf/d, nearly two times the pipeline’s original direct connects.
» The natural gas transportation segment entered the D-J Basin
with its submission of a FERC 7c Application for Tallgrass’
first greenfield natural gas pipeline, Cheyenne Connector,
which has an anticipated in-service of Q4 2019.
Gathering, Processing & Terminalling Segment
» TALLGRASS TERMINALS
Began construction to connect several D-J Basin gathering
companies into the Buckingham and Grasslands terminals,
providing additional volumes for Pony Express.
Began construction on the Guernsey and Grasslands ter-
minals, both of which are expected to be in service in the
first half of 2019.
Placed the Natoma terminal in service in July, giving
Central Kansas Uplift producers direct access to Pony.
Acquired a 51 percent interest in the Pawnee, Colo.,
terminal.
» TMID
Connected an additional 29 wells to our processing facili-
ties and secured commitments for another 33 future wells.
Executed an agreement to increase propane sales by
2 million gallons in 2019.
Renegotiated and/or renewed several contracts resulting
in more favorable terms and executed incremental gathering
and processing contracts for 2019.
» WATER BUSINESS
Closed two Bakken acquisitions and expanded gathering
and disposal infrastructure, establishing Tallgrass’ foot-
print in the basin and making Tallgrass one of the largest
water infrastructure companies in the Bakken.
Completed the installation of more than 75 miles of
gathering pipeline and 72 pump stations to service a
long-term contract in the Bakken.
Executed two long-term take-or-pay water supply con-
tracts with major producers in the D-J Basin and
expanded disposal capacity for existing clients in the
Powder River and Permian basins.
THE NEXT CHAPTER
As we begin the next chapter of our evolution, you can
expect us to move from a high-growth company to one of more
measured growth, deploying capital at appropriate returns
(“ROIC”). We will do this by building on our platform of core mid-
stream assets through organic growth and acquisitions to
expand into new basins and markets and continue to enhance
value to all stakeholders—shareholders, customers, employees
and the communities in which we operate.
As a traditional midstream operator transporting oil and gas
from producing regions to demand markets across the country,
we’re well positioned to take advantage of two emerging trends.
First, we’re seeing a growing number of power generators con-
verting from coal to natural gas. Not only is natural gas clean,
reliable, abundant and affordable, but it also complements the
increasing share of renewable generation by ensuring electric
reliability to support these intermittent resources. Simply put,
natural gas will continue to play a large role in power generation
for years to come. In the first half of 2018, REX accomplished a
milestone by connecting its first two natural gas-fired power
plants, and we expect those connections to grow as power gen-
erators capitalize on REX’s reliability and commitment to opera-
tional excellence.
In 2018, the U.S. achieved two milestones of its own: our
nation became the world’s largest oil producer, surpassing both
Saudi Arabia and Russia, and became a net exporter of crude oil
and petroleum products for the first time in almost 70 years. We
expect both production and exports to continue their growth tra-
jectory for at least the next decade.
As part of Tallgrass’ strategic growth initiatives, in August we
announced two separate projects to support the country’s crude
oil growth. The proposed 700-mile Seahorse Pipeline would trans-
port crude oil from Cushing, Okla., to the Gulf in Louisiana, where
it can be refined into critical products that fuel our economy, such
as gasoline, jet fuel and heating oil, or exported to other countries.
We also announced we have signed a binding agreement with an
unaffiliated third party that has the potential to be an anchor ship-
per and equity partner in that project.
In addition, we announced plans to develop the Plaquemines
Liquids Terminal in Louisiana. PLT is a joint development project
with Drexel Hamilton Infrastructure Partners, LP, in concert with
the Plaquemines Port & Harbor Terminal District (PPHTD), a
Louisiana state agency. The proposed PLT project is a liquids
export terminal facility on the Mississippi River in Plaquemines
Parish, La., with the capacity of up to 20 million barrels of storage
and the ability to fully load and unload Post-Panamax vessels on
its deep-water dock. Tallgrass anticipates building a separate off-
shore pipeline extension that would give PLT the added capability
of loading Very Large Crude Carriers by 3Q 2021.
At the end of January 2019, we announced an agreement
under which Blackstone Infrastructure Partners would acquire a
controlling interest in Tallgrass. We expect that transaction to
close in Q1 2019. We believe Blackstone’s scale, long-term capital
and investment expertise across the energy industry make it an
ideal partner as we continue our growth trajectory. Along with the
projects we announced in 2018, our agreement with Blackstone
advances the strategic plan we’ve charted for the future to solidify
our position as a competitive midstream operator and further
strengthen our ability to add value to our customers, our share-
holders and other stakeholders.
Thanks again, to the outstanding Tallgrass team and to our
customers, suppliers and shareholders for making all this possi-
ble. We look forward to what lies ahead.
Sincerely,
David G. Dehaemers Jr.
President and Chief Executive Officer
TALLGRASS ENERGY, LP 3
S U M M A R Y F I N A N C I A L I N F O R M AT I O N
(in thousands, except coverage)
Year Ended December 31,
2018(1)
Net income
Net income attributable to noncontrolling interestst
Net income attributable to TGE
Add:
Interest expense, net
Depreciation and amortization expense(2)
Distributions from unconsolidated investments
Deficiency payments, net(2)
Non-cash compensation expense
Loss on debt retirement
Distributions received by Tallgrass Development(3)
Deferred income tax expense
Net income attributable to Exchange Right Holders
Less:
Equity in earnings of unconsolidated investments
Gain on disposal of assets(2)
Non-cash gain related to derivative instruments(2)
Tallgrass Energy Adjusted EBITDA
Less:
Cash interest cost
Maintenance capital expenditures, net(2)
Cash Available for Dividends
Less:
Dividends to Class A (TGE)
Dividends to Class B (Exchange Right Holders)
Distribution to TEP public unitholders
Amounts in excess of dividends
Dividend coverage
$ 455,934
(235,167)
220,767
133,319
109,708
387,148
21,830
10,666
2,245
11,475
67,446
229,039
(306,819)
(10,659)
(4,252)
$ 871,913
(127,973)
(20,956)
722,984
(266,389)
(251,715)
(46,391)
$ 158,489
1.28 x
(1) Indicated amounts presented for the year ended Dec. 31, 2018, are on a pro forma basis assuming that the merger transaction with TEP had closed on Jan. 1, 2018.
(2) Net of noncontrolling interest in joint ventures.
(3) Represents distributions received by Tallgrass Development from its (i) 25.01 percent membership interest in REX from January 1, 2018 to February 6, 2018 and its
(ii) 2 percent membership interest in Pony Express from January 1, 2018 to January 31, 2018.
Tallgrass Energy
Adjusted EBITDA*
Tallgrass Energy
Adjusted EBITDA*
(in millions)
(in millions)
TGE Dividends
per Share**
TGE Dividends
per Share**
Gathering, Processing, and Terminalling
Crude Oil Transportation
TIGT & Trailblazer
Rockies Express
Gathering, Processing, and Terminalling
Crude Oil Transportation
TIGT & Trailblazer
Rockies Express
$709
$709
$797
$872
$872
$797
R
G
A
G
A
R
4
8
% C
% C
8
4
$0.5200
$0.5200
$580
$580
$231
$292
$231
$292
$0.3675
$0.3675
$0.2775
$0.2775
$0.1730
$0.1730
$0.1329
$0.1329
2013
2013
2014
2014
2015
2015
2016
2016
2017
2017
2018
2018
Q2 2015
Q2 2015
Q4 2015
Q4 2015
Q4 2016
Q4 2016
Q4 2017
Q4 2017
Q4 2018
Q4 2018
* Represents Adjusted EBITDA across the Tallgrass Energy Family of
Companies. A reconciliation of this non-GAAP metric for 2013–2017 is
available in the presentation dated 10/9/2018 under the Webcasts &
Presentations section at www.tallgrassenergy.com.
** TGE Class A shareholders received a pro-rated dividend
from TGE for the second quarter of 2015 in an amount of
$0.073 for the period from May 12, 2015–June 30, 2015.
For illustrative purposes, the chart above shows what the
dividend would have been if TGE had been public for the
entire quarter.
44
0.6
0.5
0.4
0.3
0.2
0.1
0.0
0.6
0.5
0.4
0.3
0.2
0.1
0.0
1000
1000
800
600
400
200
0
800
600
400
200
0
FORM 10-KENERGY PARTNERSENERGY PARTNERS UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2018
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
Commission file number 001-37365
Tallgrass Energy, LP
(Exact name of registrant as specified in its charter)
Delaware
(State or other Jurisdiction of Incorporation or Organization)
47-3159268
(IRS Employer Identification Number)
4200 W. 115th Street, Suite 350
Leawood, Kansas
(Address of Principal Executive Offices)
66211
(Zip Code)
(913) 928-6060
(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Class A Shares Representing Limited Partner Interests
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes
No
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
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
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
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
Non-accelerated filer
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
The aggregate market value of voting and non-voting common equity held by non-affiliates on June 29, 2018, the last business
day of the Registrant's most recently completed second fiscal quarter (based on the closing sale price of $22.16 of the Registrant's
Class A shares, as reported by the New York Stock Exchange on such date) was approximately $1,264.2 million. On February 8, 2019,
the Registrant had 156,353,761 Class A shares and 123,887,893 Class B shares outstanding.
TALLGRASS ENERGY, LP
TABLE OF CONTENTS
PART I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits, Financial Statement Schedules
Item 16. Form 10-K Summary
SIGNATURES
1
2
21
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57
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58
59
59
61
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95
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193
195
Bakken oil production area: Montana and North Dakota in the United States and Saskatchewan and Manitoba in Canada.
Glossary of Common Industry and Measurement Terms
Barrel (or bbl): forty-two U.S. gallons.
Base Gas (or Cushion Gas): the volume of gas that is intended as permanent inventory in a storage reservoir to maintain
adequate pressure and deliverability rates.
BBtu: one billion British Thermal Units.
Bcf: one billion cubic feet.
British Thermal Units or Btus: the amount of heat energy needed to raise the temperature of one pound of water by one degree
Fahrenheit.
Commodity sensitive contracts or arrangements: contracts or other arrangements, including tariff provisions, that are directly
tied to increases and decreases in the price of commodities such as crude oil, natural gas and NGLs. Examples are Keep Whole
Processing Contracts and Percent of Proceeds Processing Contracts, as well as pipeline loss allowances on our pipelines.
Condensate: an NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon
fractions.
Contract barrels: barrels of crude oil that our customers have contractually agreed to ship in exchange for firm service
assurance of capacity and deliverability to delivery points.
Delivery point: any point at which product in a pipeline is delivered to or for the account of a customer.
Dry gas: a gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have
been removed through processing.
Dth: a dekatherm, which is a unit of energy equal to 10 therms or one million British thermal units.
End-user markets: the ultimate users and consumers of transported energy products.
EPA: the United States Environmental Protection Agency.
FERC: the United States Federal Energy Regulatory Commission.
Firm fee contracts: contracts or other arrangements, including tariff provisions, that generally obligate our customers to pay a
fixed recurring charge to reserve an agreed upon amount of capacity and/or deliverability on our assets, regardless if the
contracted capacity is actually used by the customer. Such contracts are also commonly known as "take-or-pay" contracts.
Firm services: services pursuant to which customers receive firm assurances regarding the availability of capacity and/or
deliverability of natural gas, crude oil or other hydrocarbons or water on our assets up to a contracted amount.
Fractionation: the process by which NGLs are further separated into individual, typically more valuable components including
ethane, propane, butane, isobutane and natural gasoline.
GAAP: accounting principles generally accepted in the United States of America.
GHGs: greenhouse gases.
Header system: networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large
diameter high pressure long-haul transportation pipelines.
Interruptible services: services pursuant to which customers receive limited, or no, assurances regarding the availability of
capacity and deliverability in our assets.
Keep Whole Processing Contracts: natural gas processing contracts in which we are required to replace the Btu content of the
NGLs extracted from inlet wet gas processed with purchased dry natural gas.
Line fill: the volume of oil, in barrels, in the pipeline from the origin to the destination.
Liquefied natural gas or LNG: natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by
ship. The cooling process reduces the volume of natural gas by 600 times.
Local distribution company or LDC: LDCs are involved in the delivery of natural gas to end users within a specific
geographic area.
Long-term: with respect to any contract, a contract with an initial duration greater than one year.
MMBtu: one million British Thermal Units.
Mcf: one thousand cubic feet.
MDth: one thousand dekatherms.
MMcf: one million cubic feet.
Natural gas liquids or NGLs: those hydrocarbons in natural gas that are separated from the natural gas as liquids through the
process of absorption, condensation, or other methods in natural gas processing or cycling plants. Generally, such liquids
consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied
petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and
lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).
Natural Gas Processing: the separation of natural gas into pipeline-quality natural gas and a mixed NGL stream.
Non-contract barrels (or walk-up barrels): barrels of crude oil that our customers ship based solely on availability of capacity
and deliverability with no assurance of future capacity.
No-notice service: those services pursuant to which customers receive the right to transport or store natural gas on assets
outside of the daily nomination cycle without incurring penalties.
NYMEX: New York Mercantile Exchange.
NYSE: New York Stock Exchange.
Park and loan services: those services pursuant to which customers receive the right to store natural gas in (park), or borrow
gas from (loan), our facilities.
Percent of Proceeds Processing Contracts: natural gas processing contracts in which we process our customer's natural gas,
sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. Some percent of
proceeds contracts may also require our customers to pay a monthly reservation fee for processing capacity.
PHMSA: the United States Department of Transportation's Pipeline and Hazardous Materials Safety Administration.
Play: a proven geological formation that contains commercial amounts of hydrocarbons.
Produced water: all water removed from a well as a byproduct of the production of hydrocarbons and water removed from a
well in connection with operations being conducted on the well, including naturally occurring water in the recovery formation,
flow back water recovered during completion and fracturing operations and water entering the recovery formation through
water flooding techniques.
Receipt point: the point where a product is received by or into a gathering system, processing facility, or transportation
pipeline.
Reservoir: a porous and permeable underground formation containing an individual and separate natural accumulation of
producible hydrocarbons (such as crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is
characterized by a single natural pressure system.
Residue gas: the natural gas remaining after being processed or treated.
Shale gas: natural gas produced from organic (black) shale formations.
Tailgate: the point at which processed natural gas and NGLs leave a processing facility for transportation to end-user markets.
TBtu: one trillion British Thermal Units.
Tcf: one trillion cubic feet.
Throughput: the volume of products, such as crude oil, natural gas or water, transported or passing through a pipeline, plant,
terminal or other facility during a particular period.
Uncommitted shippers (or walk-up shippers): customers that have not signed long-term shipper contracts and have rights
under the FERC tariff as to rates and capacity allocation that are different than long-term committed shippers.
Volumetric fee contracts: contracts or other arrangements, including tariff provisions, that generally obligate a customer to pay
fees based upon the extent to which such customer utilizes our assets for midstream energy services. Unlike firm fee contracts,
under volumetric fee contracts our customers are not generally required to pay a charge to reserve an agreed upon amount of
capacity and/or deliverability.
Wellhead: the equipment at the surface of a well that is used to control the well's pressure; also, the point at which the
hydrocarbons and water exit the ground.
Working gas: the volume of gas in the storage reservoir that is in addition to the cushion or base gas. It may or may not be
completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be
used more than once during any season.
Working gas storage capacity: the maximum volume of natural gas that can be cost-effectively injected into a storage facility
and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes base gas and
non-cycling working gas.
X/d: the applicable measurement metric per day. For example, MMcf/d means one million cubic feet per day.
PART I
As used in this Annual 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, TEP 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. References to "Kelso" are to Kelso & Company and its affiliated investment funds and, as the context may
require, other entities under its control, and references to "EMG" are to The Energy & Minerals Group, its affiliated investment
funds and, as the context may require, other entities under its control.
A reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8.
—Financial Statements and Supplementary Data. 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 Annual 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 Annual 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 Annual 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:
•
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•
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 Item 1.—
Business, "Acquisitions and Dispositions;"
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;
our ability to complete internal growth projects on time and on budget;
the price and availability of debt and equity financing;
1
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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 Annual 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.
Item 1. Business
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 55.79% membership interest as of February 8, 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. We intend to continue to utilize the significant experience of our management team to
execute our growth strategy of acquiring midstream assets, increasing utilization of our existing assets and expanding our
systems through construction of additional assets.
Our reportable business segments are:
• Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and 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.
2
Our Assets
The following map shows our primary assets, which consist of natural gas transportation and storage assets; crude oil
transportation assets; natural gas gathering and processing assets; crude oil storage and terminalling assets; and water business
services assets. Each of these assets are described in more detail below. Connected third party refineries are also indicated on
the map below.
Natural Gas Transportation Segment
Rockies Express Pipeline. We own a 75% membership interest in Rockies Express Pipeline LLC ("Rockies Express").
Rockies Express owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system with approximately 1,712
miles of transportation pipelines, including laterals, extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio
(the "Rockies Express Pipeline") and consists of three zones:
• Zone 1 - 328 miles of mainline pipeline from the Meeker Hub in Northwest Colorado, across Southern Wyoming to
the Cheyenne Hub in Weld County, Colorado capable of transporting 2.0 Bcf/d of natural gas from west-to-east;
• Zone 2 - 714 miles of mainline pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri
capable of transporting 1.8 Bcf/d of natural gas from west-to-east; and
• Zone 3 - 643 miles of mainline pipeline from Audrain County, Missouri to Clarington, Ohio, which is bi-directional
and capable of transporting 1.8 Bcf/d of natural gas from west-to-east and 2.6 Bcf/d of natural gas from east-to-west.
For the year ended December 31, 2018, approximately 98% of Rockies Express' revenues were generated under firm fee
contracts.
3
The following tables provide information regarding the Rockies Express Pipeline for the years ended December 31, 2018,
2017, and 2016 and as of December 31, 2018:
Approximate average daily deliveries (Bcf/d) (1) ..................
4.4
4.3
3.2
2018
Year Ended December 31,
2017
2016
Approximate
Capacity
Total Firm
Contracted
Capacity (2)
Approximate %
of Capacity
Subscribed
under Firm
Contracts
Weighted Average
Remaining Firm
Contract Life (3)
West-to-east..........................................
East-to-west..........................................
2.0 Bcf/d
2.6 Bcf/d
1.5 Bcf/d
2.6 Bcf/d
75%
100%
3 years
14 years
(1) Reflects average total daily deliveries for the Rockies Express Pipeline, regardless of flow direction or distance
traveled.
(2) Reflects total capacity reserved under long-term firm fee contracts as of December 31, 2018. West-to-east firm
contracted capacity excludes the 0.2 Bcf/d contracted with Ultra beginning December 1, 2019 as part of the settlement
agreement discussed in Note 19 – Legal and Environmental Matters.
(3) Weighted by contracted capacity as of December 31, 2018. Weighted average remaining firm contract life of west-to-
east contracts excludes the 0.2 Bcf/d contract with Ultra discussed above. After giving effect to the Ultra contract
agreement reached in January 2017, the weighted average life of the west-to-east contract lives would be
approximately 4 years.
TIGT System. We own a 100% membership interest in Tallgrass Interstate Gas Transmission, LLC ("TIGT"), which owns
the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system with
approximately 4,641 miles of varying diameter transportation pipelines serving Wyoming, Colorado, Kansas, Missouri and
Nebraska (the "TIGT System"). The TIGT System includes the Huntsman natural gas storage facility located in Cheyenne
County, Nebraska. The TIGT System primarily provides transportation and storage services to on-system customers such as
local distribution companies and industrial users, including ethanol plants, and irrigation and grain drying operations, which
depend on the TIGT System's interconnections to their facilities to meet their demand for natural gas and a majority of whom
pay FERC-approved recourse rates. For the year ended December 31, 2018, approximately 94% of the TIGT System's
transportation revenue was generated from contracts with on-system customers.
Trailblazer Pipeline. We own a 100% membership interest in Trailblazer Pipeline Company LLC ("Trailblazer"), which
owns the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system with approximately 465 miles of
transportation pipelines, including laterals, that begins along the border of Wyoming and Colorado and extends to Beatrice,
Nebraska (the "Trailblazer Pipeline"). During the year ended December 31, 2018, substantially all of the Trailblazer Pipeline's
operationally available long-haul capacity was contracted under firm transportation contracts.
4
The following tables provide information regarding the TIGT System and Trailblazer Pipeline for the years ended
December 31, 2018, 2017, and 2016 and as of December 31, 2018:
Approximate average daily deliveries (Bcf/d) ......................
1.3
1.2
1.1
2018
Year Ended December 31,
2017
2016
Approximate
Capacity
Total Firm
Contracted
Capacity (1)
Approximate %
of Capacity
Subscribed
under Firm
Contracts
Transportation ......................................
Storage .................................................
2.0 Bcf/d
15.974 Bcf
(3)
1.6 Bcf/d
11 Bcf
80%
71%
Weighted
Average
Remaining Firm
Contract Life (2)
5 years
4 years
(1) Reflects total capacity reserved under long-term firm fee contracts, including backhaul service, as of December 31,
2018.
(2) Weighted by contracted capacity as of December 31, 2018.
(3) The FERC certificated working gas storage capacity.
NatGas. We own a 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas"), which is the operator of the
Rockies Express Pipeline and receives a fee from Rockies Express as compensation for its services.
Crude Oil Transportation Segment
Pony Express System. We own a 100% membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express"),
which provides crude oil transportation to customers in Wyoming, Colorado, Kansas, and the surrounding regions. Pony
Express owns an approximately 834-mile crude oil pipeline commencing in both Guernsey, Wyoming and Weld County,
Colorado and terminating in Cushing, Oklahoma, with delivery points at the McPherson, El Dorado and Ponca City refineries
and in Cushing, Oklahoma (the "Pony Express System"). In the second quarter of 2018, Pony Express placed into service an
extension of the system from an additional origin point in Weld County, Colorado located near Platteville, Colorado
("Platteville Extension"). We believe the Pony Express System is positioned as a low-cost, competitive transportation system
with access to Bakken Shale, DJ Basin and Powder River Basin production.
The table below sets forth certain information regarding the Pony Express System's long-haul capacity as of December 31,
2018 and for the periods indicated:
Approximate
Design Capacity
(bbls/d) (1)
Approximate
Contractible
Capacity Under
Contract (1)(2)
342,000
93%
Weighted Average
Remaining Firm
Contract Life (3)
2 years
Approximate Average Daily Throughput (bbls/d)
Year Ended December 31,
2017
2016
2018
336,314
267,734
285,507
(1) Excludes additional capacity related to the ability to inject drag reducing agent, which is an additive that increases
pipeline flow efficiency, and additional capacity related to expansion projects.
(2) We are required to make no less than 10% of design capacity available for non-contract, or "walk-up", shippers.
Approximately 93% of the remaining design capacity (or available contractible capacity) is committed under contract.
(3) Based on the average annual reservation capacity for each such contract's remaining life.
Powder River Gateway. In January 2019, we completed the expansion of our existing joint venture with Silver Creek
Midstream, LLC ("Silver Creek") and acquired a 51% membership interest in Powder River Gateway, LLC ("Powder River
Gateway"). Powder River Gateway owns the (i) Powder River Express Pipeline ("PRE Pipeline"), a 70-mile crude oil pipeline
with a capacity of 90,000 barrels per day that transports crude oil from the Powder River Basin to Guernsey, Wyoming; (ii) Iron
Horse Pipeline ("Iron Horse Pipeline"), a 80-mile crude oil pipeline expected to be placed into service in the second quarter of
2019 that will have an initial capacity of approximately 100,000 barrels per day and will transport crude oil from the Powder
River Basin to Guernsey, Wyoming; and (iii) crude oil terminal facilities in Guernsey, Wyoming with approximately 370,000
barrels of crude storage currently in-service and over 1 million barrels of storage expected in the second quarter of 2019 once
current construction of additional facilities is completed.
5
Gathering, Processing & Terminalling Segment
Midstream Facilities. We own a 100% membership interest in Tallgrass Midstream, LLC ("TMID"), which owns and
operates a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System"). TMID also owns and
operates natural gas processing plants in Casper and Douglas, Wyoming and a natural gas treating facility at West Frenchie
Draw, Wyoming (collectively with the Douglas Gathering System, the "Midstream Facilities"). The Casper and Douglas plants
currently have combined processing capacity of approximately 190 MMcf/d. The Casper plant also has an NGL fractionator
with a capacity of approximately 3,500 barrels per day. The natural gas processed and treated at these facilities primarily comes
from the Wind River Basin and the Powder River Basin, both in central Wyoming. TMID also owns and operates an NGL
pipeline that transports NGLs from a processing plant in Northeast Colorado to an interconnect with Overland Pass Pipeline,
and an NGL pipeline that originates at our Douglas facility and interconnects with ONEOK's Bakken NGL Pipeline. Each of
our NGL pipelines are supported by 10-year leases for 100% of their respective pipeline capacity, with the lease for the NGL
pipeline in Northeast Colorado having commenced in October 2015, and the lease for the NGL pipeline from our Douglas
facility having commenced on January 1, 2017. During the year ended December 31, 2018, approximately 12%, 51%, and 37%
of TMID's Adjusted EBITDA came from firm fee, volumetric fee, and commodity sensitive contracts, respectively.
The table below sets forth certain information regarding natural gas gathering and processing at the Midstream Facilities as
of December 31, 2018 and for the years ended December 31, 2018, 2017, and 2016:
Approximate
Capacity
(MMcf/d)
Approximate Average Volumes (MMcf/d)
Year Ended December 31,
2018
2017
2016
Gathering ...........................................
Processing..........................................
75
190 (2)
42
122
37 (1)
109
N/A
103
(1) Reflects approximate average gathering volumes subsequent to our acquisition of the Douglas Gathering System on
June 5, 2017.
(2) The West Frenchie Draw natural gas treating facility treats natural gas before it flows into the Casper and Douglas
plants and therefore does not result in additional inlet capacity.
Water Solutions. We provide water business services through our 100% membership interest in BNN Water Solutions, LLC
("Water Solutions"). Water Solutions owns and operates a freshwater delivery and storage system and a produced water
gathering and disposal system in Weld County, Colorado, a produced water disposal facility in Campbell County, Wyoming,
and a produced water gathering and disposal system in North Dakota. Water Solutions is also the sole voting member and owns
a 75.19% membership interest in BNN West Texas, LLC ("West Texas"), which owns a produced water gathering and disposal
system in Reeves and Reagan Counties, Texas that is operated by Water Solutions and owns a 63% membership interest in
BNN Colorado Water, LLC ("BNN Colorado"), which owns a freshwater storage reservoir and supply pipeline in Weld County,
Colorado. These systems are used to support third party exploration, development, and production of oil and natural gas. Water
Solutions also sources treated wastewater from municipalities in Texas and recycles flowback water and other water produced
in association with the production of oil and gas in Colorado. In November 2018, Water Solutions acquired a 100%
membership interest in NGL Water Solutions Bakken, LLC ("NGL Water Solutions Bakken"), which owns a produced water
disposal system in the Bakken basin.
6
The table below sets forth certain information regarding the Water Solutions assets as of December 31, 2018 and for the
years ended December 31, 2018, 2017, and 2016:
Approximate
Current Design
Capacity (bbls/d)
Approximate Average Volumes (bbls/d)
Year Ended December 31,
2017
2016
2018
Freshwater .........................................
Gathering and Disposal .....................
170,863 (1)
271,500 (2)
17,849
98,489
69,139
31,511
13,201
11,307
(1) Represents design capacity at our BNN Western, LLC ("Western") owned facilities and our BNN Colorado freshwater
storage reservoir and supply pipeline. Western also has access to an additional 144,539 bbls/d under supply
arrangements, which are not included in the approximate current design capacity.
(2) Represents the combined daily disposal well injection capacity for the Western produced water gathering and disposal
system acquired in December 2015, the West Texas produced water gathering and disposal system which commenced
operations by Water Solutions in March 2016, the BNN North Dakota, LLC ("BNN North Dakota") produced water
gathering and disposal system acquired in January 2018 and produced water disposal system acquired in November
2018.
Terminals. We provide crude oil storage and terminalling services through our 100% membership interest in Tallgrass
Terminals, LLC ("Terminals"). Terminals owns and operates several assets providing storage capacity and additional injection
points for the Pony Express System, including the crude oil terminal near Sterling, Colorado with approximately 1.3 million
bbls of storage capacity (the "Sterling Terminal"), the crude oil terminal in Weld County, Colorado with four truck unloading
skids capable of receiving up to 42,000 bbls per day (the "Buckingham Terminal"), and the crude oil terminal in the Central
Kansas Uplift that can deliver upward of 20,000 bbls per day into the Pony Express System and commenced operations in the
first quarter of 2018 (the "Natoma Terminal"). Terminals also owns an approximately 60% membership interest in Deeprock
Development, LLC ("Deeprock Development"), which owns crude oil terminals in Cushing, Oklahoma with approximately 4.0
million bbls of storage capacity (the "Cushing Terminal"). In April 2018, Terminals acquired a 51% membership interest in the
Pawnee, Colorado crude oil terminal ("Pawnee Terminal") with approximately 300,000 bbls of storage capacity.
Stanchion. We own a 100% membership interest in Stanchion Energy, LLC ("Stanchion"), which engages in the marketing
of crude oil. Stanchion currently consists of three of our employees who primarily engage in the purchase and sale of crude oil.
Major Customers
For the year ended December 31, 2018, Continental Resources accounted for approximately 10% of our revenues on a
consolidated basis. The loss of this customer could have a material adverse effect on our financial results.
Organizational Structure
Our general partner interest is held by Tallgrass Energy GP, LLC, whose sole member is Tallgrass Energy Holdings, LLC
("Tallgrass Energy Holdings"). A group of persons, which we refer to as the Exchange Right Holders, collectively own all our
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 Class B shares) for Class A
shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged. As of February 8, 2019, the
Exchange Right Holders primarily consist of Kelso, EMG, and Tallgrass KC. Tallgrass KC refers to Tallgrass KC, LLC, which
is an entity primarily owned by certain members of our management. Certain of the Exchange Right Holders collectively own
100% of the voting power of Tallgrass Energy Holdings.
On January 31, 2019, we announced that affiliates of Blackstone Infrastructure Partners (collectively, "BIP") had entered
into a definitive purchase agreement with Kelso, EMG, and Tallgrass KC (collectively, the "Sellers"), pursuant to which BIP
will acquire from the Sellers 100% of the membership interests in our general partner and an approximately 44% economic
interest in us (the "Blackstone Acquisition"). One or more affiliates of GIC Special Investment Pte. Ltd. ("GIC SI"), the
infrastructure and private equity arm of GIC Pte. Ltd., Singapore's sovereign wealth fund, will be a minority investor in the
Blackstone Acquisition. The interests acquired in the Blackstone Acquisition will include all of the economic interests in us
held by EMG and Kelso, and a substantial portion of the interests held by Tallgrass KC.
Subject to customary closing conditions, the Blackstone Acquisition is expected to close within the first quarter of 2019.
Following consummation of the Blackstone Acquisition, (i) the Exchange Right Holders are expected to consist of BIP and
certain members of our management and (ii) BIP will own 100% of the membership interests in our general partner.
7
While we are structured as a limited partnership, (i) we have elected to be treated as a corporation for U.S. federal income
tax purposes, (ii) neither our general partner nor the holders of our Class B shares are entitled to receive any dividends from us,
and (iii) our capital structure does not include incentive distribution rights. Therefore, our dividends will be made exclusively to
our Class A shares. However, holders of our Class A shares and Class B shares vote together as a single class on all matters
presented to our shareholders for their vote or approval, except as otherwise required by applicable law or our partnership
agreement. The term "shares" used in this annual report refers to both the Class A shares and Class B shares representing
limited partner interests in us. References to our "shareholders" refer to the holders of our Class A and Class B shares.
Our operations are conducted directly and indirectly through, and our operating assets are owned by, our subsidiaries. Our
general partner is responsible for conducting our business and managing our operations. However, as of February 8, 2019,
Tallgrass Energy Holdings effectively controls our business and affairs through the exercise of its rights as the sole member of
our general partner, including its right to appoint members to the board of directors of our general partner. Following
consummation of the Blackstone Acquisition, BIP will, subject to certain contractual rights, exercise such control through the
ownership of 100% of the membership interests in our general partner.
In connection with the closing of the initial public offering of our Class A shares (the "TGE IPO"), we, our general partner,
Tallgrass Equity and Tallgrass Energy Holdings entered into an omnibus agreement (the "TGE Omnibus Agreement"), that
addresses the following matters:
• Tallgrass Equity's obligation to reimburse Tallgrass Energy Holdings and its affiliates for expenses incurred (i) on our
behalf, (ii) on behalf of our general partner and (iii) for any other purposes related to our business and activities or
those of our general partner, including our public company expenses and general and administrative expenses; and
• Our use of the name "Tallgrass" and any associated or related marks.
8
The chart below shows the structure of Tallgrass Energy Holdings and its subsidiaries as of February 8, 2019 in a summary
format.
9
Previous Organizational Structure
We were initially formed in 2015 as part of a reorganization involving entities that were previously controlled by Tallgrass
Equity to effect the TGE IPO. As of the closing of the TGE IPO in May 2015, our sole cash-generating asset was a controlling
membership interest in Tallgrass Equity and Tallgrass Equity's sole cash-generating assets consisted of direct and indirect
partnership interests in TEP, which was a publicly traded limited partnership at the time.
Prior to the February 2018 merger discussed below, Tallgrass Energy Holdings was the general partner of Tallgrass
Development. Historically, TEP acquired a number of its assets from Tallgrass Development. In connection with TEP's initial
public offering in May 2013 (the "TEP IPO"), Tallgrass Development contributed to TEP 100% of the membership interests in
TIGT and TMID. Following the TEP IPO, TEP acquired the following additional assets from Tallgrass Development: (1) in
April 2014, a 100% membership interest in Trailblazer, (2) in four separate transactions, the most recent of which was effective
on February 1, 2018, a 100% membership interest in Pony Express, (3) in January 2017, a 100% membership interest in
NatGas and Terminals, (4) in March 2017, a 24.99% membership interest in Rockies Express, and (5) effective February 1,
2018, a 100% membership interest in Tallgrass Operations, LLC, which primarily owned certain administrative assets
consisting primarily of information technology assets. In addition, in May 2016 Tallgrass Development assigned to TEP its
right to purchase a 25% membership interest in Rockies Express from a unit of Sempra U.S. Gas and Power ("Sempra")
pursuant to the purchase agreement originally entered into between Tallgrass Development's wholly-owned subsidiary and
Sempra in March 2016.
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, a wholly-owned subsidiary of
Tallgrass Equity, and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and
an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Equity issued 27,554,785
TGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February
6, 2018, to the limited partners of Tallgrass Development.
On March 26, 2018, we entered into an Agreement and Plan of Merger (the "Merger Agreement") with Tallgrass Equity,
Tallgrass MLP GP, LLC, a Delaware limited liability company and the general partner of TEP ("TEP GP"), and Razor Merger
Sub, LLC, a Delaware limited liability company. The merger transaction contemplated by the Merger Agreement (the "TEP
Merger") was completed effective June 30, 2018, and as a result, 47,693,097 TEP common units held by the public were
converted into the right to receive Class A shares of TGE at an exchange ratio of 2.0 Class A shares for each outstanding TEP
common unit, TEP's incentive distribution rights were cancelled, TEP's common units ceased being publicly traded, and 100%
of TEP's equity interests are now owned by Tallgrass Equity and its subsidiaries.
Acquisitions and Dispositions
The acquisition of midstream assets and businesses that are strategic and complementary to our existing operations
constitutes an integral component of our business strategy and growth objectives. Such assets and businesses include natural
gas transportation and storage; crude oil transportation; and natural gas gathering and processing, crude oil storage and
terminalling services, and water business service assets and other energy assets that have characteristics and provide
opportunities similar to our existing business lines and enable us to leverage our assets, knowledge and skill sets. Below are
summaries of significant acquisitions completed in 2018 and in early 2019, as discussed in Note 3 – Acquisitions and
Dispositions and Note 22 – Subsequent Events.
• Deeprock North. In January 2018, we acquired a 38% membership interest in Deeprock North from Kinder Morgan
Deeprock North Holdco, LLC for cash consideration of $19.5 million. Immediately following the acquisition,
Deeprock North was merged into Deeprock Development. Subsequent to the acquisition and merger, Terminals owns
approximately 60% of the combined entity.
• Pawnee Terminal. In January 2018, we entered into an agreement to acquire a 51% membership interest in the
Pawnee, Colorado crude oil terminal from Zenith Energy Terminals Holdings, LLC for cash consideration of
approximately $31 million. The transaction closed in April 2018.
• BNN North Dakota. In January 2018, we acquired a 100% membership interest in Buckhorn Energy Services, LLC
and Buckhorn SWD Solutions, LLC, which were subsequently merged and renamed BNN North Dakota, LLC, for
cash consideration of approximately $95 million.
• Additional Interest in Pony Express. In February 2018, we acquired the remaining 2% membership interest in Pony
Express, along with administrative assets consisting primarily of information technology assets, from Tallgrass
Development for cash consideration of approximately $60 million, bringing our aggregate membership interest in
Pony Express to 100%.
10
• Additional Membership Interest in Rockies Express and Additional TEP Common Units. In February 2018, Tallgrass
Development merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity, and
as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an
additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Equity
issued 27,554,785 TGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million. Subsequent
to the closing of the transaction, our aggregate membership interest in Rockies Express is 75%.
•
•
Tallgrass Crude Gathering. In February 2018, we entered into an agreement with an affiliate of Silver Creek to sell
our 100% membership interest in Tallgrass Crude Gathering, LLC ("TCG") for approximately $50 million. The sale of
TCG closed in February 2018.
Joint Venture with Silver Creek. In February 2018, we entered into an agreement with Silver Creek to form Iron Horse
Pipeline, LLC ("Iron Horse"), which owns the Iron Horse Pipeline currently under construction. In August 2018, we
entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the contribution by us and
Silver Creek of cash and additional Powder River Basin assets. These additional contributions were completed in
January 2019. The expanded joint venture operates under the name Powder River Gateway, LLC and owns the Iron
Horse Pipeline, the PRE Pipeline, and crude oil terminal facilities in Guernsey, Wyoming. Effective January 1, 2019,
we own a 51% membership interest in Powder River Gateway and operate the joint venture.
• Acquisition of NGL Water Solutions Bakken. In November 2018, we acquired 100% of the membership interests in
NGL Water Solutions Bakken, which was subsequently merged into BNN North Dakota, for cash consideration of
approximately $91 million, subject to working capital adjustments.
Growth Projects
Our extensive asset base and our relationships with customers provide us with opportunities for internal growth through the
construction of additional assets that are complementary to, and expand or extend, our existing asset base. The following
growth projects are currently ongoing and will extend throughout 2019 and beyond:
•
Iron Horse Pipeline. Iron Horse Pipeline, an approximately 80-mile crude oil pipeline currently under construction,
will have an initial capacity of approximately 100,000 barrels per day, expandable up to 200,000 barrels per day, to
transport crude oil from the Powder River Basin to the Guernsey, Wyoming oil hub and is expected to be in-service in
the second quarter of 2019. As discussed above, the Iron Horse Pipeline is part of the Powder River Gateway joint
venture.
• Grasslands Terminal. We are currently constructing the Grasslands Terminal in Platteville, Colorado, which will
connect to the Platteville Extension and enable Pony Express to batch multiple common streams out of Platteville. The
Grasslands Terminal is expected to be in-service by the second quarter of 2019.
• Cheyenne Connector. We are currently constructing the Cheyenne Connector, a new pipeline lateral in Northeast
Colorado that will transport natural gas from the DJ Basin in Weld County to the Rockies Express Pipeline's Cheyenne
Hub, discussed below. Cheyenne Connector will be a large-diameter pipeline approximately 70 miles long, with an
initial capacity of at least 600 mmcf/d and significant capability for expansion. Cheyenne Connector is expected to be
in-service in the fourth quarter of 2019.
• Cheyenne Hub. The Rockies Express Pipeline's Cheyenne Hub is an existing natural gas facility owned and operated
by Rockies Express Pipeline in northern Weld County. At the Cheyenne Hub, the existing Rockies Express Pipeline
intersects and/or connects with numerous other natural gas pipelines. The Cheyenne Hub Enhancement Project
consists of modifications to the Rockies Express Pipeline's Cheyenne Hub to accommodate firm receipt and delivery
interconnectivity among multiple natural gas pipelines with various operating pressures and will provide customers
significant diversity in terms of market access. Cheyenne Hub is expected to be in-service by the fourth quarter of
2019.
• Plaquemines Liquids Terminal. 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"). We made an initial
cash contribution of $30.7 million in exchange for a 100% preferred membership interest and a 80% common
membership interest. DHIF contributed any and all assets and rights related to the project in exchange for a 20%
common membership interest and the right to receive certain special distributions. PLT will construct a liquid export
terminal facility on the Mississippi River on an approximately 600-acre site in Plaquemines Parish, Louisiana. The site
was acquired in November 2018 pursuant to an agreement between PLT and the Plaquemines Port & Harbor Terminal
District. The facility is expected to offer 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. The project is currently expected to be in-service in 2020.
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Competition
All of our businesses face strong competition for acquisitions and development of new projects from both established and
start-up companies. Competition may increase the cost to acquire existing facilities or businesses and may result in fewer
commitments and lower returns for new pipelines or other development projects. Our competitors may have greater financial
resources than we possess or may be willing to accept lower returns or greater risks. Competition differs by region and by the
nature of the business or the project involved.
Additionally, pending and future construction projects, if and when brought online, may also compete with our natural gas
transportation, storage, gathering and processing services, crude oil transportation, storage, gathering and terminalling services,
and water transportation, gathering, recycling and disposal services. Further, natural gas as a fuel, and fuels derived from crude
oil, compete with other forms of energy available to users, including electricity, coal, other liquid fuels and alternative energy.
Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a
reduction in demand for our services. Moreover, several other factors may influence the demand for natural gas and crude oil
which in turn influences the demand for our services, including price changes, the availability of natural gas and crude oil and
other forms of energy, the level of business activity, conservation, legislation and governmental regulations, weather, and the
ability to convert to alternative fuels.
Our principal competitors in our natural gas transportation and storage business include companies that own major natural
gas pipelines, such as Enbridge Inc., Kinder Morgan Inc., Northern Natural Gas Company, Southern Star Central Gas Pipeline,
Inc., Energy Transfer LP, and The Williams Companies Inc., some of whom also have existing storage facilities connected to
their transportation systems that compete with our storage facilities.
Pony Express encounters competition in the crude oil transportation business. A number of pipeline companies compete
with Pony Express to service takeaway volumes in markets that Pony Express currently serves, including pipelines owned and
operated by Sinclair Oil Corporation, Plains All American Pipeline, L.P., Suncor Energy Inc., SemGroup Corporation, Magellan
Midstream Partners, L.P., Anadarko Petroleum Corporation, NGL Energy Partners LP, Energy Transfer LP, and Enbridge
Inc. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and
marketers looking to capitalize on basis differentials between two primary crude oil price benchmarks (West Texas Intermediate
Crude and Brent Crude), and with refineries that source barrels in areas served by Pony Express.
We also experience competition in the natural gas processing business. Our principal competitors for processing business
include other facilities that service its supply areas, such as the other regional processing and treating facilities in the greater
Powder River Basin which include plants owned and operated by Kinder Morgan, Inc., ONEOK, Inc., Western Gas Partners,
LP, The Williams Companies Inc., and Meritage Midstream Services II, LLC. In addition, due to the competitive nature of the
liquids-rich plays in the Wind River Basin and Powder River Basin, it is possible that one of our competitors could build
additional processing facilities that service our supply areas. In addition, Terminals encounters competition in the crude oil
storage and terminalling business from facilities owned by Magellan Midstream Partners, L.P., NGL Energy Partners LP, Plains
All American, L.P., Blueknight Energy Partners, L.P., SemGroup Corporation, and Enbridge Inc. Further, we experience
competition in the water business services. Our principal competitors in such business are other midstream companies, such as
NGL Energy Partners LP, who compete with Water Solutions in areas of concentrated production activity.
Regulatory Environment
Federal Energy Regulatory Commission
We provide open-access interstate transportation service on our natural gas transportation systems pursuant to tariffs
approved by the FERC. As interstate transportation and storage systems, the rates, terms of service and continued operations of
the Rockies Express Pipeline, the TIGT System and the Trailblazer Pipeline are subject to regulation by the FERC, under
among other statutes, the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy
Policy Act of 2005, or EPAct 2005. The rates and terms of service on the Pony Express System, PRE Pipeline, and Iron Horse
Pipeline are subject to regulation by the FERC under the Interstate Commerce Act, or the ICA, and the Energy Policy Act of
1992. We provide interstate transportation service on the Pony Express System and PRE Pipeline pursuant to tariffs on file with
the FERC. Our NGL pipeline that interconnects with Overland Pass Pipeline is leased to a third party who has obtained a
waiver for itself from the FERC from the tariff, filing and reporting requirements of the ICA, and our NGL pipeline that
interconnects with ONEOK's Bakken NGL Pipeline is leased to a third party who is obligated to operate the leased pipeline in
conformance with the ICA as a FERC regulated NGL pipeline.
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The FERC has jurisdiction over, among other things, the construction, ownership and commercial operation of pipelines
and related facilities used in the transportation and storage of natural gas in interstate commerce, including the modification,
extension, enlargement and abandonment of such facilities. The FERC also has jurisdiction over the rates, charges and terms
and conditions of service for the transportation and storage of natural gas in interstate commerce. The FERC's authority over
interstate crude oil pipelines is less broad than its authority over interstate natural gas pipelines and includes rates, rules and
regulations for service, the form of tariffs governing service, the maintenance of accounts and records, and depreciation and
amortization policies.
The rates and terms for access to interstate natural gas pipeline transportation services are subject to extensive regulation
and the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of these
initiatives, interstate natural gas transportation and marketing entities have been substantially restructured to remove barriers
and practices that historically limited non-pipeline natural gas sellers, including producers, from competing effectively with
interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The FERC's
regulations require, among other things, that interstate natural gas pipelines provide firm and interruptible transportation service
on an open access basis, provide internet access to current information about available pipeline capacity and other relevant
information, and permit pipeline shippers under certain circumstances to release contracted transportation and storage capacity
to other shippers, thereby creating secondary markets for such services. The result of the FERC's initiatives has been to
eliminate interstate natural gas pipelines' historical role of providing bundled sales service of natural gas and to require
pipelines to offer unbundled storage and transportation services on a not unduly discriminatory or preferential basis. The rates
for such transportation and storage services are subject to the FERC's ratemaking authority, and the FERC exercises its
authority by applying cost-of-service principles to limit the maximum and minimum levels of tariff-based recourse rates;
however, it also allows for discounted or negotiated rates as an alternative to cost-based rates and may grant market-based rates
in certain circumstances. The FERC regulations also restrict interstate natural gas pipelines from sharing certain transportation
or customer information with marketing affiliates and require that the transmission function personnel of interstate natural gas
pipelines operate independently of the marketing function personnel of the pipeline or its affiliates.
FERC; Market Behavior Rules; Posting and Reporting Requirement; Other Enforcement Authorities
EPAct 2005, among other matters, amended the NGA to add an anti-manipulation provision that makes it unlawful for any
entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and,
furthermore, provides the FERC with additional civil penalty authority. The FERC adopted rules implementing the anti-
manipulation provision of EPAct 2005 that make it unlawful for any entity, directly or indirectly in connection with the
purchase or sale of natural gas transportation services subject to the jurisdiction of the FERC to (1) use or employ any device,
scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary
to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any
person.
These anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and
storage companies that provide interstate services as well as otherwise non-jurisdictional entities to the extent the activities are
conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. EPAct 2005 also amended
the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes of more than $1
million per day per violation. In connection with this enhanced civil penalty authority, the FERC issued policy statements on
enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers,
including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with
all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines,
including the disgorgement of unjust profits.
EPAct 2005 also amended the NGA to authorize the FERC to facilitate price transparency in markets for the sale or
transportation of physical natural gas in interstate commerce. The FERC has taken steps to enhance its market oversight and
monitoring of the natural gas industry by adopting rules that (1) require buyers and sellers of annual quantities of 2,200,000
MMBtu or more of gas in any year to report by May on the aggregate volumes of natural gas they purchased or sold at
wholesale in the prior calendar year; (2) report whether they provide prices to any index publishers and, if so, whether their
reporting complies with the FERC's policy statement on price reporting; and (3) increase the internet posting obligations of
interstate pipelines.
In addition, the Commodity Futures Trading Commission, or CFTC, is directed under the Commodities Exchange Act, or
CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to
the Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, in July 2010 and other authority, the
CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and
futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of more than $1 million or
triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.
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Further, the Federal Trade Commission, or FTC, has the authority under the Federal Trade Commission Act, or FTCA, and
the Energy Independence and Security Act of 2007, or EISA, to regulate wholesale petroleum markets. The FTC has adopted
anti-market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain
petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions
for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and
request that a court impose fines of more than $1 million per violation per day.
The FERC also has the authority under the ICA to regulate the interstate transportation of petroleum on common carrier
pipelines, including whether a pipeline's rates or rules and regulations for service are "just and reasonable." Among other
enforcement powers, the FERC can order prospective rate changes, suspend the effectiveness of rates, and order reparations for
damages. In addition, the ICA imposes potential criminal liability for certain violations of the statute.
Certain Outstanding Notices Issued by the FERC
FERC Advanced Notice of Proposed Rulemaking, Revisions to Indexing Policies and Page 700 of FERC Form No. 6,
Docket No. RM17-1-000
On November 2, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking, under which the FERC is
proposing changes to its regulation of oil pipelines in two different areas: (1) its policies regarding the permissible scope of rate
increases based on its annual issuance of changes to the generic oil pipeline index, based on specific pipelines' earnings or their
specific changes to costs; and (2) the reporting requirements for page 700 of FERC Form No. 6, Annual Report of Oil Pipeline
Companies. The FERC's Advanced Notice of Proposed Rulemaking does not propose specific regulations, and may be
followed by a Notice of Proposed Rulemaking proposing specific regulations or a Policy Statement announcing new or
changed policies. Comments have been filed with the FERC by interested parties and the proceeding is pending before the
FERC.
Notice of Inquiry on FERC's Pipeline Certificate Policy Statement, PL18-1-000
On April 19, 2018, the FERC issued a Notice of Inquiry regarding whether it should revise its current policy statement on
its review and authorization of natural gas pipelines under Section 7 of the Natural Gas Act. The current policy statement,
"Certification of New Interstate Natural Gas Pipeline Facilities - Statement of Policy," was issued in 1999. The Notice of
Inquiry requested comments in four general areas: (1) the reliance on precedent agreements to demonstrate need for a proposed
project; (2) the potential exercise of eminent domain and landowner interests; (3) the FERC's evaluation of alternatives and
environmental effects under the National Environmental Policy Act and the Natural Gas Act; and (4) the efficiency and
effectiveness of the FERC's certificate processes. Comments have been filed by interested parties and the proceeding is pending
before the FERC.
Examples of Our Dockets at the FERC
Trailblazer 2018 General Rate Case Filing
On June 29, 2018, Trailblazer filed a general rate case with the FERC proposing, among other things, an increase in rates
on Trailblazer's Existing System Firm Transportation Service and a decrease in rates for Expansion System Firm Transportation
Service and interruptible services. On July 31, 2018, the FERC issued an Order: (1) approving the as-filed rate decreases for
Expansion System Firm Transportation Service and interruptible services, effective August 1, 2018; (2) accepting and
suspending the rest of the rate case filing (including the proposed rate increases) to become effective January 1, 2019 subject to
refund, and establishing hearing and settlement procedures; and (3) establishing a paper hearing to examine the extent to which
Trailblazer is entitled to an Income Tax Allowance. Parties have submitted briefs on the Income Tax Allowance issue and the
paper hearing remains pending before the FERC. The remaining issues are currently subject to settlement judge procedures.
Cheyenne Hub Enhancement Project
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.
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Cheyenne Connector Pipeline Project
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.
For additional information regarding these dockets and certain other regulatory filings with the FERC, see Note 18 –
Regulatory Matters.
Pipeline and Hazardous Materials Safety Administration
We are also subject to safety regulations imposed by PHMSA, including those regulations requiring us to develop and
maintain integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional
measures to protect pipeline segments located in areas, which are referred to as high consequence areas, or HCAs, where a leak
or rupture could potentially do the most harm.
In January 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or The Pipeline Safety Act of
2011, which amended the Pipeline Safety Improvement Act of 2002, increased penalties for violations of safety laws and rules,
among other matters, and may result in the imposition of more stringent regulations in the next few years. This legislation also
requires the U.S. Department of Transportation to study and report to Congress on other areas of pipeline safety, including
expanding the reach of the integrity management regulations beyond high consequence areas, but restricts the U.S. Department
of Transportation from promulgating expanded integrity management rules during the review period and for a period following
submission of its report to Congress unless the rulemaking is needed to address a present condition that poses a risk to public
safety, property or the environment. PHMSA issued a final rule effective October 25, 2013 that implemented aspects of the new
legislation. Among other things, the final rule increases the maximum civil penalties for violations of pipeline safety statutes or
regulations, broadens PHMSA's authority to submit information requests, and provides additional detail regarding PHMSA's
corrective action authority. In addition, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, or
PIPES Act, reauthorized PHMSA's oil and gas pipeline programs through 2019 and gave PHMSA power to issue emergency
orders upon finding an imminent hazard, required PHMSA to issue safety standards for underground natural gas storage
facilities, set deadlines for conducting post-inspection briefings and making findings, required liquid pipeline operators to
undertake new safety measures, and required certain updates to the PHMSA website.
Additionally, PHMSA is also currently considering changes to its regulations. On December 14, 2016, PHMSA issued an
interim final rule, or IFR, that addresses safety issues related to downhole facilities, including well integrity, well bore tubing, and
casing at underground natural gas storage facilities. The IFR incorporates by reference two of the American Petroleum Institute's
Recommended Practice standards and mandates certain reporting requirements for operators of underground natural gas storage
facilities. Operators of natural gas storage facilities were given one year from January 18, 2017, the effective date of the IFR, to
implement this first set of PHMSA regulations governing underground storage fields. PHMSA determined, however, that it will
not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatory
provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final
rule. On January 13, 2017, PHMSA finalized new hazardous liquid pipeline safety regulations. Among other things, the final rule
would have required additional event-driven and periodic inspections, required the use of leak detection systems on all hazardous
liquid pipelines, modified repair criteria, and required certain pipelines to eventually accommodate in-line inspection tools.
However, on January 24, 2017, this rule was withdrawn for further review by the Trump Administration and was never published
in the Federal Register.
Also, on April 8, 2016, PHMSA published a notice of proposed rule-making, or NPRM, addressing natural gas transmission
and gathering lines. The proposed rule would include changes to existing integrity management requirements and would expand
assessment and repair requirements to pipelines in areas with medium population densities (referred to as Moderate Consequence
Areas or MCAs), along with other changes. This NPRM builds on an Advisory Bulletin PHMSA issued in May 2012, which
advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design,
construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of
that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying
maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of
such pressures, could significantly increase our costs. TIGT continues to investigate and, when necessary, report to PHMSA the
miles of pipeline for which it has incomplete records for maximum allowable operating pressure, or MAOP. We are currently
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undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally,
failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which
would reduce available capacity on our pipelines. At the state level, several states have passed legislation or promulgated rulemaking
dealing with pipeline safety. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity
regulation, and actual future expenditures may be different from the amounts we currently anticipate. Regulations, changes to
regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of
our pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities.
Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures.
Pipeline Integrity Issues
The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of
in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe
determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs can have a
significant impact on the costs to perform integrity testing and repairs. In July 2018, PHMSA issued an advance notice of
proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and
particularly the actions operators must take when class locations change due to population growth or building construction near
the pipeline. We will continue pipeline integrity testing programs to assess and maintain the integrity of its existing and future
pipelines as required by the U.S. Department of Transportation regulations. The results of these tests could cause us to incur
significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the
continued safe and reliable operation of its pipelines, which expenditures could be material.
From time to time, our pipelines may experience integrity issues. These integrity issues may cause explosions, fire, damage
to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for
damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines.
Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/
or criminal fines and penalties and we may also be subject to private civil liability for such matters.
Trailblazer
Starting in 2014 Trailblazer's operating capacity was decreased as a result of smart tool surveys that identified
approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred
approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To
date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing
subscription levels or had a material adverse financial impact on us. However, Trailblazer continued performing remediation to
increase and maximize its operating capacity over the long-term and spent approximately $21 million during 2018 for this pipe
replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating
capacity. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a
general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
In connection with TEP's acquisition of Trailblazer in April 2014, TD agreed to indemnify TEP for certain out of pocket
costs related to repairing or remediating the Trailblazer Pipeline. The contractual indemnity was capped at $20 million and
subject to an annual $1.5 million deductible. TEP has received the entirety of the $20 million from TD pursuant to the
contractual indemnity as of December 31, 2017.
Pony Express
In connection with certain crack tool runs on the Pony Express System completed in 2015, 2016 and 2017, Pony Express
completed approximately $18 million of remediation for anomalies identified on the Pony Express System associated with
portions of the pipeline that were converted from natural gas to crude oil service. Remediation work was substantially complete
as of March 1, 2018.
Environmental, Health and Safety Matters
General
The ownership, operation and expansion of our assets are subject to federal, state and local laws, regulations and potential
liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health.
These laws and regulations can restrict or impact our business activities in many ways, such as restricting the way we can
handle or dispose of our wastes, requiring remedial action to mitigate pollution conditions that may be caused by our operations
or that are attributable to former operations, regulating future construction activities to mitigate harm to threatened or
endangered species, wetlands and migratory birds, and requiring the installation and operation of pollution control or seismic
monitoring equipment. The cost of complying with these laws and regulations can be significant, and we expect to incur
significant compliance costs in the future as new, more stringent requirements are adopted and implemented.
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Failure to comply with existing environmental laws, regulations, permits, approvals or authorizations or to meet the
requirements of new environmental laws, regulations or permits, approvals and authorizations may trigger a variety of
administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and/or temporary or
permanent interruptions in our operations that could influence our business, financial position, results of operations and
prospects. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites
where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. The costs and liabilities
resulting from a failure to comply with environmental laws and regulations could negatively affect our business, financial
position, results of operations and prospects. Moreover, it is not uncommon for neighboring landowners and other third parties
to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or
other waste products into the environment.
In addition, we have agreed to a number of conditions in our environmental permits, approvals and authorizations that
require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve,
among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and
private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas
where we currently operate, and would operate in the future, and we are unable to predict the effect that any such measures
would have on our business, financial position, results of operations or prospects.
We are also subject to the requirements of the Occupational Health and Safety Act, or OSHA, the Pipeline Safety Act and
other comparable federal and state statutes. In general, we expect that it may have to increase expenditures in the future to
comply with higher industry and regulatory safety standards. Such increases in expenditures could become significant over
time.
Historically, our total expenditures for environmental control measures and for remediation have not been significant in
relation to our consolidated financial position or results of operations. It is reasonably likely, however, that the long-term trend
in environmental legislation and regulations will eventually move towards more restrictive standards. Compliance with these
standards is expected to increase the cost of conducting business.
For additional information regarding Environmental, Health and Safety Matters, please read Item 1A.—Risk Factors.
Air Emissions
Our operations are subject to the federal Clean Air Act, or CAA, and comparable state laws and regulations. These laws
and regulations regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and
compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require
that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air
emissions or result in the increase of existing air emissions (including GHG emissions, as discussed below), obtain and strictly
comply with air permits containing various emissions and operational limitations and/or install emission control equipment. We
may be required to incur certain capital expenditures in the future for air pollution control equipment and technology in
connection with obtaining and maintaining operating permits and approvals for air emissions.
The EPA finalized a rule, effective August 2, 2016, under the New Source Performance Standard Program, or NSPS
Program, to limit methane emissions from the oil and gas and transmission sectors. The rule sets additional emissions limits for
volatile organic compounds and regulates methane emissions for new and modified sources in the oil and gas industry. In
October 2018, the EPA proposed a rule to reconsider and amend various requirements of the NSPS standard. However, the
NSPS rule currently remains in effect. The EPA also finalized a rule effective August 2, 2016 regarding the alternative criteria
for aggregating multiple small surface sites into a single source for air-quality permitting purposes. EPA draft guidance issued
in September 2018 clarified that this rule pertains to the oil and gas industry. Also, effective January 17, 2017, the Bureau of
Land Management of the U.S. Department of the Interior, or BLM, imposed new rules to reduce venting, flaring and leaks
during oil and natural gas production activities on onshore federal and Indian lands. This rule was suspended, stayed, and
reinstated before the BLM issued a final rule in September 2018 that rescinds and revises many of the requirements of the 2017
rule. The revision rule is being challenged in the U.S. District Court for the Northern District of California but currently
remains in effect.
Developments in GHG Regulations
Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and products
produced from crude oil, are examples of GHGs. The EPA has determined that the emission of GHGs presents an
endangerment to public health and the environment because emissions of such gases contribute to the warming of the Earth's
atmosphere and other climatic changes. Various laws and regulations exist or are under development that seek to regulate the
emission of such GHGs, including the EPA programs to control GHG emissions and state actions to develop statewide or
regional programs. In recent years, the U.S. Congress has considered, but not adopted, legislation to reduce emissions of
GHGs. There have also been efforts to regulate GHGs at an international level, most recently in the Paris Agreement, which
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was signed on April 22, 2016 by 175 countries, including the United States. The Paris Agreement will require countries to
review and "represent a progression" in their intended, nationally-determined contributions, which set GHG emission reduction
goals every five years beginning in 2020. However, in August of 2017, the United States informed the United Nations of its
intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is
November 2020.
Because our operations, including our compressor stations, emit various types of GHGs, primarily methane and carbon
dioxide, such new legislation or regulation could increase our costs related to operating and maintaining our facilities.
Depending on the particular new law, regulation or program adopted, we could be required to incur capital expenditures for
installing new emission controls on our facilities, acquire permits or other authorizations for emissions of GHGs from our
facilities, acquire and surrender allowances for our GHG emissions, pay taxes related to our GHG emissions and administer
and manage a GHG emissions program. We are not able at this time to estimate such increased costs; however, as is the case
with similarly situated entities in the industry, they could be significant to us. While we may be able to include some or all of
such increased costs in the rates charged by our pipelines, such recovery of costs in all cases is uncertain and may depend on
events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final
legislation or other regulations. Similarly, while we may be able to recover some or all of such increased costs in the rates
charged by our processing facilities, such recovery of costs is uncertain and may depend on the terms of our contracts with our
customers. In addition, new laws, regulations, or programs adopted could also impact our customers' operations or the overall
demand for fossil fuels. Any of the foregoing could have an adverse effect on our business, financial position, results of
operations and prospects.
Regulation of Hydraulic Fracturing
A sizeable portion of the hydrocarbons we transport, process, and store comes from hydraulically fractured wells.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight
formations. The process typically involves the injection of water, sand and a small percentage of chemicals under pressure into
the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically
the state's oil and gas commission; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing
activities involving diesel under the federal Safe Drinking Water Act, or SDWA, and has released draft permitting guidance for
hydraulic fracturing activities that use diesel in fracturing fluids in those states where the EPA is the permitting authority. A
number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to
review, a variety of environmental issues associated with hydraulic fracturing. In addition, some states, including those in
which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent
disclosure and/or well construction requirements on hydraulic fracturing operations. Other states, including states in which we
operate, have restrictions on produced water storage from hydraulic fracturing operations and the operation of produced water
disposal wells. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and
manner of drilling activities in general or hydraulic fracturing activities in particular, and in some cases, may seek to ban
hydraulic fracturing entirely. Some state and local authorities have considered or imposed new laws and rules related to
hydraulic fracturing, including temporary or permanent bans, additional permit requirements, operational restrictions and
chemical disclosure obligations on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more
difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on
hydraulic fracturing could also reduce the volume of crude oil, natural gas, and NGLs that our customers produce, and could
thereby adversely affect our revenues and results of operations.
Hazardous Substances and Waste
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous
substances, nonhazardous and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation,
storage, treatment, transportation and disposal of nonhazardous and hazardous waste and may impose strict joint and several
liability for the investigation and remediation of affected areas where hazardous substances may have been released or
disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and
comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of
persons that contributed to the release or threatened release of a hazardous substance into the environment. We may handle
hazardous substances within the meaning of CERCLA, or analogous state laws, in the course of our ordinary operations and, as
a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these
hazardous substances have been released or threatened to be released into the environment.
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We also generate wastes that are subject to the Resource Conservation and Recovery Act, or RCRA, and comparable state
laws. RCRA regulates both nonhazardous and hazardous solid wastes, but it imposes strict requirements on the generation,
storage, treatment, transportation and disposal of hazardous wastes. It is possible that wastes resulting from our operations that
are currently treated as non-hazardous wastes could be designated as "hazardous wastes" in the future, subjecting us to more
rigorous and costly management and disposal requirements. It is also possible that federal or state regulatory agencies will
adopt stricter management or disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in
the laws and regulations could have a material adverse effect on our business, financial position, results of operations and
prospects or otherwise impose limits or restrictions on our operations or those of our customers.
In some cases, we own or lease properties where hydrocarbons are being or have been handled for many years.
Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or
under the locations where these hydrocarbons and wastes have been transported for treatment or disposal. We could also have
liability for releases or disposal on properties owned or leased by others. These properties and the wastes disposed thereon may
be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate
previously disposed wastes (including wastes disposed of or released by prior owners and operators), to clean up contaminated
property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.
Our produced water disposal operations require it to comply with the Class II well standards under the federal SDWA. The
SDWA imposes requirements on owners and operators of Class II wells through the EPA's Underground Injection Control
program, including construction, operating, monitoring and testing, reporting and closure requirements. Our disposal wells are
also subject to comparable state laws and regulations. Compliance with current and future laws and regulations regarding our
produced water disposal wells may impose substantial costs and restrictions on our produced water disposal operations, as well
as adversely affect demand for our produced water disposal services. State and federal regulatory agencies recently have
focused on a possible connection between the operation of produced water injection wells used for oil and gas waste disposal
and seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In some instances,
operators of produced water injection wells in the vicinity of minor seismic events have been ordered to reduce produced water
injection volumes or suspend operations. Regulatory agencies are continuing to study possible linkage between produced water
injection activity and induced seismicity. These developments could result in additional regulation of produced water injection
wells, such regulations could impose additional costs and restrictions on our produced water disposal operations.
Federal and State Waters
The Federal Water Pollution Control Act, also known as the Clean Water Act, or the CWA, and comparable state laws
impose restrictions and strict controls regarding the discharge of pollutants, including petroleum products, into state waters or
waters of the United States. In 2015, the EPA and the U.S. Army Corps of Engineers adopted a rule to clarify the meaning of
the term "waters of the United States" with respect to federal jurisdiction. Many interested parties believe that the rule expands
federal jurisdiction under the CWA. This rule was initially challenged in federal courts at both the appellate and district court
levels. It was stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit but, based on a January 2018 U.S. Supreme
Court decision determining that only the district courts have jurisdiction to hear the challenges, the Sixth Circuit stay was
withdrawn. Some federal district courts have enjoined the rule, but the rule is currently effective in over 20 states. In February
2018, the agencies also published a final rule adding a February 6, 2020 applicability date to the 2015 rule, but this rule was
enjoined nationwide in August 2018. In December 2018, the EPA and the U.S. Army Corp of Engineers released a proposed
rule to redefine the extent of CWA jurisdiction. If finalized, this rule would replace the 2015 rule defining "waters of the United
States" and the scope of federal jurisdiction.
Regulations promulgated pursuant to the CWA and analogous state laws require that entities that discharge into federal
and/or state waters obtain National Pollutant Discharge Elimination System, or NPDES, permits and/or state permits
authorizing these discharges. The CWA and analogous state laws assess administrative, civil and criminal penalties for
discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such
waters. In addition, the CWA and analogous state laws require that individual permits or coverage under general permits be
obtained by covered facilities for discharges of storm water runoff. Some states also maintain groundwater protection programs
that require permits for discharges or operations that may impact groundwater. We believe that we are in substantial compliance
with the CWA permitting requirements as well as the conditions imposed thereunder and that continued compliance with such
existing permit conditions will not have a material effect on our results of operations.
The primary federal law related to oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill
provisions of the CWA and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil
spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. Spill prevention,
control and countermeasure requirements of federal laws and analogous state laws require us to maintain spill prevention
control and countermeasure plans. These laws also require appropriate containment berms and similar structures to help prevent
the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. Regulations promulgated
pursuant to OPA further require certain facilities to maintain oil spill prevention and oil spill contingency plans. A liable
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"responsible party" includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that
poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a
discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil
removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are
limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.
Endangered Species
The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats.
While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we
believe that we are in substantial compliance with the ESA. However, the designation of previously unlisted endangered or
threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future
development in the affected areas.
National Environmental Policy Act
The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection,
maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies.
A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as
a result, many activities requiring FERC or other federal approval must undergo a NEPA review. A NEPA review can create
delays and increased costs that could materially adversely affect our operations.
Employee Safety
We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and
safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about
hazardous materials used or produced in operations and that this information be provided to employees, state and local
government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements,
including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated
substances.
Seasonality
Weather generally impacts natural gas demand for power generation, heating purposes and other natural gas usages, which
in turn influences the value of transportation and storage. Price volatility also affects gas prices, which in turn influences
drilling and production. Peak demand for natural gas typically occurs during the winter months, caused by heating demand.
Nevertheless, because a high percentage of our natural gas transportation and storage and crude oil transportation revenues are
derived from firm capacity reservation fees under long-term firm fee contracts, our revenues attributable to those segments are
not generally seasonal in nature. We experience some seasonality in our processing segment, as volumes at our processing
facilities are slightly higher in the summer months. We also experience some seasonality in our maintenance, repair, overhaul,
integrity, and other projects, as warm weather months are most conducive to efficient execution of these activities.
Title to Properties and Rights-of-Way
Our real property generally falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest
derives from leases, easements, rights-of-way, permits, surface use agreements, or licenses from landowners or governmental
authorities, permitting the use of such land for our operations. We believe that we have satisfactory title to the material portions
of the land on which our pipelines and facilities are owned by us in fee title. The remainder of the land on which our pipelines
and facilities are located are held by us pursuant primarily to leases, easements, rights-of-way, permits, surface use agreements
or licenses between us, as grantee, and a third party, as grantor. We believe that we have satisfactory rights to all of the material
parcels in which our interest derives from leases, easements, rights-of-way, permits, surface use agreements, and licenses.
Insurance
We generally share insurance coverage with Tallgrass Energy Holdings pursuant to the terms of the TGE Omnibus
Agreement and an Omnibus Agreement dated May 17, 2013 entered into among TEP, TEP GP, Tallgrass Development and the
general partner of Tallgrass Development (the "TEP Omnibus Agreement"). This shared insurance program includes general
and excess liability insurance, auto liability insurance, workers' compensation insurance, pollution, business interruption and
property and director and officer liability insurance. All insurance coverage is in amounts which management believes are
reasonable and appropriate.
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Employees
We are managed and operated by the board of directors and executive officers of our general partner. As of December 31,
2018, we employed approximately 750 full-time employees through Tallgrass Management, LLC ("Tallgrass Management").
Prior to July 1, 2018, Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings. Effective July 1,
2018, Tallgrass Management was contributed to Tallgrass Equity in connection with the TEP Merger. As a result, the costs of
employer and director compensation and benefits are now incurred directly by Tallgrass Equity.
Under the terms of the TGE Omnibus Agreement, the TEP Omnibus Agreement and our partnership agreement, we
reimburse Tallgrass Energy Holdings (and its affiliates) and our general partner, respectively, for the provision of various
general and administrative services for our benefit and for direct expenses incurred by Tallgrass Energy Holdings (and its
affiliates) or our general partner on our behalf, including services performed and expenses incurred by our executive
management personnel in connection with our business and affairs.
Available Information
We make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge
through our website, www.tallgrassenergy.com, as soon as reasonably practicable after they are filed with the SEC. The filings
are also available through the SEC's website, www.sec.gov. Our press releases and recent presentations are also available on
our website.
Item 1A. Risk Factors
Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the
business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses.
If any of the following risks were to occur, our business, financial condition or results of operations could be materially
adversely affected. In that case, we might not be able to pay quarterly cash dividends on our Class A shares at the current
dividend level, or pay any dividend at all, and the trading price of our Class A shares could decline.
Risks Related to Our Business
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and
expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the quarterly cash
dividend at the current dividend level, or at all, to holders of our Class A shares.
We may not have sufficient available cash each quarter to enable us to pay the quarterly cash dividend at the current
dividend level or at all. The amount of cash we have available for dividends on our Class A shares principally depends upon the
amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
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the level of firm services we provide to customers pursuant to firm fee contracts and the volume of customer products
we transport, store, process, gather, treat and dispose using our assets;
our ability to renew or replace expiring long-term firm fee contracts with other long-term firm fee contracts;
the creditworthiness of our customers, particularly customers who are subject to firm fee contracts;
our ability to source, complete and integrate acquisitions;
the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of natural gas,
NGLs, crude oil and other hydrocarbons;
the actual and anticipated future prices, and the volatility thereof, of natural gas, crude oil and other commodities;
changes in the fees we charge for our services, including firm services and interruptible services;
our ability to identify, develop, and complete internal growth projects or expansion capital expenditures on favorable
terms to improve optimization of our current assets;
regional, domestic and foreign supply and perceptions of supply of natural gas, crude oil and other hydrocarbons;
the level of demand and perceptions of demand in end-user markets we directly or indirectly serve;
applicable laws and regulations affecting our and our customers' business, including the market for natural gas, crude
oil, other hydrocarbons and water, the rates we can charge on our assets, how we contract for services, our existing
contracts, our operating costs or our operating flexibility;
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the effect of worldwide energy conservation measures;
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prevailing economic conditions;
the effect of seasonal variations in temperature and climate on the amount of customer products we are able to
transport, store, process, gather, treat and dispose using our assets;
the realized pricing impacts on revenues and expenses that are directly related to commodity prices;
the level of competition from other midstream energy companies in our geographic markets;
the level of our operating and maintenance costs;
damage to our assets and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and
other natural disasters or acts of terrorism;
outages in our assets;
the relationship between natural gas and NGL prices and resulting effect on processing margins; and
leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or
otherwise.
In addition, the actual amount of cash we will have available for dividend will depend on other factors, including:
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our ability to borrow funds and access capital markets;
the level, timing and characterization of capital expenditures we make;
the level of our general and administrative expenses, including reimbursements to our general partner and its affiliates,
for services provided to us;
the cost of pursuing and completing acquisitions and capital expansion projects, if any;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
restrictions contained in our debt agreements;
the amount of cash reserves established by our general partner; and
other business risks affecting our cash levels.
If we are not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, our
financial condition, results of operations, cash flows and ability to make quarterly cash dividends to our Class A
shareholders will be adversely affected.
A substantial majority of our contracts for transporting, storing, and processing our customers' products on our systems are
long-term firm fee contracts with terms of various durations. For the year ended December 31, 2018, approximately 92% of our
natural gas transportation and storage revenues were generated under firm fee transportation and storage contracts and
approximately 87% of our crude oil transportation revenues were generated under firm fee transportation contracts. As of
December 31, 2018, the weighted average remaining life of our long-term natural gas transportation contracts and natural gas
storage contracts at TIGT and Trailblazer was approximately five years and four years, respectively, and the weighted average
remaining life of our crude oil transportation contracts at Pony Express was approximately two years. In addition, a majority of
Rockies Express' west-to-east pipeline capacity is subject to long-term firm fee contracts that expire in 2019 and a significant
amount of Rockies Express' revenue in 2018 was derived under these contracts.
We may be unable to maintain the long-term nature and economic structure of our current contract portfolio over time.
Depending on prevailing market conditions at the time of a contract renewal, our natural gas transportation, storage and
processing customers with long-term fee-based contracts may desire to enter into contracts with reduced fees, and may be
unwilling to enter into long-term contracts at all. In addition, a significant portion of the long-term contracts for the Pony
Express Pipeline expire in 2019 and those customers may unilaterally decide whether to renew such contracts. If these contracts
are not renewed, Pony Express' ability to enter into replacement long-term contracts would be limited. Under current FERC
policy, Pony Express is generally prohibited from entering into new long-term contracts that grant contract shippers priorities in
prorationing under the ICA unless such contract relates to an increase in the capacity of the Pony Express Pipeline.
Our ability to renew or replace our expiring contracts on terms similar to, or more attractive than, those of our existing
contracts is uncertain and depends on a number of factors beyond our control, including:
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the level of existing and new competition to provide competing services to our markets;
the macroeconomic factors affecting crude oil and natural gas economics for our current and potential customers;
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the balance of supply and demand for natural gas, crude oil and other hydrocarbons, on a short-term, seasonal and
long-term basis, in the markets we directly and indirectly serve;
the extent to which the current and potential customers in our markets are willing to provide firm fee commitments on
a long-term basis; and
the effects of federal, state or local laws or regulations on the contracting practices of our customers.
During periods of price reduction and high volatility in the commodity markets, we expect customers will generally be less
likely to enter into long-term firm fee contracts, and even if they enter into such contracts, may only be willing to provide
acreage dedications to our assets rather than firm fee commitments. Acreage dedications typically do not require our customers
to pay us unless they utilize our assets, and they may also be subject to challenge in bankruptcy proceedings.
To the extent we are unable to renew or replace our existing contracts on terms that are favorable to us or successfully
manage the long-term nature and economic structure of our contract profile over time, our revenues and cash flows could
decline and our ability to make quarterly cash dividends to our Class A shareholders could be materially and adversely affected.
We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and
any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial condition,
cash flows, and operating results.
Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no
assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their
creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to
make quarterly cash dividends to our Class A shareholders. Our long-term firm fee contracts obligate our customers to pay
demand charges regardless of whether they utilize our assets, except for certain circumstances outlined in applicable customer
agreements. As a result, during the term of our long-term firm fee contracts and absent an event of force majeure, our revenues
will generally depend on our customers' financial condition and their ability to pay rather than upon the extent to which our
customers actually utilize our assets. Periods of price reduction and high volatility in the commodity markets could impact their
ability to meet their financial obligations to us. Further, our contract counterparties may not perform or adhere to our existing or
future contractual arrangements. To the extent one or more of our contract counterparties is in financial distress or commences
bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable
provisions of the United States Bankruptcy Code. Any material nonpayment or nonperformance by our contract counterparties
due to inability or unwillingness to perform or adhere to contractual arrangements could have a material adverse impact on our
business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders.
For example, in 2016, Ultra Resources, Inc., or Ultra, defaulted on its firm transportation service agreement with Rockies
Express for approximately 0.2 Bcf/d through November 11, 2019, and as a result, Rockies Express filed a lawsuit seeking
approximately $303 million in damages and other relief. Approximately 13% of Rockies Express' revenue in 2015 was derived
from the Ultra contract. In April 2016, Ultra filed for bankruptcy protection and in January 2017, Rockies Express and Ultra
agreed to settle Rockies Express' claim against Ultra's bankruptcy estate. In accordance with the settlement agreement, Ultra
made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm
transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate
of approximately $0.37, or approximately $26.8 million annually.
In addition, Triad Hunter, LLC, or Triad, sought bankruptcy relief in December 2015. At the time Triad commenced the
bankruptcy proceedings, Triad and Rockies Express were parties to a precedent agreement that provided Triad with an
approximate 0.1 Bcf/d of firm capacity in connection with the Rockies Express Zone 3 Capacity Enhancement Project. In order
to settle its claim, Rockies Express agreed to amend certain material terms of the precedent agreement, including reducing
Triad's firm capacity under the precedent agreement to an approximate 0.05 Bcf/d.
Although the Triad and Ultra claims were ultimately settled, and on terms we view as favorable, future bankruptcy
proceedings with a counterparty may not result in a favorable settlement for us.
The procedures and policies we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in
some cases, requiring credit support, cannot fully eliminate counterparty credit risks. In accordance with FERC regulations and
our own internal credit policies, counterparties with investment grade credit ratings are deemed able to meet their financial
obligations to us without requiring credit support in the form of a letter of credit or prepayment. Although we generally ask for
credit support from customers we deem to not be creditworthy or upon a deterioration of the financial condition of an existing
customer, some customers may be unwilling or unable to provide it due to liquidity constraints. To the extent our procedures
and policies prove to be inadequate or we are unable to obtain credit support, our financial position and results of operations
may be negatively impacted.
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Some of our counterparties may be highly leveraged or have limited financial resources and are subject to their own
operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial
losses in our dealings with such parties. As seen with the decline and volatility in crude oil prices from the second half of 2014
through the first half of 2016 and in the second half of 2018, prices for crude oil and natural gas are subject to large fluctuations
in response to changes in supply and demand, market uncertainty and a variety of other factors that are beyond our control.
Such volatility in commodity prices might have an impact on many of our counterparties and their ability to borrow and obtain
additional capital on attractive terms, which, in turn, could have a negative impact on their ability to meet their obligations to
us.
Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for
the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would
be successful or would provide similar financial and operational results.
We depend on certain key customers for a significant portion of our revenues and are exposed to credit risks of these
customers. The loss of or material nonpayment or nonperformance by any of these key customers could adversely affect our
cash flow and results of operations.
We rely on certain key customers for a portion of revenues. For example, for the year ended December 31, 2018,
Continental Resources accounted for approximately 10% of our revenues on a consolidated basis. In addition, for the year
ended December 31, 2018, approximately 47% of our consolidated revenues were represented by the top ten customers on our
Pony Express System. We own a 75% membership interest in Rockies Express, which is not consolidated for financial
reporting purposes. Approximately 18%, 13%, and 12%, respectively, of Rockies Express' total revenues for the year ended
December 31, 2018 were represented by Rockies Express' three largest non-affiliated shippers.
We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms. For
additional detail, see "—If we are not able to renew or replace expiring customer contracts at favorable rates or on a long-term
basis, our financial condition, results of operations, cash flows and ability to make quarterly cash dividends to our Class A
shareholders will be adversely affected."
In addition, some of these key customers may experience financial problems that could have a significant effect on their
creditworthiness. For example, Rockies Express terminated its contract with its third largest non-affiliated shipper by total 2015
revenue, Ultra, in March 2016. For more detail regarding Ultra, see "—We are exposed to the creditworthiness and
performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one
or more of these parties could adversely affect our financial condition, cash flows, and operating results."
Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to
enforce performance of obligations under contractual arrangements. To the extent one or more of our key customers is in
financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or
rejection under applicable provisions of the United States Bankruptcy Code. Additionally, many of our customers finance their
activities through cash flow from operations, the incurrence of indebtedness or the issuance of equity. The combination of
reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under credit facilities and
the lack of availability of debt or equity financing may result in a significant reduction of our customers' liquidity and limit
their ability to make payments or perform on their obligations to us. Furthermore, some of our customers may be highly
leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their
obligations to us. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition,
creditworthiness or otherwise, could have a material adverse effect on our business, cash flows, ability to make quarterly cash
dividends to our Class A shareholders, the price of our Class A shares, our results of operations and ability to conduct our
business.
If we are unable to make acquisitions on economically acceptable terms, our future growth will be limited, and the
acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per share basis.
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations
on a per share basis.
The acquisition component of our strategy is based, in part, on our expectation of ongoing divestitures of midstream energy
assets by industry participants. Many factors could impair our access to future midstream assets. A material decrease in
divestitures of midstream energy assets by industry participants would limit our opportunities for future acquisitions and could
have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash
dividends to our Class A shareholders. Prior to February 7, 2018, Tallgrass Development was our primary source of
acquisitions. Now that Tallgrass Development has divested its entire asset portfolio and merged out of existence, our growth
through acquisitions will rely almost exclusively on buying assets or businesses from third parties.
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Our future growth and ability to maintain or increase dividends will be limited if we are unable to make accretive
acquisitions because, among other reasons, (i) we are unable to identify attractive acquisition opportunities, (ii) we are unable
to negotiate acceptable purchase contracts, (iii) we are unable to obtain financing for these acquisitions on economically
acceptable terms, (iv) we are outbid by competitors or (v) we are unable to obtain necessary governmental or third-party
consents. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless
result in a decrease in the cash generated from operations on a per share basis. For example, we completed a number of
acquisitions in 2018, including the acquisition of an additional 25.01% membership interest in Rockies Express from Tallgrass
Development, a 100% membership interest in NGL Water Solutions Bakken, LLC from NGL Energy Partners, a 51%
membership interest in Pawnee Terminal from Zenith Energy, and a 38% membership interest in Deeprock North from Kinder
Morgan. If certain risks or unanticipated liabilities were to arise, the desired benefits of these acquisition may not be fully
realized and our future financial performance and results of operations could be negatively impacted.
Any acquisition involves potential risks, including, among other things:
• mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
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an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities;
an inability to successfully integrate the assets or businesses we acquire;
the assumption of unknown liabilities for which we are not indemnified or for which its indemnity is inadequate;
the diversion of management's and employees' attention from other business concerns;
unforeseen difficulties operating in new geographic areas or business lines; and
a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to
finance an acquisition.
If any acquisition eventually proves not to be accretive to our cash available for dividend per share, it could have a material
adverse effect on our business, results of operations, financial condition and ability to make quarterly cash dividends to our
Class A shareholders.
Constructing new assets subjects us to risks of project delays, cost overruns and lower-than-anticipated volumes of
natural gas or crude oil once a project is completed. Our operating cash flows from our capital projects may not be
immediate or meet our expectations.
One of the ways we may grow our business is by constructing additions or modifications to our existing facilities. We also
may construct new facilities, either near our existing operations or in new areas. Construction projects require significant
amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of
which are beyond our control. We may be unable to complete announced construction projects on schedule, at the budgeted
cost, or at all, which could have a material adverse effect on our business and results of operations. For example, in June 2014,
Michels Corporation, or Michels, filed a complaint and request for relief against Rockies Express as a result of work performed
by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and
asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit, and also filed notices
of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. In February 2017, Rockies
Express and Michels resolved the claims brought by Michels in exchange for a $10 million cash payment by Rockies Express.
Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays
or cost increases may arise as a result of factors that are beyond our control, including:
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•
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denial or delay in issuing requisite regulatory approvals and/or permits, which for many of our projects includes a
requirement to obtain a certificate from the FERC authorizing the project before construction can commence;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires,
releases) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
changes in market conditions impacting long lead-time projects;
• market-related increases in a project's debt or equity financing costs; and
•
nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.
25
These projects also involve numerous economic uncertainties and the cash flow generated from these projects may not
meet expectations or project estimates. Moreover, we may not receive any material increase in operating cash flow from a
project for some time or at all. For instance, we incurred construction expenditures in 2018 for the construction of the Iron
Horse Pipeline and the Cheyenne Connector Pipeline. However, we will not receive any increases in cash flow from these
projects until such project is completed and placed in-service.
The project specifications and expectations regarding project cost, timing, asset performance, investment returns and other
matters usually rely in part on the expertise of third parties such as engineers, technical experts and construction contractors.
These estimates may prove to be inaccurate because of numerous operational, technological, economic and other uncertainties.
We also rely in part on estimates from producers regarding the timing and volume of anticipated natural gas and crude oil
production. Production estimates are subject to numerous uncertainties, nearly all of which are beyond our control. These
estimates may prove to be inaccurate, and new facilities may not attract sufficient volumes to achieve our expected cash flow
and investment return.
If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our
ability to make quarterly cash dividends may be diminished or our financial leverage could increase.
In order to expand our asset base through acquisitions or capital projects, we may need to make expansion capital
expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our
business operations and may be unable to maintain or raise the level of our quarterly cash dividends. We could be required to
use cash from our operations or incur borrowings or sell additional Class A shares or other limited partner interests in order to
fund our expansion capital expenditures. Using cash from operations will reduce cash available for dividends to our Class A
shareholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be
limited by our financial condition at the time of any such financing or offering as well as the covenants in our debt agreements,
general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in
obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to
pay quarterly cash dividends to our Class A shareholders. In addition, incurring additional debt may significantly increase our
interest expense and financial leverage, and issuing additional limited partner interests may result in significant dilution of
Class A shareholders and increase the aggregate amount of cash required to maintain the then-current dividend rate, which
could materially decrease our ability to pay quarterly cash dividends at the then-current dividend rate. We do not currently have
any commitment with our general partner or other affiliates, including Tallgrass Energy Holdings, for them to provide any
direct or indirect financial assistance to us.
The Throughput and Deficiency Agreements for the Pony Express System and some of our service agreements with
respect to our water business services contain provisions that can reduce the cash flow stability that the agreements were
designed to achieve.
The Throughput and Deficiency Agreements, or TDAs, for the Pony Express System and some of our service agreements
with respect to our water services business are firm fee contracts with minimum volume commitments that are designed to
generate stable cash flows and minimize direct commodity price risk. Under these minimum volume commitments, our
customers agree to ship a minimum volume of crude oil or to have a minimum volume of water serviced, as the case may be,
over certain periods during the term of the applicable agreement.
If a customer's actual throughput volumes or volumes serviced are less than its minimum volume commitment for the
applicable period, it must make a deficiency payment at the end of the applicable period based upon the difference between the
minimum volume commitment and the actual amounts serviced. A customer may apply any deficiency payments it makes as a
credit against payment for volumes transported or serviced by us in excess of its minimum volume commitment in future
periods. Upon termination of the Pony Express TDAs, customers may continue to use any remaining deficiency credits against
any volumes serviced by us for a period of six months following termination, even though such customers may no longer have
a minimum volume commitment.
To the extent that a customer's actual throughput volumes or volumes serviced are above its minimum volume commitment
for the applicable period, the customer may use the excess volumes to credit against future deficiency payments in subsequent
periods. As of December 31, 2018, Pony Express had a cumulative net deficiency balance of $97.1 million and a cumulative
shipper incremental balance of $4.9 million.
Some or all of these provisions can apply in combination with one another. As a result, in the future we may not receive
any cash payments for volumes shipped or serviced by us, and we may not receive deficiency payments as a result of excess
volumes shipped in prior periods. This would result in reduced revenue and cash flows to us and could have a material adverse
effect on our ability to make quarterly cash dividends to our Class A shareholders.
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We may not be able to compete effectively in our midstream services activities and our business is subject to the risk of a
capacity overbuild of midstream energy infrastructure in the areas where we operate.
We face competition in all aspects of our business and may not be able to compete effectively against our competitors. In
general, competition comes from a wide variety of players in a wide variety of contexts, including new entrants and existing
players and in connection with day-to-day business, expansion capital projects, acquisitions and joint venture activities. Some
of our competitors have capital resources greater than ours and control greater supplies of crude oil, natural gas or NGLs.
Our ability to renew or replace our existing contracts at rates sufficient to maintain current revenues and current cash flows
could be adversely affected by the activities of our competitors. Some of our competitors have assets in closer proximity to
certain hydrocarbon supplies and have available idle capacity in existing assets that may require no or minimal capital
investments for use. For example, several pipelines access many of the same basins as our assets and provide transport to
customers in the Rocky Mountain, Appalachian Mountain and Midwest regions of the United States, such as the Dakota Access
Pipeline, Saddlehorn-Grand Mesa Pipeline and White Cliffs Pipeline that compete with the Pony Express Pipeline. Pony
Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers
looking to capitalize on basis differentials between two primary crude oil benchmarks (West Texas Intermediate Crude and
Brent Crude). Furthermore, Tallgrass Energy Holdings and its affiliates are not limited in their ability to compete with us.
Our competitors may expand or construct new midstream services assets that would create additional competition for the
services we provide to our customers, or our customers may develop their own facilities in lieu of using ours. A significant
driver of competition in some of the markets where we operate (including, for example, the Rocky Mountain and Appalachian
Mountain regions) has been the rapid development of new midstream energy infrastructure capacity in recent years. As a result,
we are exposed to the risk that the areas in which we operate become overbuilt, resulting in an excess of midstream energy
infrastructure capacity. If we experience a significant capacity overbuild in one or more of the areas where we operate, it could
have a significant adverse impact on our financial position, cash flows and ability to maintain or increase dividends to our Class
A shareholders. For example, our competitors in these areas could substantially decrease the prices at which they offer their
services, and we may be unable to compete effectively. This could materially impair our cash flows and ability to make
quarterly cash dividends to our Class A shareholders.
Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users,
including electricity, coal, other fuels and alternative energy. Increased demand for such forms of energy at the expense of
natural gas or fuels derived from crude oil could lead to a reduction in demand for our services.
All of these competitive pressures could make it more difficult for us to renew our existing long-term firm fee contracts
when they expire or to attract new customers as we seek to expand our business, which could have a material adverse effect on
our business, financial condition, results of operations and prospects. In addition, competition could intensify the negative
impact of factors that decrease demand for natural gas and crude oil in the markets we serve, such as adverse economic
conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions decreasing demand.
We have certain long-term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even
if our costs increase. As a result, our costs could exceed our revenues.
As of December 31, 2018, approximately 53% of our contracted natural gas transportation firm capacity was provided
under long-term, fixed price "negotiated or discount rate" contracts that are not subject to adjustment, even if our cost to
perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues
received under such contracts. It is possible that costs to perform services under our "negotiated or discount rate" contracts will
exceed the negotiated or discounted rates. It is also possible with respect to discounted rates that if our filed "recourse rates"
should ever be reduced below applicable discounted rates, we would only be allowed by the FERC to charge the lower recourse
rates, since FERC policy does not allow discount rates to be charged to the extent that they exceed applicable recourse rates. If
these events were to occur, it could decrease the cash flow realized by our assets and, therefore, the cash we have available for
dividends to our Class A shareholders.
Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a
"negotiated rate," which is generally fixed between the natural gas pipeline and the shipper for the contract term and does not
necessarily vary with changes in the level of cost-based "recourse rates," provided that the affected customer is willing to agree
to such rates and that the FERC has accepted the negotiated rate agreement. These "negotiated or discount rate" contracts are
not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the
specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between "recourse
rates" (if higher) and negotiated or discounted rates, under current FERC policy, may be recoverable from other shippers in
certain circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future
rate case. However, if the FERC were to disallow the recovery of such costs from other customers, it could decrease the cash
flow realized by our assets and, therefore, the cash we have available for dividends to our Class A shareholders.
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Rates under Pony Express' TDAs are typically subject to change only per contract terms and conditions, including Pony
Express' right to file changes to contract rates to reflect annual index percentage adjustments published by the FERC. We
generally cannot file for rate increases with respect to committed shippers who have signed TDAs, other than to reflect annual
index adjustments or to recover compliance costs imposed by governmental actions.
A significant amount of the revenue currently generated by the Pony Express System and the Rockies Express Pipeline
are from contracts that contain most favored nations rights, limiting flexibility to offer certain capacity to new shippers.
Approximately 93% of the Pony Express System's current available contractible capacity is provided to committed
shippers under long-term TDAs. Some of the TDAs contain most favored nations rights, or MFNs, which could result in lower
rates being charged to certain committed shippers to ensure that the rates such shippers are paying are no greater than ninety to
one hundred percent of the rates being charged to other similarly situated shippers for similar service at similar volumes and
terms. Triggering the MFNs on the TDAs could lead to a reduction in revenue generated by Pony Express, which could have a
material adverse effect on our revenues, cash flow, results of operations, and our ability to make quarterly cash dividends to our
Class A shareholders.
Rockies Express' foundation and anchor shippers for west-to-east service hold certain MFNs granting them a right to a rate
reduction in certain instances where Rockies Express provides service to another shipper at a rate lower than the foundation or
anchor shipper rate for a term of one year or greater or, in the case of the foundation shipper, from certain specified receipt
locations. The MFNs effectively limit Rockies Express' flexibility in negotiating rates for some of its services with other
shippers, because triggering the MFNs of the foundation and anchor shippers could lead to a reduction in the rates that Rockies
Express charges, which could have a material adverse effect on Rockies Express' revenues, cash flow and results of operations,
which in turn could impair Rockies Express' ability to make distributions to its equity holders and our ability to make quarterly
cash dividends to our Class A shareholders.
If third-party pipelines or other facilities interconnected to our systems become partially or fully unavailable, if the
volumes we transport do not meet the quality requirements of such pipelines or facilities, or if claims are made against us
for events that occur downstream of our interconnection with third-party facilities, our revenues and our ability to make
quarterly cash dividends to our Class A shareholders could be adversely affected.
Our assets typically connect to other pipelines or facilities owned, leased and/or operated by unaffiliated third parties, such
as ONEOK Bakken Pipeline, L.L.C., Whiting Petroleum, and others. For example, our Pony Express System connects to
upstream joint tariff pipelines, including the Belle Fourche Pipeline owned by the True Companies (which also own and operate
the Bridger Pipeline upstream of the Belle Fourche Pipeline) and the Double H Pipeline owned by Kinder Morgan, which are
responsible for delivering a substantial portion of the crude oil for transportation on the Pony Express System. In addition, part
of the crude oil we transport on the Pony Express System is either stored in crude oil tanks located on, or pumped over to
downstream pipelines that interconnect through, the Cushing Terminal, which we do not operate.
The continuing operation of such third-party facilities and other midstream facilities is not within our control. These
pipelines, plants and other midstream facilities may become unavailable to us for any number of reasons, including because of
testing, turnarounds, line repair, extended unscheduled maintenance, reduced operating pressure, lack of operating capacity,
regulatory requirements, conversion to another form of commodity transportation service, cessation of operations, curtailments
of receipt or deliveries due to insufficient capacity or because of damage from weather events or other operational hazards. For
example, the operations of the Bridger Pipeline's Poplar System were down for approximately five months during the first half
of 2015 due to a pipeline release. Bridger declared a force majeure as a result of this event and temporarily lacked the capacity
to make up volumes on other lines that directly or indirectly deliver crude oil into designated origin points on the Pony Express
System or the Belle Fourche Pipeline. The largest committed shipper on the Pony Express System also declared a force majeure
as a result of this incident.
In addition, our interconnection with third-party facilities may result in claims being made against us for events that occur
downstream of our pipelines. For example, TIGT has been named as a defendant in a lawsuit for damages arising from a gas
leak and home explosion that occurred in June 2014 in Finney County, Kansas. Although TIGT did not directly distribute
natural gas to the home in question, the plaintiffs nonetheless allege that TIGT committed torts and otherwise violated federal
safety laws. TIGT believes the claims are without merit and intends to vigorously defend them.
If the costs to us to access and transport on these third-party pipelines or any alternative pipelines significantly increase, if
any of these pipelines or other midstream facilities become unable to receive, transport, store or process products from our
assets, if the volumes we transport or process do not meet the quality requirements of such pipelines or facilities, or if claims
are made against us for events that occur downstream of our interconnection with third-party facilities, our revenues and our
ability to make quarterly cash dividends to our Class A shareholders could be adversely affected.
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The lack of diversification of our assets and geographic locations could adversely affect our ability to make quarterly
cash dividends to our Class A shareholders.
We rely on revenues generated from our assets, which are primarily located in the Rocky Mountain, Appalachian Mountain
and Midwest regions of the United States. Revenues on our assets primarily depend on exploration and production activities of
our customers located in these regions. Due to our lack of diversification in assets and geographic location, an adverse
development in these businesses or our customers' areas of operations, including adverse developments due to catastrophic
events, weather, regulatory action and decreases in supply or demand for hydrocarbons, could have a significantly greater
impact on our results of operations and cash available for dividends to our Class A shareholders than if we maintained more
diverse assets and locations. For example, our water business services are provided through a limited number of assets with a
relatively high concentration in Weld County, Colorado. Thus, the growth and profitability of our water business services will
be especially vulnerable to conditions and fluctuations in the local Weld County economy and subject to changes in local
government regulations and priorities. In addition, a number of our other assets are also located in Colorado. Certain interest
groups in Colorado generally opposed to the development of oil, natural gas and NGLs, and hydraulic fracturing in particular,
have from time to time advanced various options for ballot initiatives aimed at significantly limiting or preventing the
development of oil, natural gas and NGLs. For example, a Colorado ballot initiative, Proposition 112, would have substantially
increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development in the
state. Although Proposition 112 was defeated in the November 2018 elections, similar efforts in Colorado, if passed, could
restrict oil and gas development in the future which could result in a reduction in demand for our services.
Our operations are dependent on our rights and ability to receive or renew the required permits and other approvals
from governmental authorities and other third parties.
Performance of our operations requires that we obtain and maintain numerous environmental and land use permits and
other approvals authorizing our business activities. A decision by a governmental authority or other third party to deny, delay or
restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an
existing permit or other approval, could have a material adverse effect on our ability to initiate or continue operations at the
affected location or facility. Expansion of our existing operations and construction of new assets are both also predicated on
securing the necessary environmental or land use permits and other approvals, which we may not receive in a timely manner or
at all.
In order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and
present data to governmental authorities pertaining to the potential adverse impact that any proposed activities may have on the
environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require
preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new
sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens
the time needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is
sometimes delayed or prevented due to community opposition and other factors beyond our control. The denial of a permit or
other approval essential to our operations or the imposition of restrictive conditions with which it is not practicable or feasible
to comply could impair or prevent our ability to develop or expand a property or right-of-way. Significant opposition to a
permit or other approval by neighboring property owners, members of the public or non-governmental organizations, or other
third parties or delay in the environmental review and permitting process also could impair or delay our ability to develop or
expand a property or right-of-way. New legal requirements, including those related to the protection of the environment, could
be adopted at the federal, state and local levels that could materially adversely affect our operations, our cost structure or our
customers' ability to use our services. Such current or future regulations could have a material adverse effect on our business
and we may not be able to obtain or renew permits or other approvals in the future.
Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect
our business and results of operations.
Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial
markets. Included among these potential negative impacts are reduced energy demand and lower prices for our services and
increased difficulty in collecting amounts owed to us by our customers which could reduce our access to credit markets, raise
the cost of such access or require us to provide additional collateral to our counterparties. Our ability to access available
capacity under the TEP revolving credit facility could be impaired if one or more of our lenders fails to honor its contractual
obligation to lend to us. If financing is not available when needed, or is available only on unfavorable terms, we may be unable
to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
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The amount of cash we have available for dividend to Class A shareholders depends primarily on our cash flow rather
than on our profitability, which may prevent us from making dividends, even during periods in which we record net income.
The amount of cash we have available for dividends depends primarily upon our cash flow and not solely on profitability,
which will be affected by non-cash items. As a result, we may make cash dividends during periods when we record losses for
financial accounting purposes and may not make cash dividends during periods when we record net earnings for financial
accounting purposes.
The revenue in our Gathering, Processing & Terminalling segment largely depends on the amount of natural gas that
our customers actually deliver to our natural gas processing plants.
During the year ended December 31, 2018, approximately 12%, 51%, and 37% of TMID's Adjusted EBITDA came from
firm fee, volumetric fee, and commodity sensitive contracts, respectively. On these volumetric fee contracts, our revenue is
largely tied to the amount of natural gas that our customers actually deliver to our Casper and Douglas plants for processing.
Unlike many pipeline transportation customers, our natural gas processing customers are not generally subject to "take or pay"
obligations. Thus, if our natural gas processing customers do not produce natural gas and deliver that natural gas to our
processing plants to be processed, revenue for our Gathering, Processing & Terminalling segment will decline. As natural gas,
crude oil or NGL prices decline, our customers will likely make less money from the production of natural gas, crude oil or
NGLs than it costs them to produce it. If that happens, our customers may not continue to produce natural gas and our revenue
will decline. The decreased commodity prices in late 2014 through 2016 contributed to a significant drop in actual volumes
from several producers from which TMID receives natural gas for processing. If processing volumes at TMID do not continue
recovering over time, we could have an impairment of the goodwill at the TMID reporting unit, which is a component of our
Gathering, Processing & Terminalling segment, and our revenue will decline. In addition, the fees our customers pay to reserve
capacity at our processing plants may not deter those customers from processing their natural gas volumes at other facilities,
with whom they may have had prior arrangements or otherwise.
We are exposed to direct commodity price risk with respect to some of our processing revenues and the utilization of
commodity derivatives by Stanchion, and our exposure to direct commodity price risk may increase in the future.
Our Gathering, Processing & Terminalling segment operates under three types of contracts, two of which directly expose
our cash flows to increases and decreases in the price of natural gas and NGLs: percent of proceeds and keep whole processing
contracts. We do not currently hedge the commodity exposure inherent in these types of processing contracts, and as a result,
our revenues and results of operations are impacted by fluctuations in the prices of natural gas and NGLs.
Percent of proceeds processing contracts generally provide upside in high commodity price environments, but result in
lower margins in low commodity price environments. Under keep whole processing contracts, our revenues and our cash flows
generally increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and
NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for us
to process natural gas under keep whole arrangements. When natural gas prices are high relative to NGL prices, it is less
profitable for us and our customers to process natural gas both because of the higher value of natural gas and the increased cost
(principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we
may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the
volume of natural gas processed at some of our plants. In addition, NGL prices have historically been related to the market
price of oil and as a result any significant changes in oil prices could also indirectly impact our operations. Indirectly, reduced
commodity prices impact us through reduced exploration and production activity, which results in fewer opportunities for new
business to offset natural volume declines. NGL and natural gas prices are volatile and are impacted by changes in the supply
and demand for NGLs and natural gas, as well as market uncertainty. For example, from the second half of 2014 through the
first half of 2016, natural gas and crude oil prices declined substantially and these declines directly and indirectly resulted in
lower processing volumes and realizations on our percent of proceeds and keep whole processing contracts.
In 2017, we also began utilizing commodity derivatives in connection with the operations of our crude oil marketing
subsidiary, Stanchion. Our portfolio of derivative and other energy contracts may consist of contracts to buy and sell
commodities that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or
manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. If a performance failure
were to occur in one of our contracts, we might incur losses in addition to amounts, if any, already recognized in our financial
statements or paid to, or received from, counterparties. As a result, our business, results of operations, financial condition and
ability to pay quarterly cash dividends to our Class A shareholders may be adversely affected.
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Our success depends on the supply and demand for natural gas and crude oil.
The success of our business is in many ways impacted by the supply and demand for natural gas and crude oil. For
example, our business can be negatively impacted by sustained downturns in supply and demand for natural gas and crude oil
in the markets that we and our customers serve, including reductions in our ability to renew contracts on favorable terms and to
construct new infrastructure. Further, a portion of the demand for our water business services depends substantially on the level
of expenditures by the oil and gas industry for the exploration, development and production of oil and natural gas reserves.
These expenditures are generally dependent on the industry's view of future oil and natural gas prices and are sensitive to the
industry's view of future economic growth and the resulting impact on demand for oil and natural gas. Declines, as well as
anticipated declines, in oil and gas prices could also result in project modifications, delays or cancellations, general business
disruptions, and delays in, or nonpayment of, amounts that are owed to us. These effects could have a material adverse effect on
our financial condition, results of operations and cash flows.
One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in
the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced
with natural gas-fired power generation rather than alternative energy sources. One of the major factors impacting domestic
natural gas and crude oil supplies has been the significant growth in unconventional sources such as shale plays and the
continued progression of hydraulic fracturing technology. The supply and demand for natural gas and crude oil, and therefore
the future rate of growth of our business, depends on these and many other factors outside of our control, including, but not
limited to:
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adverse changes in general global economic conditions;
adverse changes in domestic laws and regulations;
technological advancements that may drive further increases in production and reduction in costs of developing crude
oil and natural gas shale plays;
the price and availability of other forms of energy, including alternative energy which may benefit from government
subsidies;
adoption of various energy efficiency and conservation measures;
prices for natural gas, crude oil and NGLs;
decisions of the members of the Organization of the Petroleum Exporting Countries, or OPEC, regarding price and
production controls;
increased costs to explore for, develop, produce, gather, process and transport natural gas or crude oil;
• weather conditions, seasonal trends and hurricane disruptions;
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the nature and extent of, and changes in, governmental regulation, for example GHG legislation, taxation and
hydraulic fracturing;
perceptions of customers on the availability and price volatility of our services and natural gas and crude oil prices,
particularly customers' perceptions on the volatility of natural gas and crude oil prices over the long-term;
capacity and transportation service into, or out of, our markets; and
petrochemical demand for NGLs.
The oil and gas industry historically has experienced periodic downturns. For example, from the second half of 2014
through the first half of 2016, the oil and gas industry experienced a sustained period of decline and volatility in natural gas and
crude oil prices. Any prolonged downturns in the oil and gas industry could result in a reduction in demand for our services and
could adversely affect our financial condition, results of operations and cash flows.
Any significant decrease in available supplies of hydrocarbons in our areas of operation, or redirection of existing
hydrocarbon supplies to other markets, could adversely affect our business and operating results. Persistent low commodity
prices could result in lower throughput volumes and reduced cash flows.
Our business is dependent on the continued availability of natural gas and crude oil production and reserves. Production
from existing wells and natural gas and crude oil supply basins with access to our assets will naturally decline over time. The
amount of natural gas and crude oil reserves underlying these wells may also be less than anticipated, and the rate at which
production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the contracted
capacity and/or the volume of products utilizing our assets, our customers must continually obtain adequate supplies of natural
gas and crude oil.
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However, the development of additional natural gas and crude oil reserves requires significant capital expenditures by
others for exploration and development drilling and the installation of production, storage, transportation and other facilities
that permit natural gas and crude oil to be produced and products delivered to our facilities. In addition, low prices for natural
gas and crude oil, regulatory limitations, including environmental regulations, or the lack of available capital for these projects
could have a material adverse effect on the development and production of additional reserves, as well as storage, pipeline
transportation, and import and export of natural gas and crude oil supplies. The volatility and sustained lower prices for crude
oil and refined products from the second half of 2014 through the first half of 2016 led to a decline in drilling activity,
production and refining of crude oil, and import levels in these areas. For example, in response to this volatility and lower
prices, a number of producers in our areas of operation significantly reduced their capital budgets and drilling plans in 2015
through 2017. Although producers in areas we serve increased their production in 2018 and are expected to continue this
increase in 2019, it may take a prolonged period before the increased production has the possibility of resulting in increased
utilization of our assets. In addition, production may fluctuate for other reasons, including, for example, in the case of crude oil,
the extent to which the members of OPEC abide by agreements regarding production controls. Furthermore, competition for
natural gas and crude oil supplies to serve other markets could reduce the amount of natural gas and crude oil supply available
for our customers. Accordingly, to maintain or increase the contracted capacity and/or the volume of products utilizing our
assets, our customers must compete with others to obtain adequate supplies of natural gas and crude oil.
If new supplies of natural gas and crude oil are not obtained to replace the natural decline in volumes from existing supply
basins, if natural gas and crude oil supplies are diverted to serve other markets, if environmental regulations restrict new natural
gas and crude oil drilling or if OPEC does not maintain production controls, the overall demand for services on our systems
will likely decline, which could have a material adverse effect on our ability to renew or replace our current customer contracts
when they expire and on our business, financial condition, results of operations and ability to make quarterly cash dividends to
our Class A shareholders.
Our natural gas, crude oil and liquids operations are subject to extensive regulation by federal, state and local
regulatory authorities, which could have a material adverse effect on our business, financial condition, and results of
operations.
We provide open-access interstate transportation service on our interstate natural gas transportation systems pursuant to
tariffs approved by the FERC. Our interstate natural gas transportation and storage operations are regulated by the FERC, under
the NGA, the NGPA, and the EPAct 2005. The Rockies Express Pipeline, the TIGT System and the Trailblazer Pipeline each
operate under a tariff approved by the FERC that establishes rates and terms and conditions of service to our customers. The
rates and terms of service on the Pony Express System and PRE Pipeline are subject to regulation by the FERC under the ICA,
and the Energy Policy Act of 1992. We provide interstate crude oil transportation service on the Pony Express System and PRE
Pipeline pursuant to tariffs on file with the FERC. Our NGL pipeline that interconnects with Overland Pass Pipeline is leased to
a third party that has obtained a FERC waiver from the tariff, filing and reporting requirements of the ICA, and our NGL
pipeline that interconnects with ONEOK's Bakken NGL Pipeline is leased to a third party that is obligated to operate the leased
pipeline in conformance with the ICA as a FERC-regulated NGL pipeline.
Generally, the FERC's authority over natural gas facilities extends to:
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rates, operating terms and conditions of service;
the form of tariffs governing service;
the types of services we may offer to our customers;
the certification and construction of new, or the expansion of existing, facilities;
the acquisition, extension, disposition or abandonment of facilities;
customer creditworthiness and credit support requirements;
the maintenance of accounts and records;
relationships among affiliated companies involved in certain aspects of the natural gas business;
depreciation and amortization policies; and
the initiation and discontinuation of services.
The FERC's authority over crude oil and NGL pipelines is less broad, extending to:
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rates, rules and regulations of service;
the form of tariffs governing rates and service;
the maintenance of accounts and records; and
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depreciation and amortization policies.
Interstate natural gas pipelines subject to the jurisdiction of the FERC may not charge rates or impose terms and conditions
of service that, upon review by the FERC, are found to be unjust, unreasonable, unduly discriminatory, or preferential. The
maximum recourse rates that we may charge for our natural gas transportation and storage services are established through the
FERC's ratemaking process. The maximum applicable recourse rates and terms and conditions for service are set forth in our
FERC-approved tariffs.
On June 29, 2018, Trailblazer filed a general rate case with the FERC proposing, among other things, an increase in rates
on Trailblazer's Existing System Firm Transportation Service and a decrease in rates for Expansion System Firm Transportation
Service and interruptible services. On July 31, 2018, the FERC issued an Order: (1) approving the as-filed rate decreases for
Expansion System Firm Transportation Service and interruptible services, effective August 1, 2018; (2) accepting and
suspending the rest of the rate case filing (including the proposed rate increases) to become effective January 1, 2019 subject to
refund, and establishing hearing and settlement procedures; and (3) establishing a paper hearing to examine the extent to which
Trailblazer is entitled to an Income Tax Allowance. Resolution of these issues remains pending before the FERC. In the event
that Trailblazer is not able to recover its full cost of service as a result of the outcome of this proceeding, Trailblazer's cash
flows and its results of operations could be adversely affected.
TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA in October 2015, which resulted in a
settlement that was approved by an order issued by the FERC on November 2, 2016. The settlement established settlement rates
to be effective through at least April 30, 2019. In the event the assumptions relied upon during settlement negotiations were
incorrect or the actual costs incurred to operate the TIGT System increase, TIGT's cash flows and its results of operations could
be adversely affected.
Pursuant to the NGA, existing interstate natural gas transportation and storage rates and terms and conditions of service
may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to
terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can
be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i)
"recourse rates" (i.e., the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its
tariff); (ii) "discount rates" (i.e., rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and
that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline's tariff); and (iii)
"negotiated rates" (i.e., rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within
or outside of the cost-based maximum and minimum rate levels set forth in the tariff, and which are individually filed with the
FERC for review and acceptance). When capacity is available and offered for sale, the rates (which include reservation,
commodity, surcharges, and fixed fuel and lost and unaccounted for charges) at which such capacity is sold are subject to
regulatory approval and oversight. Regulators and customers on our natural gas pipeline systems have the right to protest or
otherwise challenge the rates that we charge under a process prescribed by applicable regulations. The FERC may also initiate
reviews of our rates. Customers on our interstate natural gas pipeline systems may also dispute terms and conditions contained
in our agreements, as well as the interpretation and application of our tariffs, among other things.
Rates for interstate crude oil transportation service must be filed as a tariff with the FERC and are subject to applicable
FERC regulation. The filed tariff rates include contract rates entered into with shippers willing to make long-term commitments
to the pipeline to support new pipeline capacity. Contract rates generally are not subject to regulation or change by the FERC.
Non-contract "walk-up" rates are available to uncommitted non-contract shippers and generally are subject to regulation and
change by the FERC. Interstate crude oil pipelines typically must reserve at least ten percent of their capacity for walk-up
shippers. Contract tariff rates may be changed by Pony Express on an annual basis to reflect annual FERC index adjustments to
the extent permitted by contract. Non-contract rates may be adjusted, positively or negatively, on an annual basis pursuant to a
FERC indexing procedure. An interstate crude oil pipeline may also file new tariff rates at any time, subject to contract
restrictions and provisions, and FERC regulatory procedures. The filing of any indexed rate increase or other rate increase may
be protested by parties having standing, subject to applicable regulatory and contract provisions, and thereby be subjected to
cost-of-service review by the FERC to determine whether the proposed new rate is just and reasonable.
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Under the ICA, which applies to the Pony Express System and the PRE Pipeline, parties having standing and not restricted
by contract may protest newly filed rates and terms and conditions of service within a prescribed notice period. Currently,
shippers party to a TDA for the Pony Express System are generally limited from protesting certain rates on the Pony Express
System, but this limitation will not apply to such shipper upon expiration of their TDA. The FERC is authorized to suspend,
subject to refund, the effectiveness of a protested rate for up to seven months while it determines if the protested rate is just and
reasonable. Our rates may be reduced and we may be required to issue refunds as a result of settlement or by an order of the
FERC following a hearing finding that a protested rate is unjust and unreasonable. Parties having standing and not restricted by
contract may file a complaint at any time regarding existing rates and terms and conditions of service. If the complaint is not
resolved by settlement, the FERC may conduct a hearing and order the crude oil pipeline to make reparations going back for up
to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. We cannot
guarantee that any new or existing local or joint tariff rate for service on the Pony Express System or the PRE Pipeline would
not be rejected or modified by the FERC, or subjected to refunds or reparations. While the FERC regulates rates and terms and
conditions of service for transportation of crude oil in interstate commerce by pipeline, state agencies may also regulate
facilities (including construction, acquisition, disposition, financing, and abandonment), rates, and terms and conditions of
service for crude oil pipeline transportation in intrastate commerce. Any successful challenge by a regulator or shipper in any of
these matters could have a material adverse effect on our business, financial condition and results of operations.
Pony Express Pipeline's tariff rates may not always be eligible for increases to reflect a FERC index adjustment. For
example, on November 2, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking, under which the FERC is
proposing changes to its policies regarding the permissible scope of rate increases based on its annual issuance of changes to
the generic oil pipeline index, based on specific pipelines' earnings or their specific changes to costs. The FERC's Advanced
Notice of Proposed Rulemaking does not propose specific regulations, and may be followed by a Notice of Proposed
Rulemaking proposing specific regulations or a Policy Statement announcing new or changed policies. This proceeding is
pending before the FERC.
The FERC's jurisdiction over natural gas facilities extends to the certification and construction of interstate transportation
and storage facilities, including, but not limited to, acquisitions, facility maintenance and upgrades, expansions, and
abandonment of facilities and services. With some exceptions applicable to smaller projects, auxiliary facilities, and certain
facility replacements, prior to commencing construction and/or operation of new or existing interstate natural gas transportation
and storage facilities, an interstate natural gas pipeline must obtain a certificate authorizing the construction from, or file to
amend its existing certificate with, the FERC. Typically, a significant expansion project requires review by a number of
governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process
on schedule. Any delay or refusal by an agency to issue authorizations or permits as requested for one or more of these projects
may mean that they will be constructed in a manner or with capital requirements that we did not anticipate or that we will not
be able to pursue these projects. Such delay, modification or refusal could materially and negatively impact the additional
revenues expected from these projects. The FERC does not regulate the construction, expansion, or abandonment of crude oil
or NGL pipelines, whether interstate or intrastate, nor the initiation or discontinuation of services on those pipelines, provided
that the action taken is not discriminatory or preferential among similarly situated shippers.
The FERC has the authority to conduct audits of regulated entities to assess compliance with FERC regulations and
policies. The FERC also conducts audits to verify that the websites of interstate natural gas pipelines accurately provide
information on the operations and availability of services on the pipeline. FERC regulations also require entities providing
interstate natural gas and crude oil transportation services to comply with uniform terms and conditions for service, as set forth
in publicly available tariffs or, as it concerns natural gas facilities, agreements for transportation and storage services executed
between interstate pipelines and their customers. Natural gas transportation service agreements are generally required to
conform, in all material respects, with the standard form of service agreements set forth in the natural gas pipeline's FERC-
approved tariff. The pipeline and a customer may choose to enter into a non-conforming service agreement so long as the
agreement is filed with, and accepted by, the FERC. In the event that the FERC finds that a natural gas transportation
agreement, in whole or part, is materially non-conforming, the FERC could reject the agreement or require us to modify the
agreement, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all
customers. Transportation agreements entered into with crude oil shippers are generally not subject to FERC regulation or
required to be available for FERC or public review, but the rates and terms and services provided to similarly situated shippers
may not be unduly discriminatory or preferential.
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The FERC has promulgated rules and policies covering many aspects of our natural gas pipeline business, including
regulations that require us to provide firm and interruptible transportation service on an open access basis that is not unduly
discriminatory or preferential, provide internet access to current information about our available pipeline capacity and other
relevant transmission information, and permit pipeline shippers to release contracted transportation and storage capacity to
other shippers, thereby creating secondary markets for such services. FERC regulations also prevent interstate natural gas
pipelines from sharing customer information with marketing affiliates, and restrict how interstate natural gas pipelines share
transportation information with marketing affiliates. FERC regulations require that certain transmission function personnel of
interstate natural gas pipelines function independently of personnel engaged in natural gas marketing functions. Crude oil
pipelines subject to the ICA must comply with FERC regulations that require the pipeline to act as a common carrier and not
engage in undue discrimination or preferential treatment with respect to shippers. The ICA also prevents crude oil and NGL
pipelines from disclosing certain shipper information without the shipper's consent.
FERC policies also govern how interstate natural gas pipelines respond to interconnection requests from third party
facilities, including other pipelines. Generally, an interstate natural gas pipeline must grant an interconnection request upon the
satisfaction of several conditions. As a consequence, an interstate natural gas pipeline faces the risk that an interconnecting
third-party pipeline may pose a risk of additional competition to serve a particular market or customer. Failure to comply with
applicable provisions of the NGA, NGPA, EPAct 2005 and certain other laws, as well as with the regulations, rules, orders,
restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies,
including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of more than
$1 million per day, per violation. Violations of the ICA, the Energy Policy Act of 1992, or regulations and orders promulgated
by the FERC are also subject to administrative and criminal penalties and remedies, including forfeiture and individual liability.
In addition, new laws or regulations or different interpretations of existing laws or regulations applicable to our pipeline
systems or midstream facilities could have a material adverse effect on our business, financial condition, results of operations
and prospects. For example, on November 22, 2017, in FERC Docket No. OR17-2-000, the FERC issued an Order on Petition
for Declaratory Order addressing whether certain specific hypothetical transactions between a petroleum liquids pipeline and its
marketing affiliate proposed by the petitioner, Magellan Midstream Partners, L.P., would violate the requirements of the ICA or
the FERC's regulations and policies. The FERC concluded that certain transactions proposed by the petitioner could be
inconsistent with the ICA and the FERC's policies. Various market participants filed requests for clarification or, in the
alternative, rehearing of the November 22, 2017 declaratory order. On January 22, 2018, the FERC issued an order granting
rehearing for further consideration, which afforded the FERC additional time to consider and rule on the pending clarification/
rehearing requests. The outcome of this proceeding and any related proceeding(s) may require us to modify the business
practices between our petroleum liquids pipelines regulated by the FERC and our affiliated marketer, Stanchion. To the extent
the foregoing proceedings result in substantial new restrictions on the transactions between petroleum liquids pipelines and
their affiliated shippers, the business activities of Stanchion could be affected.
The FERC may also not continue to pursue its approach of pro-competitive policies as it considers matters such as
interstate pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and
transportation and storage facilities. Further, the FERC is reviewing, and may possibly revise, its policies for analyzing whether
proposed natural gas facilities are in the public convenience and necessity, including its Policy Statement on Certification of
New Interstate Natural Gas Facilities issued in 1999. A change in such policies could delay or prevent the FERC's approval of
proposed natural gas facilities, which could have a material impact on our business. We may face challenges to our rates or
terms of service in the future. Any successful challenge could materially and adversely affect our future earnings and cash
flows.
The rates and terms and conditions of our regulated assets are subject to review and possible adjustment by federal and
state regulators, which could adversely affect our business, results of operations, financial condition and ability to make
quarterly cash dividends to our Class A shareholders.
Our shippers or other interested stakeholders, such as state natural gas utility regulatory agencies, may challenge the rates
or the terms and conditions of service applicable to our natural gas or crude oil pipeline tariffs, unless they have entered into
agreements not to challenge such tariffs. The FERC has authority to investigate our rates and terms and conditions of service
pursuant to NGA Section 5 for natural gas pipelines and the ICA for common carrier oil pipelines. Our crude oil contract
shippers have generally agreed not to complain or protest rates unless they are in conflict with their contracts. The FERC
generally does not regulate crude oil transportation contracts, but contract rates must be filed with the FERC and tariff rules and
regulations generally apply to contract shippers.
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On our interstate crude oil pipeline systems, the Pony Express System and the PRE Pipeline, shippers may generally
challenge new or existing rates at any time unless they have contractually agreed not to. Currently, shippers party to a TDA for
the Pony Express System are generally limited from protesting certain rates on the Pony Express System, but this limitation
will not apply to such shipper upon expiration of their TDA. As a result of settlement or by order of the FERC following
hearing, its rates may be reduced. If a shipper files a lawful complaint, and if the complaint is not resolved with that shipper, to
the extent the FERC determines after hearing that we have collected payment on rates that were not previously just and
reasonable, we may be required to pay reparations to that shipper for up to two years prior to the date on which a complaint was
filed. Regardless of the prospective just and reasonable rate, reparations may not be required below the last rates determined by
the FERC to be just and reasonable. In other words, crude oil pipelines are not required to make reparations that refund
revenues collected pursuant to rates previously determined to be just and reasonable.
The FERC has historically permitted regulated interstate crude oil and natural gas pipelines to include an income tax
allowance in their cost of service used to calculate cost-based transportation rates. The allowance is intended to reflect the
actual or potential tax liability attributable to the regulated entity’s operating income, regardless of the form of ownership. On
July 1, 2016, in United Airlines, Inc. v FERC, the United States Court of Appeals for the D.C. Circuit vacated a pair of FERC
orders to the extent they permitted an interstate refined petroleum products pipeline owned by a Master Limited Partnership
("MLP") to include an income tax allowance in its cost-of-service rates. The D.C. Circuit held that the FERC had failed to
demonstrate that the inclusion of both an income tax allowance in the pipeline’s rates and a return on equity determined using a
discounted cash flow methodology would not lead to a double-recovery of income tax costs for pipelines organized as an MLP.
Following the D.C. Circuit’s decision, the FERC issued its Revised Policy Statement on Treatment of Income Taxes in
Docket No. PL17-1-000 on March 15, 2018 which eliminates the recovery of an income tax allowance by MLP crude oil and
natural gas pipelines in cost-of-service-based rates. The FERC directed MLP crude oil pipelines to reflect the elimination of the
income tax allowance in their Form No. 6, page 700 reporting and stated that it will incorporate the effects of this Revised
Policy on industry-wide crude oil pipeline costs in the 2020 five-year review of the crude oil pipeline index level. The
Commission also stated that it would address income tax allowances for other "pass-through" entities that are not MLPs in
future proceedings.
While we are not an MLP, our ownership of our FERC regulated pipelines is held through our ownership in Tallgrass
Equity which is a "pass-through" entity. The FERC could determine to apply the elimination of the income tax allowance to
"pass-through" entities like Tallgrass Equity. To the extent that we charge cost-of-service based rates, those rates could be
affected by the elimination of the income tax allowance if our rates are subject to complaint or challenge raised by shippers or
by the FERC acting on its own initiative, or if we propose new cost-of-service rates or changes to our existing rates. In such
instances, it is possible that certain tariff rates could be reduced, which could adversely affect our financial position, results of
operations and ability to make quarterly cash dividends to our Class A shareholders.
On December 22, 2017, federal legislation known as the "Tax Cuts and Jobs Act" was enacted, which made various
changes to the United States tax laws, including reducing the highest marginal U.S. federal corporate income tax rate from 35%
to 21% for tax years beginning after December 31, 2017, adjusting the individual income tax brackets, and establishing limited
deductions for certain income from "pass-through" entities. In late 2018, Rockies Express and TIGT each submitted one-time
informational filings 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. The FERC has indicated that it will review these filings to determine whether a pipeline's rates
should be set for investigation under Section 5 of the Natural Gas Act or instead no action should be taken on the filing. The
filings of Rockies Express and TIGT are pending before the FERC. If the FERC requires us to establish new tariff rates that
reflect changes resulting from the Tax Cuts and Jobs Act, it is possible that certain tariff rates could be reduced, which could
adversely affect our financial position, results of operations and ability to make quarterly cash dividends to our Class A
shareholders.
Successful challenges to rates charged on our natural gas and crude oil pipeline systems, or to the terms and conditions of
service on those systems, could have a material adverse effect on our business, results of operations, financial condition and
ability to make quarterly cash dividends to our Class A shareholders.
We are subject to numerous hazards and operational risks.
Our operations are subject to all the risks and hazards typically associated with transportation, storage, terminalling,
processing, gathering and disposing of hydrocarbons and water. These operating risks include, but are not limited to:
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damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes,
floods, fires or other adverse weather conditions and other natural disasters and acts of terrorism;
inadvertent damage from construction, vehicles, farm and utility equipment;
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uncontrolled releases of crude oil, natural gas and other hydrocarbons or hazardous materials, including water from
hydraulic fracturing;
leaks, migrations or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;
outages at our facilities;
ruptures, fires, leaks and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and
suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of
property and equipment and pollution or other environmental damage. The location of our assets, including certain segments of
our pipeline systems in or near populated areas, including residential areas, commercial business centers, industrial sites and
other public gathering areas could increase the level of damages resulting from these risks. Despite the precautions we take,
events could cause considerable harm to people or property, could result in loss of service available to customers, and could
have a material adverse effect on our financial condition and results of operations and ability to make quarterly cash dividends
to Class A shareholders.
For example, 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.
However, 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 and the total cost of remediation was approximately $6.1 million prior to any insurance recoveries. As an
additional example, approximately 10,000 bbls of crude oil were released at the Sterling Terminal in January 2017 as a result of
a defective roof drain system on a storage tank. While the release was restricted to the containment area designed for such
purpose and approximately 9,000 bbls were ultimately recovered, the total cost to remediate the release was approximately
$600,000.
In addition, maintenance, repair and remediation activities could result in service interruptions on segments of our systems
or alter the operational profile of our systems. Any such service interruption or alteration could limit our ability to satisfy
customer requirements, could obligate us to provide reservation charge credits to customers for constrained capacity, or could
allow existing customers to be solicited by other companies for potential new projects that would compete directly with our
services.
We could be required by regulatory authorities to test or undertake modifications to our systems, operations or both that
could result in a material adverse impact on our business, financial condition and results of operations. Such actions, including
those required by PHMSA, could materially and adversely impact our ability to meet contractual obligations and retain
customers, with a resulting material adverse impact on our business and results of operations, and could also limit or prevent
our ability to make quarterly cash dividends to our Class A shareholders. Some or all of our costs arising from these operational
risks may not be recoverable under insurance, contractual indemnification or increases in rates charged to our customers.
Our business could be negatively impacted by security threats, including cyber security threats, and related disruptions.
We rely on our information technology infrastructure to process, transmit and store electronic information, including
information we use to safely operate our assets. The U.S. government has issued public warnings that indicate that energy
assets might be specific targets of cyber security threats. We may face cyber security and other security threats to our
information technology infrastructure, which could include threats to our operational and safety systems that operate our
pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure,
including coordinated attacks from hackers, whether state-sponsored groups, "hacktivists," or private individuals. The age,
operating systems or condition of our current information technology infrastructure and software assets and our ability to
maintain and upgrade such assets could affect our ability to resist cyber security threats. We could also face attempts to gain
access to information related to our assets through unauthorized access by targeting acts of deception against individuals with
legitimate access to physical locations or information, otherwise known as "social engineering."
Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to
perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions,
could result in damage to our assets, service interruptions, safety incidents, damage to the environment, potential liability or the
loss of contracts, and have a material adverse effect on our operations, financial position, results of operations and prospects.
Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or
enhance our protective and detective measures or to investigate and remediate any vulnerability to cyber incidents.
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If we are unable to protect our information and telecommunication systems against disruptions or failures, our
operations could be disrupted.
We rely extensively on computer systems to process transactions, maintain information and manage our business.
Disruptions in the availability of our computer systems could impact our ability to service our customers and adversely affect
our sales and results of operations. We are dependent on internal and third-party information technology networks and systems,
including the Internet, wired, and wireless communications, to process, transmit and store electronic information. Our computer
systems are subject to damage or interruption due to system replacements, implementations and conversions, power outages,
computer or telecommunication failures, computer viruses, security breaches, catastrophic events such as fires, tornadoes,
snowstorms and floods and usage errors by our employees, consultants and contractors. If our computer systems are damaged
or cease to function properly, we may have to make a significant investment to fix or replace them, and we may have
interruptions in our ability to service our customers. Although we attempt to reduce these risks by using redundancy for certain
critical systems, this disruption caused by the unavailability of our computer systems could nevertheless significantly disrupt
our operations or may result in financial damage or loss due to, among other things, lost or misappropriated information.
Violations of data protection laws may carry fines and expose us to criminal sanctions and civil suits.
We are subject to data protection laws. Complying with varying jurisdictional requirements could increase the costs and
complexity of compliance, and violations of applicable data protection laws could result in significant penalties. Non-
compliance with data protection laws could expose us to regulatory investigations, which could result in fines and penalties. In
addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations.
We could also be subject to litigation from persons or corporations allegedly affected by data protection violations. Any
violation of these laws or harm to our reputation could have a material adverse effect on our business, financial condition,
results of operations and prospects.
Our insurance coverage may not be adequate.
We are not insured or fully insured against all risks that could affect our business, including losses from environmental
accidents or cyber security threats. For example, we do not maintain business interruption insurance in the type and amount to
cover all possible losses. In addition, we do not carry insurance for certain environmental exposures, including but not limited
to potential environmental fines and penalties, certain business interruptions, named windstorm or hurricane exposures and, in
limited circumstances, certain political risk exposures. Further, in the event there is a total or partial loss of one or more of our
insured assets, any insurance proceeds that we may receive in respect thereof may be insufficient to effect a restoration of such
asset to the condition that existed prior to such loss. In addition, we are either not insured or not fully insured with respect to the
legal proceedings described in Note 19 – Legal and Environmental Matters and may, depending upon the circumstances, need
to pay self-insured retention amounts prior to having losses covered by the insurance providers. The occurrence of any
operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results
of operations and cash flows.
Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates, and
we have elected and may elect in the future to self-insure a portion of our risks of loss. As a result of market conditions,
premiums and deductibles for certain types of insurance policies may substantially increase, and in some instances, certain
types of insurance could become unavailable or available only for reduced amounts of coverage. Any insurance coverage we do
obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses.
Our pipeline integrity program may impose significant costs and liabilities on us, while increased regulatory
requirements relating to the integrity of our pipeline systems may require us to make additional capital and operating
expenditures to comply with such requirements.
We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal requirements
set by PHMSA for owners and operators of pipelines in the areas of pipeline design, construction, and testing, the qualification
of personnel and the development of operations and emergency response plans. The rules require pipeline operators to develop
integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments
located in what the rules refer to as HCAs.
Our pipeline operations are subject to pipeline safety regulations administered by PHMSA. These regulations, among other
things, include requirements to monitor and maintain the integrity of our pipeline systems and determine the pressures at which
our pipeline systems can operate. The Pipeline Safety Act of 2011, enacted January 3, 2012, amends the Pipeline Safety
Improvement Act of 2002 in a number of significant ways, including:
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reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing
additional safety requirements for newly constructed pipelines;
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requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote-
controlled shutoff valves on new or rebuilt pipeline facilities;
requiring operators of pipelines to verify MAOP and report exceedances within five days; and
requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and
existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those
requirements to areas outside of HCAs.
In August 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline
Safety Act of 2011, including increasing maximum civil penalties from $0.1 million to $0.2 million per violation per day of
violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing
PHMSA's enforcement process. In November 2018, PHMSA issued a final rule that increased the per-day violation penalty
from $209,002 to $213,268 and the maximum penalty for a related series of violations from $2,090,022 to $2,132,679, effective
November 27, 2018. On January 13, 2017, PHMSA finalized new hazardous liquid pipeline safety regulations extending certain
regulatory reporting requirements to all hazardous liquid gathering (including oil) pipelines. The final rule would have required
additional event-driven and periodic inspections, required the use of leak detection systems on all hazardous liquid pipelines,
modified repair criteria, and required certain pipelines to eventually accommodate in-line inspection tools. However, on
January 24, 2017, this rule was withdrawn for further review by the Trump Administration and was never published in the
Federal Register. In addition, on April 8, 2016, PHMSA published a notice of proposed rule-making, or NPRM, addressing
natural gas transmission and gathering lines. The proposed rule would include changes to existing integrity management
requirements and would expand assessment and repair requirements to pipelines in MCAs, along with other changes. Further,
this NPRM would build on the requirements in an Advisory Bulletin PHMSA issued in May 2012, which advised pipeline
operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction,
inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must
be traceable, verifiable and complete. Comments on the NPRM were due on July 7, 2016; further action is pending. We are still
monitoring and evaluating the effects of these proposed and recently finalized requirements on our operations.
The PIPES Act, enacted on June 22, 2016, reauthorized PHMSA's oil and gas pipeline programs through 2019 and
provided for the following new mandates, among others:
• Empowers PHMSA to issue emergency orders to individual operators, groups of operators, or the industry upon a
written finding that an unsafe condition or practice constitutes or is causing an imminent hazard;
• Requires PHMSA, in consultation with other federal agencies, to issue minimum safety standards for underground
natural gas storage facilities within two years;
• Requires PHMSA to conduct post-inspection briefings outlining any concerns within 30 days and providing written
preliminary findings within 90 days to the extent practicable;
• Requires liquid pipeline operators to provide safety data sheets on spilled product to the designated federal on-scene
coordinator and appropriate state and local emergency responders within 6 hours of telephonic or electronic notice of
an accident to the National Response Center; and
• Requires PHMSA to publish updates on its website every 90 days on the status of an outstanding final rule required by
a statutory mandate.
On December 14, 2016, PHMSA issued an IFR that addresses safety issues related to downhole facilities, including well
integrity, well bore tubing and casing at underground natural gas storage facilities. The IFR incorporates by reference two of the
American Petroleum Institute's Recommended Practice standards and mandates certain reporting requirements for operators of
underground natural gas storage facilities. Operators of natural gas storage facilities were given one year from January 18, 2017,
the effective date of the IFR, to implement this first set of PHMSA regulations governing underground storage fields. PHMSA
determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had
previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year
after PHMSA issues a final rule.
In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements
for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population
growth or building construction near the pipeline.
The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of
in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe
determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs, such as the
MCAs proposed by the April 2016 NPRM, can have a significant impact on the costs to perform integrity testing and repairs.
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For example, starting in 2014, Trailblazer's operating capacity was decreased as a result of smart tool surveys that
identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer
incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of
pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at
existing subscription levels or had a material adverse financial impact on us. However, Trailblazer continued performing
remediation to increase and maximize its operating capacity over the long-term and spent approximately $21 million during
2018 for this pipe replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable
operating capacity. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery
through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
Additionally, in connection with certain crack tool runs on the Pony Express System completed in 2015, 2016 and 2017,
Pony Express completed approximately $18 million of remediation for anomalies identified on the Pony Express System
associated with portions of the pipeline converted from natural gas to crude oil service. Remediation work was substantially
complete as of March 31, 2018.
There can be no assurance as to the amount or timing of future expenditures required to remediate or resolve these issues,
and actual future expenditures may be different from the amounts we currently anticipate. These integrity issues could have a
material adverse effect on our business, financial position, results of operations and prospects.
We will continue pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines
as required by the U.S. Department of Transportation regulations. The results of these tests could cause us to incur potentially
material unanticipated capital and operating expenditures for repairs or upgrades.
Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of
existing laws and regulations could significantly increase the amount of these expenditures. For example, PHMSA issued an
Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the MAOP for each
section of their pipeline and that the records must be traceable, verifiable and complete. Locating such records and, in the
absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or
replacing facilities to meet the demands of verifiable pressures, could significantly increase costs. TIGT continues to investigate
and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for MAOP. We are currently
undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally,
failure to locate such records or verify maximum pressures could require us to operate at reduced pressures, which would
reduce available capacity on our natural gas pipeline systems. These specific requirements do not currently apply to crude oil
pipelines, but proposed regulations implementing the Pipeline Safety Act of 2011 and future regulations implementing the
PIPES Act likely will expand the scope of regulation applicable to crude oil pipelines. There can be no assurance as to the
amount or timing of future expenditures required to comply with pipeline integrity regulation, and actual future expenditures
may be different from the amounts we currently anticipate. In addition, we may be subject to enforcement actions and penalties
for failure to comply with pipeline regulations. Revised or additional regulations that result in increased compliance costs or
additional operating restrictions could have a material adverse effect on our business, financial position, results of operations
and prospects. In addition, we may be subject to enforcement actions and penalties for failure to comply with pipeline
regulations.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which
may expose us to significant costs, liabilities and expenditures that could exceed our current expectations.
Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent
in our crude oil transportation, storage, gathering and terminalling, natural gas transportation, storage, gathering and processing,
NGL transportation and water business services, and as a result, we may be required to make substantial expenditures that
could exceed current expectations. Our operations are subject to extensive federal, state, and local laws and regulations
governing health and safety aspects of our operations, environmental protection, including the discharge of materials into the
environment, and the security of chemical and industrial facilities. These laws include, but are not limited to, the following:
• CAA and analogous state and local laws, which impose obligations related to air emissions and which the EPA has
relied upon as authority for adopting climate change regulatory initiatives;
• CWA and analogous state and local laws, which regulate discharge of pollutants or fill material from our facilities to
state and federal waters, including wetlands and which require compliance with state water quality standards;
• CERCLA and analogous state and local laws, which regulate the cleanup of hazardous substances that may have been
released at properties currently or previously owned or operated by us or locations to which we have sent wastes for
disposal;
• RCRA and analogous state and local laws, which impose requirements for the handling and discharge of hazardous
and nonhazardous solid waste from our facilities;
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• The SDWA, which ensures the quality of the nation's public drinking water through adoption of drinking water
standards and controls the waste fluids from disposal wells into below-ground formations;
• OSHA and analogous state and local laws, which establish workplace standards for the protection of the health and
safety of employees, including the implementation of hazard communications programs designed to inform employees
about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control
measures;
• NEPA and analogous state and local laws, which require federal agencies to evaluate major agency actions having the
potential to significantly impact the environment and which may require the preparation of Environmental
Assessments and more detailed Environmental Impact Statements that may be made available for public review and
comment;
• The Migratory Bird Treaty Act, or MBTA, and analogous state and local laws, which implement various treaties and
conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to
which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring
the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
• ESA and analogous state and local laws, which seek to ensure that activities do not jeopardize endangered or
threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;
• Bald and Golden Eagle Protection Act, or BGEPA, and analogous state and local laws, which prohibit anyone, without
a permit issued by the Secretary of the Interior, from "taking" bald or golden eagles, including their parts, nests, or
eggs, and defines "take" as "pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, molest or disturb;"
• OPA and analogous state and local laws, which impose liability for discharges of oil into waters of the United States
and requires facilities which could be reasonably expected to discharge oil into waters of the United States to maintain
and implement appropriate spill contingency plans; and
• National Historic Preservation Act, or NHPA, and analogous state and local laws, which are intended to preserve and
protect historical and archeological sites.
Various governmental authorities, including but not limited to the EPA, the U.S. Department of the Interior, the U.S.
Department of Homeland Security, and analogous federal, state and local agencies have the power to enforce compliance with
these and other similar laws and regulations and the permits and related plans issued under them, oftentimes requiring difficult
and costly actions. Failure to comply with these and other similar laws, regulations, permits, plans and agreements may result in
the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter
conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and
delays in granting permits.
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be
material, due to our handling of the products we transport, process, treat, dispose, gather or store, air emissions related to our
operations, historical industry operations, and waste disposal practices, such as the prior use of flow meters and manometers
containing mercury. These activities are subject to stringent and complex federal, state and local laws and regulations governing
environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and
natural and cultural resources. These laws and regulations can restrict or impact our business activities in many ways, such as
restricting the way we handle or dispose of wastes or requiring remedial action to mitigate pollution conditions that may be
caused by our operations or that are attributable to former operators. Joint and several, strict liability may be incurred without
regard to fault under certain environmental laws and regulations, including but not limited to CERCLA, RCRA and analogous
state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with oil,
natural gas and wastes on, under, or from our properties and facilities, many of which have been used for midstream activities
for a number of years, oftentimes by third parties not under our control. We are generally responsible for all liabilities
associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the
liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could
acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses,
which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into
compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those
facilities, which might cause us to incur losses. We are currently conducting remediation at several sites to address
contamination. For these ongoing environmental remediation projects, we spent approximately $568,000 in 2017,
approximately $362,000 in 2018 and we have budgeted approximately $1.1 million for 2019.
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Private parties, including but not limited to the owners of properties through which our pipelines pass and facilities where
our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to
seek damages for non-compliance with environmental laws, regulations and permits issued thereunder, or for personal injury or
property damage arising from our operations. Some sites at which we operate are located near current or former third-party
hydrocarbon storage, processing, operations or other facilities, and there is a risk that contamination has migrated from those
sites to ours that could result in remedial action. In addition, increasingly strict laws, regulations and enforcement policies could
materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance does not
cover all environmental risks and costs and may not provide sufficient coverage if an environmental claim is made against us.
In June 2016, the EPA extended its National Enforcement Initiatives, enforcement priorities list, including an initiative
related to Energy Extraction Activities, for 2017 through 2019, and the EPA is retaining the Energy Extraction Activities
initiative for an additional three years, effective October 2016. The EPA has clarified that it will focus on significant public
health and environmental problems: exposure to significant releases of volatile organic compounds, reducing non-attainment,
and reducing water quality impairment. We cannot predict what the results of the current initiative or any future initiative will
be, or whether federal, state or local laws or regulations will be enacted in this area. If new regulations are imposed related to
oil and gas extraction, the volumes of products, including hydrocarbons and water, that we transport, store, gather, dispose and/
or process could decline and our results of operations could be materially and adversely affected.
Our business may be materially and adversely affected by changed regulations and increased costs due to stricter pollution
control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits or plans
developed thereunder. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory
approvals for our operations, or may have to implement contingencies or conditions in order to obtain such approvals. If there
is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the
operation, maintenance or construction of our facilities could be prevented or become subject to additional costs, resulting in
potentially material adverse consequences to our business, financial condition, results of operations and cash flows. For
instance, on November 25, 2014, the Wyoming Department of Environmental Quality issued a Notice of Violation for
violations of Part 60 Subpart OOOO related to the Casper Gas Plant Depropanizer project. 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 the CAA's NSPS Subpart OOOO for the
entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and
initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing. Costs associated with
penalties and to comply with the terms of any consent decree or settlement, as well as with Subpart OOOO, could be material.
We are also generally responsible for all liabilities associated with the environmental condition of our facilities and assets,
whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection
with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental
liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be
required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut
down, divest or alter the operation of those facilities, which might cause us to incur losses. As an example, in August 2011, the
EPA and the Wyoming Department of Environmental Quality conducted an inspection of the Leak Detection and Repair
Program, or LDAR, at the Casper 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 CAA. 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. In July 2014, the EPA provided
TMID with a draft Consent Decree that has been the basis for subsequent settlement negotiations. Subsequently, the EPA
indicated that it intends to join TIGT as a defendant in this matter based on TIGT's ownership of the compressor station located
adjacent to the Casper Gas Plant in order to address alleged LDAR issues at the compressor station. Settlement negotiations are
continuing between the parties. We are not currently able to estimate the costs that may be associated with a settlement or other
resolution of this matter, which could be material.
We have agreed to a number of conditions in our environmental permits and associated plans, approvals and authorizations
that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve,
among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and
private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas
where we currently operate, and would operate if our facilities are extended or expanded, or if we construct new facilities, and
we are unable to predict the effect that any such measures would have on our business, financial position, results of operations
or prospects.
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Also, on June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or Corps, issued a final rule to clarify the term
"waters of the United States" as it pertains to federal jurisdiction under the CWA. Many interested parties believe that the rule
expands federal jurisdiction under the CWA. This rule was initially challenged in federal courts at both the appellate and district
court levels. It was stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit, but based on a January 2018 U.S.
Supreme Court decision determining that only the district courts have jurisdiction to hear the challenges, the Sixth Circuit stay
was withdrawn. Some federal district courts have enjoined the rule, but the rule is currently effective in over 20 states. In
February 2018, the agencies also published a final rule adding a February 6, 2020 applicability date to the 2015 rule, but this
rule was enjoined nationwide in August 2018. In December 2018, the EPA and the U.S. Army Corp of Engineers released a
proposed rule to redefine the extent of CWA jurisdiction. If finalized, this rule would replace the 2015 rule defining "waters of
the United States" and the scope of federal jurisdiction. Although it is unclear how or whether the Corps and the EPA will
implement the 2015 rule in states in which we have operations at this time, the rule may require additional Corps or EPA
authorizations or involvement in our future operations, for instance, if we extend its pipelines into or across areas (such as
certain ditches) newly considered "waters of the United States" under the 2015 final rule.
Certain interest groups generally opposed to the development of oil, natural gas and NGLs, and hydraulic fracturing in
particular, have from time to time advanced various options for ballot initiatives aimed at significantly limiting or preventing
the development of oil, natural gas and NGLs. For example, a Colorado ballot initiative, Proposition 112, would have
substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas
development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar efforts in Colorado or
elsewhere, if passed, could restrict oil and gas development in the future which could result in a reduction in demand for our
services.
The general trend in environmental regulation is to place more restrictions and limitations on activities that may affect the
environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or
remediation, and actual future expenditures may be materially different from the amounts we currently anticipate. Revised or
additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are
not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of
operations and prospects.
Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for
us and reduced demand for our services.
The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there
has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible
means for their regulation. In addition, efforts have been made and continue to be made in the international community toward
the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States
participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. On April
22, 2016, 175 countries, including the United States, signed the Paris Agreement. The Paris Agreement will require countries to
review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction
goals, every five years beginning in 2020. However, in August of 2017, the United States informed the United Nations of its
intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is
November 2020.
Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets
of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles
and another that regulates emissions of GHGs from certain large stationary sources. The EPA also expanded its existing GHG
emissions reporting requirements to include upstream petroleum and natural gas systems that emit 25,000 metric tons or more
of CO2 equivalent per year. Some of our facilities are required to report under this rule, and operational and/or regulatory
changes could require additional facilities to comply with GHG emissions reporting requirements. Furthermore, the EPA
adopted a final rule, effective August 2, 2016, imposing more stringent controls on methane and volatile organic compounds
emissions from oil and gas development, production, and transportation operations under the New Source Performance
Standard, or NSPS, program. In October 2018, the EPA proposed a rule to reconsider and amend various requirements of the
NSPS standard. However, the rule currently remains in effect. In 2016, the EPA also finalized a rule regarding the alternative
criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could
cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting
processes and requirements across the oil and gas industry. The BLM also adopted new rules, effective January 17, 2017, to
reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. This rule
was suspended, stayed, and reinstated before the BLM issued a final rule in September 2018 that rescinds and revises many of
the requirements of the 2017 rule. The revision rule is being challenged in the U.S. District Court for the Northern District of
California but currently remains in effect. In addition, many states have already taken legal measures to reduce emissions of
GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.
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Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or
major producers of fuels, to acquire and surrender emission allowances with the number of allowances available for purchase
reduced each year until the overall GHG emission reduction goal is achieved.
The adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs
from, our equipment and operations could require us to incur additional costs to reduce emissions of GHGs associated with our
operations, could adversely affect our operations in the absence of any permits that may be required to regulate emission of
GHGs, or could adversely affect demand for the crude oil and natural gas we gather, process, or otherwise handle. For instance,
the EPA's recently finalized NSPS rules or future rules under CAA Section 111(d) could result in the direct regulation of GHGs
associated with our operations, including the operations of Rockies Express. We are not able at this time to estimate such
increased costs; however, they could be significant. While we may be able to recover some or all of such increased costs in the
rates charged by our processing facilities, such recovery of costs is uncertain and may depend on the terms of our contracts with
our customers.
If new laws or regulations that significantly restrict GHGs are adopted, such laws could also make it more difficult or
costly for our customers to operate, which could reduce our customers' production and therefore the demand for our services.
While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry,
they could be significant for us. Restrictions on GHG emissions could also reduce the volume of natural gas that our customers
produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also
generally result in additional costs, including increased capital expenditures and operating costs, for us and our customers,
which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business. In
addition, to the extent financial markets view climate change and GHG emissions as a financial risk, this could materially and
adversely impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change, or
incentives to conserve energy or use alternative energy sources, could also affect the markets for our services by making natural
gas and crude oil products less desirable than competing sources of energy. In addition, in response to concerns related to
climate change, certain investors may divest oil and gas investments. For example, officials in New York state and New York
City have announced their intent to divest the state and city pension funds' holdings in fossil fuel companies. Such divestments
could adversely impact our costs of and access to capital.
Increased regulation of hydraulic fracturing and other oil and natural gas processing operations could affect our
operations and result in reductions or delays in production by our customers, which could have a material adverse impact
on our revenues.
A sizeable portion of our customers' production comes from hydraulically fractured wells. Hydraulic fracturing is an
important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process
typically involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture
the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state's oil and gas
commission; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving
diesel under the SDWA and has released draft permitting guidance for hydraulic fracturing activities that use diesel in fracturing
fluids in those states where the EPA is the permitting authority. A number of federal agencies, including the EPA and the U.S.
Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with
hydraulic fracturing. For example, on May 19, 2014, the EPA published an advance notice of rulemaking under the Toxic
Substances Control Act, to gather information regarding the potential regulation of chemical substances and mixtures used in
oil and gas exploration and production. In May 2016, the EPA issued final rules that update new source performance standard
requirements and that will impose more stringent controls on methane and volatile organic compounds emissions from oil and
gas development and production operations, including hydraulic fracturing and other well completion activity. In October 2018,
the EPA proposed a rule to reconsider and amend various requirements of the NSPS standard. However, the rule currently
remains in effect. The EPA also issued a final rule in June 2016 that prohibits the discharge of hydraulic fracturing wastewater
from onshore unconventional oil and gas extraction facilities into publicly owned sewage treatment plants; however, facilities
that were lawfully discharging this wastewater to publicly owned sewage treatment plants on April 17, 2015 have until August
29, 2019 to comply with this rule. Also, effective June 24, 2015, the BLM adopted rules regarding well stimulation, chemical
disclosures, water management, and other requirements for hydraulic fracturing on federal and Indian lands. However, in
December 2017, the BLM published a final rule rescinding the 2015 rule. The rescission is currently subject to legal challenge.
Also, the BLM adopted new rules effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas
production activities on onshore federal and Indian leases. This rule was suspended, stayed, and reinstated before the BLM
issued a final rule in September 2018 that rescinds and revises many of the requirements of the 2017 rule. The revision rule is
being challenged in the U.S. District Court for the Northern District of California but currently remains in effect.
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Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic
fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition,
some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that
could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Local
government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling
activities in general or hydraulic fracturing activities in particular, and in some cases, may seek to ban hydraulic fracturing
entirely. Some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing,
including temporary or permanent bans, additional permit requirements, operational restrictions and chemical disclosure
obligations on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. Other governmental agencies,
including the U.S. Department of Energy and the EPA, have evaluated or are evaluating various other aspects of hydraulic
fracturing such as the potential environmental effects of hydraulic fracturing on drinking water and groundwater. On December
13, 2016, the EPA released a study of the potential adverse effects that hydraulic fracturing may have on water quality and
public health, concluding that there is scientific evidence that hydraulic fracturing activities potentially can impact drinking
water resources in the United States under some circumstances.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult
or significantly more costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions
on hydraulic fracturing could also reduce the volume of crude oil, natural gas or other hydrocarbons that our customers
produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also
generally result in additional costs, including increased capital expenditures and operating costs, for us and our customers,
which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.
Our produced water disposal operations may be subject to additional regulation and liability or claims of environmental
damages.
We operate produced water disposal wells which are regulated under the federal SDWA as Class II wells and under state
laws. State laws and regulations that govern these operations can be more stringent than the SDWA. In addition, the possibility
exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of
any remediation that may become necessary. We may also incur material environmental costs and liabilities. Furthermore, our
insurance may not provide sufficient coverage in the event an environmental claim is made against us. In addition, although the
disposal wells have received certain governmental regulatory licenses, permits or approvals, this does not shield us from
potential claims from third parties claiming contamination of their water supply or other environmental damages. Remediation
of environmental contamination or damages can be extremely costly and such costs, if we are found liable, may have a material
adverse effect on our business, financial condition and results of operations.
Produced water injection well operations and hydraulic fracturing may cause induced seismicity.
State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing related
activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced
seismicity. In a few instances, operators of produced water injection wells in the vicinity of seismic events have been ordered to
reduce produced water injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado
and Texas, have modified their regulations to account for induced seismicity. Regulatory agencies at all levels are continuing to
study the possible linkage between oil and gas activity and induced seismicity. In 2015, the United States Geological Study
identified eight states, including Colorado, Oklahoma and Texas, with areas of increased rates of induced seismicity that could
be attributed to fluid injection or oil and gas extraction. The USGS also produced a one-year 2017 induced seismicity model
that forecast an elevated hazard from induced seismicity in Oklahoma compared to the hazard calculated for seismicity before
2009. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that produced water disposal well
operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste
disposal. The Oklahoma Corporation Commission, or OCC, has adopted a plan calling for mandatory reductions in oil and gas
wastewater disposal well volumes, the implementation of which has involved reductions of injection or shut-ins of disposal
wells. The OCC has also released guidance to operators in the SCOOP and STACK areas for management of certain seismic
activity that may be related to hydraulic fracturing activities. These developments could result in additional regulation and
restrictions on the use of produced water injection wells and hydraulic fracturing. Such regulations and restrictions could have a
material adverse effect on our business, financial condition and results of operations.
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We are exposed to costs associated with lost and unaccounted for volumes.
A certain amount of natural gas and crude oil may be lost or unaccounted for in normal operations in connection with their
transportation across a pipeline system. Under our tariffs and contractual arrangements with our customers we are entitled to
retain a specified volume of natural gas and crude oil in order to compensate us for such lost and unaccounted for volumes, as
well as the natural gas used to run our natural gas compressor stations, which we refer to collectively as fuel usage. Our
pipeline tariffs currently contain fuel usage true-up mechanisms. The use of fuel (natural gas, electric and lost and unaccounted
for gas) trackers on the Rockies Express Pipeline, the TIGT System, and the Trailblazer Pipeline, while minimizing risk over
time, nevertheless leaves the systems exposed to the possibility of under- or over-collections on an annual basis. The level of
lost and unaccounted for volumes, and natural gas fuel usage, on our pipeline systems may exceed the natural gas and crude oil
volumes retained from our customers as compensation for our lost and unaccounted for volumes, and fuel usage, pursuant to
our tariffs and contractual agreements, and it may be necessary to purchase natural gas or crude oil in the market to make up for
the difference, which exposes us to commodity price risk. Future exposure to the volatility of natural gas and crude oil prices as
a result of lost and unaccounted for volume imbalances could have a material adverse effect on our business, financial
condition, results of operations and ability to make quarterly cash dividends to our Class A shareholders.
Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our
natural gas storage business.
Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for our storage services. The
natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which
impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis,
natural gas is typically injected into storage between April and October when natural gas prices are generally lower and
withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the
market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels
previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or
otherwise, then demand for our storage services and the prices that we will be able to charge for those services may decline.
In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring
base gas and likely place upward pressure on the costs of associated storage expansion activities. Alternatively, an extended
period of low seasonal volatility in natural gas prices could adversely impact storage values for some period of time until
market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition,
results of operations and ability to make quarterly cash dividends to our Class A shareholders.
Certain portions of our transportation, storage and processing facilities have been in service for several decades. There
could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our
facilities that could have a material adverse effect on our business and results of operations.
Significant portions of our transportation, storage and processing systems have been in service for several decades. The age
and condition of our facilities could result in increased maintenance or repair expenditures, and any downtime associated with
increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and
repair expenditures or loss of revenue due to the age or condition of our facilities could adversely affect our business and results
of operations and our ability to make quarterly cash dividends to our Class A shareholders.
The TEP revolving credit facility and the indentures governing the TEP senior notes contain certain restrictions which
could adversely affect our business, financial condition, results of operations and ability to make quarterly cash dividends to
our Class A shareholders.
We are dependent upon certain earnings and cash flow generated by our operations in order to meet our debt service
obligations. The TEP revolving credit facility, the indenture governing its 4.75% senior notes due 2023 (the "2023 Notes") the
indenture governing its 5.50% senior notes due 2024 (the "2024 Notes"), and the indenture governing its 5.50% senior notes
due 2028 (the "2028 Notes") contain, and any future financing agreements may contain, operating and financial restrictions and
covenants that could restrict our ability to finance future operations or capital needs, or to expand or pursue our business
activities, which may, in turn, limit our ability to make quarterly cash dividends. For example, the TEP revolving credit facility
limits TEP's ability and the ability of its restricted subsidiaries to, among other things:
•
•
incur or guarantee additional indebtedness;
redeem or repurchase units or pay distributions under certain circumstances;
• make certain investments and acquisitions;
•
•
incur certain liens or permit them to exist;
enter into certain types of transactions with affiliates;
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• merge or consolidate with another company; and
•
transfer, sell or otherwise dispose of assets.
The TEP revolving credit facility also contains covenants requiring TEP to maintain certain financial ratios. Our ability to
meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that TEP will meet
those ratios and tests. Further, TEP's obligations under the revolving credit facility are (i) guaranteed by TEP and each of its
existing and subsequently acquired or organized direct or indirect wholly-owned domestic subsidiaries, subject to its ability to
designate certain subsidiaries as "Unrestricted Subsidiaries," and (ii) secured by a first priority lien on substantially all of the
present and after acquired property owned by TEP and each guarantor (other than real property interests related to its pipelines).
Similarly, the indenture governing the 2024 Notes contains covenants that, among other things, limit TEP's ability and the
ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create
liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated
securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from our restricted subsidiaries;
(vi) consolidate with or merge with or into, or sell substantially all its properties to, another person; (vii) sell or otherwise
dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates.
In addition, the indentures governing the 2023 Notes and the 2028 Notes contain covenants that, among other things, limit
TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback
transactions; and (iii) consolidate with or merge with or into, or sell substantially all of its properties to, another person.
The provisions of the TEP revolving credit facility and the indentures governing its senior notes may affect our ability to
obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes
in business conditions. In addition, a failure to comply with the provisions of the TEP revolving credit facility or the indentures
governing its senior notes, including a failure to meet any of the required financial ratios and tests, could result in a default or
an event of default that could enable its lenders or the holders of the senior notes to declare the outstanding principal of that
indebtedness, together with accrued and unpaid interest, to be immediately due and payable, and in the case of the TEP
revolving credit facility, would prohibit TEP's ability to make distributions. If the payment of the indebtedness under the TEP
revolving credit facility is accelerated and we are unable to repay the indebtedness in full, the lenders could foreclose on the
assets pledged by TEP and the guarantors under the TEP revolving credit facility. In that case, these assets may be insufficient
to repay such indebtedness in full, and our Class A shareholders could experience a partial or total loss of their investment.
Our future indebtedness levels may limit our flexibility to obtain financing and to pursue other business opportunities.
Our level of indebtedness could have important consequences to us, including the following:
•
•
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and dividends to Class A shareholders will be reduced
by that portion of our cash flow required to make interest payments on our indebtedness;
• we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
•
our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our indebtedness depends upon, among other things, our future financial and operating performance,
which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which
are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced
to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital
expenditures, selling assets or seeking additional equity capital. Taking any of these actions is likely to reduce the value of an
investment in us. Plus, we may not be able to effect any of these actions on satisfactory terms or at all.
Increases in interest rates could adversely impact our Class A share price, our ability to issue equity or incur
indebtedness for acquisitions or other purposes and our ability to make quarterly cash dividends at our intended levels.
The interest rate on borrowings under the TEP revolving credit facility float based upon one or more of the prime rate, the
U.S. federal funds rate or LIBOR. As a result, those borrowings, as well as borrowings under possible future credit facilities or
debt offerings, could be higher than current levels, causing our financing costs to increase accordingly. We do not currently
hedge the interest rate risk on borrowings under the TEP revolving credit facility.
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As with other yield-oriented securities, our Class A share price may be impacted by the level of our cash dividend and
implied dividend yield. The dividend yield is often used by investors to compare and rank yield-oriented securities for
investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield
requirements of investors who invest in our Class A shares, and a rising interest rate environment could have an adverse impact
on our Class A share price, our ability to issue equity or incur indebtedness for acquisitions or other purposes and our ability to
maintain or increase quarterly cash dividends on our Class A shares.
Rockies Express has a substantial amount of indebtedness and Rockies Express may not be able to generate a sufficient
amount of cash flow to meet its debt service obligations.
As of January 31, 2019, Rockies Express had $1.5 billion of senior notes outstanding, of which $750 million will mature
on April 15, 2020, $250 million will mature in 2038 and $500 million will mature in 2040. In addition, Rockies Express has
$525 million of outstanding indebtedness pursuant to a term loan facility that provides for a one-time principal payment due on
the January 7, 2020 maturity date. Further, Rockies Express has a revolving credit facility with $150 million of borrowing
capacity that matures on January 31, 2020.
The substantial indebtedness held by Rockies Express could have important consequences. For example, it could:
• make it more difficult for Rockies Express to satisfy its obligations with respect to its indebtedness;
•
•
•
•
•
•
increase the vulnerability of Rockies Express to general adverse economic and industry conditions;
limit the ability of Rockies Express to obtain additional financing for future working capital, capital expenditures and
other general business purposes;
require Rockies Express to dedicate a substantial portion of its cash flow from operations to payments on its
indebtedness, thereby reducing the availability of cash flow for operations and other purposes;
limit its flexibility in planning for, or reacting to, changes in its business and the industry in which Rockies Express
operates;
place Rockies Express at a competitive disadvantage compared to its competitors that have less indebtedness; and
have a material adverse effect if Rockies Express fails to comply with the covenants in the indenture relating to its
notes or in the instruments governing its other indebtedness.
The terms of the indentures governing the existing Rockies Express notes do not restrict the amount of additional
unsecured indebtedness Rockies Express may incur, and the agreements governing its term loan credit facility and revolving
credit facility permit additional unsecured borrowings. If new indebtedness is added to the current indebtedness levels, these
related risks could increase.
Rockies Express' ability to make scheduled payments or to refinance its obligations with respect to its indebtedness will
depend on its financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial,
business, and other factors beyond its control. In addition, a significant amount of Rockies Express' revenue in 2018 was
generated by long-term contracts that expire in 2019 and Rockies Express may not be able to renew or replace expiring
contracts at favorable rates or on a long-term basis, which may result in lower cash flows in periods subsequent to 2019. We
cannot assure you that Rockies Express' operating performance, cash flow and capital resources will be sufficient for payment
of its indebtedness in the future. In the event that Rockies Express is required to dispose of material assets or restructure its
indebtedness to meet its debt service and other obligations, we cannot assure you as to the terms of any such transaction or how
soon any such transaction could be completed.
If Rockies Express' cash flow and capital resources are insufficient to fund its debt service obligations, it may be forced to
sell material assets, obtain additional capital, including through capital contributions from its members, or restructure its
indebtedness. The payment of additional capital contributions by us to Rockies Express to fund such obligations would reduce
the amount of cash available to make dividends to our Class A shareholders.
Rockies Express' term loan credit facility and revolving credit facility contain certain restrictions which could limit its
financial flexibility and increase its financing costs.
Rockies Express' term loan credit facility and revolving credit facility contain restrictive covenants that may prevent it
from engaging in various transactions that Rockies Express deems beneficial and that may be beneficial to Rockies Express.
The term loan credit facility and the revolving credit facility generally require Rockies Express to comply with various
affirmative and negative covenants, including a limit on the leverage ratio (as defined in each credit agreement) of Rockies
Express and restrictions on:
•
incurring secured indebtedness;
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•
•
•
entering into mergers, consolidations and sales of assets;
granting liens;
entering into transactions with affiliates; and
• making restricted payments.
Instruments governing any future indebtedness at Rockies Express may contain similar or more restrictive provisions.
Rockies Express' ability to respond to changes in business and economic conditions and to obtain additional financing, if
needed, may be restricted.
We do not own most of the land on which our assets are located, which could disrupt our operations and subject us to
increased costs.
We do not own in fee but rather have leases, easements, rights-of-way, permits, surface use agreements, and licenses for
most of the land on which our assets are located, and we are therefore subject to the possibility of more onerous terms and/or
increased costs to retain necessary land use if we do not have valid interests in the land, if such interests in the land lapse or
terminate or if our facilities are not properly located within the boundaries of such interests in the land. For example, the West
Frenchie Draw treating facility is located on land leased from the Wyoming Board of Land Commissioners pursuant to a
contract that can be terminated at any time. Although many of these rights are perpetual in nature, we occasionally obtain the
right to construct and operate pipelines on other owners' land for a specific period of time. If we were to be unsuccessful in
renegotiating our leases, easements, rights-of-way, permits, surface use agreements and licenses, we might incur increased costs
to maintain our assets, which could have a material adverse effect on our business, results of operations, financial condition and
ability to make quarterly cash dividends to our Class A shareholders. In addition, we are subject to the possibility of increased
costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
Some leases, easements, rights-of-way, permits, surface use agreements and licenses for our assets are shared with other
pipeline systems and other assets owned by third parties. We or owners of the other pipeline systems or assets may not have
commenced or concluded eminent domain proceedings for some rights-of-way. In some instances, lands over which leases,
easements, rights-of-way, permits, surface use agreements and licenses have been obtained are subject to prior liens which have
not been subordinated to the grants to us.
Our interstate natural gas pipeline systems have federal eminent domain authority in certain instances. To the extent federal
eminent domain authority is not available, the availability of eminent domain for future crude oil or natural gas pipeline
expansions varies from state to state, depending upon the laws of the particular state and in some states it may not be available
at all. Regardless, we must compensate landowners for the use of their property, which may include any loss of value to the
remainder of their property not being used by us, which are sometimes referred to as "severance damages." Severance damages
are often difficult to quantify and their amount can be significant. In eminent domain actions, such compensation may be
determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to
lose the right to use or occupy the property on which our crude oil or natural gas pipeline systems are located.
A shortage of skilled labor in the midstream industry could reduce labor productivity and increase costs, which could
have a material adverse effect on our business and results of operations.
The transportation, storage and terminalling of crude oil, the transportation, storage and processing of natural gas, and the
transportation, gathering, recycling and disposal of water requires skilled laborers in multiple disciplines such as equipment
operators, mechanics and engineers, among others. If we experience shortages of skilled labor in the future, our labor and
overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience
materially increased health and benefit costs for employees, our results of operations could be materially and adversely
affected.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our
financial results or prevent fraud. As a result, shareholders could lose confidence in our financial reporting, which would
harm our business and the trading price of our Class A shares.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully
as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating
results will be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful,
that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able
to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain
effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our
operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to
lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our
Class A shares.
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New technologies, including those involving recycling of produced water or the replacement of water in fracturing
fluid, may adversely affect our future results of operations and financial condition.
The produced water disposal industry is subject to the introduction of new waste treatment and disposal techniques and
services using new technologies including those involving recycling of produced water, some of which may be subject to patent
protection. As competitors and others use or develop new technologies or technologies comparable to our water business
services in the future, we may lose market share or be placed at a competitive disadvantage. For example, some companies
have successfully used propane as the fracturing fluid instead of water. Further, we may face competitive pressure to implement
or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and
personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before
we can. Additionally, we may be unable to implement new technologies or products at all, on a timely basis or at an acceptable
cost. New technology could also make it easier for our customers to vertically integrate their operations or reduce the amount of
waste produced in oil and natural gas drilling and production activities, thereby reducing or eliminating the need for third-party
disposal. Limits on our ability to effectively use or implement new technologies, including in its water business services, may
have a material adverse effect on our business, financial condition and results of operations.
Rockies Express is a joint venture and our investment could be adversely affected by our lack of sole decision-making
authority.
We do not control Rockies Express through our ownership of a 75% membership interest. Under the limited liability
company agreement of Rockies Express, as amended, substantially all matters are decided by a vote of 80% of the membership
interests, other than certain fundamental decisions that require a vote of 90% of the membership interests. As a result, all the
decisions of the Rockies Express members effectively require unanimous approval of us and the other member of Rockies
Express, Phillips 66. Thus, our investment in Rockies Express involves risks that are not present when we are able to exercise
control over an asset, including the possibility that the unaffiliated third-party member of Rockies Express might become
bankrupt, fail to fund its required capital contributions or otherwise attempt to make business decisions with respect to Rockies
Express that we do not believe are in its best interest. Moreover, under the Rockies Express limited liability company
agreement, we are required to provide certain capital contributions in order to fund expenditures contemplated by Rockies
Express' annual budget, and may be required to provide capital contributions under certain circumstances specified in the
Rockies Express limited liability company agreement if determined to be reasonably necessary by a vote of Rockies Express'
members.
As an unaffiliated third-party member of Rockies Express, Phillips 66 may have economic or other business interests or
goals that are inconsistent with our business interests or goals. The Rockies Express limited liability company agreement
expressly permits Rockies Express members to make decisions with respect to their ownership interest without taking into
account the interests of Rockies Express or any other member of Rockies Express.
Our membership interest in Rockies Express is subject to a right of first refusal, which may make it more difficult to sell
our interest in Rockies Express in the future.
Under the terms of Rockies Express' limited liability company agreement, if any member desires to transfer its membership
interest to an unaffiliated third party, each other member first has a right to purchase its proportionate share of the membership
interest being sold. If we desire to sell all or any portion of our interest in Rockies Express to an unaffiliated third-party in the
future, we will be required to first offer the sale of our membership interest to the other members, who will have 30 days to
elect to purchase their proportionate interest before any sale or transfer to a third party may be consummated. This requirement
could make it difficult for us to sell our interest in Rockies Express.
Risks Inherent in an Investment in Us
Our quarterly cash dividends to our Class A shareholders are not cumulative.
Our quarterly cash dividends to our Class A shareholders are not cumulative. Consequently, if cash dividends on our
Class A shares are not paid with respect to any fiscal quarter then our Class A shareholders will not be entitled to receive that
quarter's payments in the future.
Our partnership agreement requires that we distribute our available cash on a quarterly basis, which could limit our
ability to grow and make acquisitions.
Our partnership agreement requires us to distribute our available cash to our Class A shareholders on a quarterly basis.
Accordingly, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance
of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are
unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
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In addition, because we intend to dividend our available cash, our growth may not be as fast as that of businesses that
reinvest their available cash to expand ongoing operations. To the extent we issue additional shares in connection with any
acquisitions or expansion capital expenditures, the payment of dividends on those additional shares may increase the risk that
we will be unable to maintain or increase our per share dividend level. There are no limitations in our partnership agreement on
our ability to issue additional shares, including shares ranking senior to the Class A shares. The incurrence of additional
commercial borrowings or other indebtedness to finance our growth strategy would result in increased interest expense, which
in turn may impact the cash available for dividends to our Class A shareholders.
If we issue additional Class A shares without canceling an equivalent number of Class B shares, Tallgrass Equity incurs
additional debt, we incur debt or we or Tallgrass Equity are required to pay taxes, the payment of distributions on those
additional Class A shares or interest on that debt or payment of such taxes could increase the risk that we will be unable to
maintain or increase our cash dividend levels.
Restrictions in TEP's and Rockies Express' respective credit facilities and the indentures governing TEP's and Rockies
Express' existing senior notes could limit Tallgrass Equity's ability to make distributions to us, thereby limiting our ability to
make quarterly cash dividends to our Class A shareholders. Any credit facility we enter into in the future could pose similar
restrictions that would further limit our ability to make quarterly cash dividends.
TEP's and Rockies Express' respective credit facilities and the indentures governing TEP's and Rockies Express' existing
senior notes contain various operating and financial restrictions and covenants. Tallgrass Equity's, TEP's and Rockies Express'
respective ability to comply with these restrictions and covenants may be affected by events beyond their control, including
prevailing economic, financial and industry conditions. If TEP or Rockies Express are unable to comply with these restrictions
and covenants, any indebtedness under these credit facilities and indentures may become immediately due and payable and
TEP's and Rockies Express' respective lenders' commitment to make further loans under their revolving credit facilities may
terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.
We may enter into a credit facility in the future that would impose similar restrictions to those discussed above. In addition,
our payment of principal and interest on any future indebtedness would reduce our cash available for dividends to our Class A
shares.
For more information regarding the TEP revolving credit facility and the indentures governing TEP's existing senior notes,
please see the section above "—The TEP revolving credit facility and the indentures governing the TEP senior notes contain
certain restrictions which could adversely affect our business, financial condition, results of operations and ability to make
quarterly cash dividends to our Class A shareholders." For more information regarding Rockies Express' revolving credit
facility and the indentures governing Rockies Express' existing senior notes, please see the sections above "—Rockies Express
has a substantial amount of indebtedness and Rockies Express may not be able to generate a sufficient amount of cash flow to
meet its debt service obligations." and "—Rockies Express' term loan credit facility and revolving credit facility contain certain
restrictions which could limit its financial flexibility and increase its financing costs."
Our shareholders do not vote in the election of our general partner's directors. The Exchange Right Holders own a
sufficient number of shares to allow them to prevent the removal of our general partner.
Our shareholders have only limited voting rights on matters affecting our business and, therefore, limited ability to
influence management's decisions regarding our business. The board of directors of our general partner, including our
independent directors, is currently designated and elected by Tallgrass Energy Holdings or its designees. Our shareholders do
not have the ability to elect our general partner or the members of the board of directors of our general partner.
In addition, if our Class A shareholders are dissatisfied with the performance of our general partner, they have little ability
to remove our general partner. Our general partner may not be removed except by vote of the holders of at least 80% of our
outstanding shares, voting together as a single class. The Exchange Right Holders own all of our Class B shares, which
collectively represents 44.21% of our total outstanding Class A and Class B shares. This ownership level enables the Exchange
Right Holders to prevent our general partner's removal.
As a result of these provisions, the price at which our shares trade may be lower because of the absence or reduction of a
takeover premium in the trading price.
Our general partner may cause us to issue additional Class A shares or other equity securities, including equity
securities that are senior to our Class A shares, without your approval, which may adversely affect you.
Our general partner may cause us to issue an unlimited number of additional Class A shares, or other equity securities of
equal rank with the Class A shares, without shareholder approval. In addition, we may issue an unlimited number of shares that
are senior to our Class A shares in right of dividend, liquidation and voting. Except for Class A shares issued in connection with
the exercise by any Exchange Right Holder of its right to exchange a Class B share for a Class A share (the "Exchange Right"),
each of which will result in the cancellation of an equivalent number of Class B shares and therefore have no effect on the total
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number of outstanding shares, the issuance of additional Class A shares, or other equity securities of equal or senior rank, may
have the following effects:
•
•
•
•
each shareholder's proportionate ownership interest in us may decrease;
the amount of cash available for dividends on each Class A share may decrease;
the relative voting strength of each previously outstanding Class A share may be diminished;
the date upon which we begin paying material U.S. federal income taxes, or upon which a material portion of our
dividends constitute taxable dividend income for U.S. federal income tax purposes, could be accelerated; and
•
the market price of the Class A shares may decline.
You may not have limited liability if a court finds that shareholder action constitutes control of our business.
Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court
determined that the right or the exercise of the right by our shareholders (who hold limited partner interests despite the fact that
we use the term "shareholder" in this Annual Report) as a group to remove or replace our general partner, to approve some
amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in
the "control" of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities
of a limited partnership have not been clearly established in many jurisdictions.
Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some
circumstances, a shareholder may be liable to us for the amount of a dividend for a period of three years from the date of the
dividend.
Our partnership agreement restricts the rights of shareholders owning 20% or more of our shares.
Our shareholders' voting rights are restricted by the provision in our partnership agreement generally providing that any
shares held by a person or group that owns 20% or more of any class of shares then outstanding, other than our general partner,
the Exchange Right Holders or their respective affiliates and persons who acquired such shares with the prior approval of our
general partner's board of directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions
limiting the ability of our shareholders to call meetings or to acquire information about our operations, as well as other
provisions limiting our shareholders' ability to influence the manner or direction of our management. As a result, the price at
which our Class A shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
Future sales of our Class A shares in the public market, including sales of Class A shares by the Exchange Right
Holders after the exercise of the Exchange Right, could reduce our Class A share price, and any additional capital raised by
us through the sale of equity or convertible securities may dilute your ownership in us.
Subject to certain limitations and exceptions, the Exchange Right Holders may cause the exchange of their Tallgrass Equity
units (together with a corresponding number of Class B shares) for Class A shares (on a one-for-one basis, subject to customary
conversion rate adjustments for equity splits and reclassification and other similar transactions) and then sell those Class A
shares. For example, in November 2016 certain participating Exchange Right Holders sold 10,350,000 Class A Shares in a
secondary offering. Further, in accordance with a shareholder and registration rights agreement entered into with the Exchange
Right Holders, we have registered the resale of 125,291,659 Class A shares issuable upon exercise of the Exchange Right
pursuant to our Form S-3 (File No. 333-225382) filed with the SEC on June 1, 2018, which became effective June 13, 2018.
We may also issue additional Class A shares or convertible securities in subsequent public or private offerings. We cannot
predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that
future issuances and sales of our Class A shares, including sales of Class A shares by the Exchange Right Holders after the
exercise of the Exchange Right, will have on the market price of our Class A shares. Sales of substantial amounts of our Class A
shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely
affect prevailing market prices of our Class A shares.
Tallgrass Energy Holdings currently has sole authority to elect the board of directors of our general partner, and
following consummation of the Blackstone Acquisition, BIP will have such authority.
Tallgrass Energy Holdings currently has the ability to elect all of the members of our board of directors. In addition,
Tallgrass Energy Holdings is able to determine the outcome of nearly all matters requiring shareholder approval, including
certain mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of
directors or a change in control of our company that could deprive our shareholders of an opportunity to receive a premium for
their Class A shares as part of a sale of our company. Certain of the Exchange Right Holders currently own 100% of the voting
interests in Tallgrass Energy Holdings and EMG, Kelso and Tallgrass KC each have the right to designate two members to the
six-person board of managers of Tallgrass Energy Holdings for so long as they maintain certain ownership percentages in
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Tallgrass Energy Holdings. Following consummation of the Blackstone Acquisition, BIP will own 100% of the membership
interests in our general partner and will have the ability to elect all of the members of the board of directors of our general
partner, subject to certain contractual rights to designate directors, including those granted to our chief executive officer, Mr.
Dehaemers, to (i) designate one individual from the three specified executive officers to serve as a member of the board of
directors of our general partner until December 31, 2020, for so long as Mr. Dehaemers remains a member of the board of
directors of our general partner, and (ii) under certain circumstances, designate one individual to serve as an independent
member of the board of directors of our general partner, for so long as Mr. Dehaemers is employed as the chief executive
officer of our general partner. Prior to the Blackstone Acquisition, Tallgrass Energy Holdings continues to be able to, and
following consummation of the Blackstone Acquisition, BIP will be able to, strongly influence all matters requiring shareholder
approval, regardless of whether or not shareholders believe that the transaction is in their own best interests.
A valuation allowance on our deferred tax asset could reduce our earnings.
A significant deferred tax asset was recorded as a result of certain reorganization transactions completed in connection with
the TGE IPO. In November 2016, we completed a Secondary Offering of Class A shares, which resulted in the recognition of
an additional deferred tax asset. The aggregate deferred tax asset was $273.5 million as of December 31, 2018. GAAP requires
that a valuation allowance must be established for deferred tax assets when it is more likely than not that they will not be
realized. If we were to determine that a valuation allowance was appropriate for our deferred tax asset, we would be required to
take an immediate charge to earnings with a corresponding reduction of partners' equity and increase in balance sheet leverage
as measured by debt to total capitalization.
The NYSE does not require a limited partnership like us to comply with certain of its corporate governance
requirements.
Because we are a limited partnership, the NYSE does not require our general partner to have a majority of independent
directors on its board of directors. The NYSE also does not require our general partner to establish a compensation committee
or a nominating and corporate governance committee. Accordingly, our shareholders do not have the same protections afforded
to certain corporations that are subject to all the NYSE corporate governance requirements. In addition, as a limited partnership,
we are not required to seek shareholder approval for issuances of Class A shares including issuances in excess of 20% of
outstanding equity securities, or for issuances of equity to certain affiliates.
We may incur liability as a result of our ownership of TEP's general partner.
Under Delaware law, a general partner of a limited partnership is generally liable for the debts and liabilities of the
partnership for which it serves as general partner, subject to the terms of any indemnification agreements contained in the
partnership agreement and except to the extent the partnership's contracts are non-recourse to the general partner. As a result of
our structure, we indirectly own and control the general partner of TEP. To the extent the indemnification provisions in TEP's
partnership agreement or non-recourse provisions in our contracts are not sufficient to protect TEP GP from such liability, we
may in the future incur liabilities as a result of our indirect ownership of TEP's general partner. Please read the section entitled
"—Risks Related to Conflicts of Interest."
Risks Related to Conflicts of Interest
Our existing organizational structure and the relationships among us, our general partner, Tallgrass Energy Holdings, the
owners of Tallgrass Energy Holdings, including the Exchange Right Holders, and their affiliated entities present the potential
for conflicts of interest. Moreover, additional conflicts of interest may arise in the future among us and the entities affiliated
with any general partner or similar interests we acquire.
Conflicts of interest may arise as a result of our organizational structure and the relationships among us, our general
partner, and its direct and indirect owners, which include Tallgrass Energy Holdings, the owners of Tallgrass Energy
Holdings, including the Exchange Right Holders, and their affiliated entities prior to the Blackstone Acquisition, and BIP,
GIC SI and their affiliated entities following consummation of the Blackstone Acquisition.
Our partnership agreement defines the duties of our general partner (and, by extension, its officers and directors). Our
general partner's board of directors or its conflicts committee has authority on our behalf to resolve any conflict involving us
and they have broad latitude to consider the interests of all parties to the conflict.
Conflicts of interest may arise between us and our shareholders, on the one hand, and our general partner and its direct and
indirect owners, on the other hand, which include Tallgrass Energy Holdings and the Exchange Right Holders, and affiliated
entities prior to the Blackstone Acquisition, and BIP, GIC SI and their affiliated entities following consummation of the
Blackstone Acquisition. The resolution of these conflicts may not always be in our best interest or that of our shareholders.
53
Certain of the Exchange Right Holders own 100% of the voting interests in Tallgrass Energy Holdings and the
Exchange Right Holders control all of our Class B shares, which represents approximately 44.21% of the combined voting
power of our Class A and Class B shares.
As of February 8, 2019, certain of the Exchange Right Holders own 100% of the voting interests in Tallgrass Energy
Holdings and the Exchange Right Holders hold Class B shares representing approximately 44.21% of the combined voting
power of our Class A and Class B shares. Although each of the Exchange Right Holders are entitled to act separately in their
own respective interests with respect to their ownership interest in Tallgrass Energy Holdings and us, certain of the Exchange
Right Holders collectively have the ability to elect all the members of Tallgrass Energy Holdings' board of managers, each of
whom also serves as a member of the board of directors of our general partner. So long as any of the Exchange Right Holders
continue to own a significant amount of the voting interests in Tallgrass Energy Holdings, they will continue to be able to
control our management and affairs. Following consummation of the Blackstone Acquisition, BIP will own 100% of the
membership interests in our general partner, and will, subject to certain contractual restrictions, control approximately 44% of
the combined voting power of our Class A shares and Class B shares.
Our partnership agreement replaces our general partner's fiduciary duties to holders of our Class A shares with
contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would
otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For
example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as
opposed to in its capacity as our general partner, free of any duties to us and our shareholders other than the implied contractual
covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the shareholders
where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our
general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any
consideration to any interest of, or factors affecting, us, our affiliates or our shareholders. Examples of decisions that our
general partner may make in its individual capacity include:
•
how to allocate business opportunities among us and its affiliates;
• whether to exercise its limited call right;
• whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors
of our general partner;
•
how to exercise its voting rights with respect to the units it owns; and
• whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the
partnership agreement.
In addition, our partnership agreement provides that any construction or interpretation of our partnership agreement and
any action taken pursuant thereto or any determination, in each case, made by our general partner in good faith, shall be
conclusive and binding on all shareholders.
By purchasing shares, you agree to become bound by the provisions in the partnership agreement, including the provisions
discussed above.
Our partnership agreement restricts the remedies available to holders of our Class A shares for actions taken by our
general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to shareholders for actions taken by our
general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our
partnership agreement provides that:
• whenever our general partner, the board of directors of our general partner or any committee thereof (including the
conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities,
our general partner, the board of directors of our general partner and any committee thereof (including the conflicts
committee), as applicable, is required to make such determination, or take or decline to take such other action, in good
faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as
specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by
our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
•
our general partner will not have any liability to us or our shareholders for decisions made in its capacity as a general
partner so long as such decisions are made in good faith;
54
•
•
our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners
resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of
competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in
bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the
conduct was criminal; and
our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us
or our shareholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
approved by the conflicts committee of the board of directors of our general partner (although our general
partner is not obligated to seek such approval);
approved by the vote of a majority of the outstanding voting shares, excluding any shares owned by our
general partner and its affiliates;
determined by the board of directors of our general partner to be on terms no less favorable to us than those
generally being provided to or available from unrelated third parties; or
determined by the board of directors of our general partner to be fair and reasonable to us, taking into account
the totality of the relationships among the parties involved, including other transactions that may be
particularly favorable or advantageous to us.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our
general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of
interest is not approved by our shareholders or the conflicts committee and the board of directors of our general partner
determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies
either of the standards set forth in the last two bullets above, then it will be presumed that, in making its decision, the board of
directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership
challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such
presumption.
Our general partner's affiliates and Tallgrass Energy Holdings may compete with us.
Our partnership agreement provides that our general partner is restricted from engaging in any business activities other
than acting as our general partner and those activities incidental to its ownership of interests in us. The restrictions contained in
our general partner's limited liability company agreement are subject to a number of exceptions. For example, affiliates of our
general partner, including Tallgrass Energy Holdings, the Exchange Right Holders, and their respective affiliates, including
Kelso and EMG, are not prohibited from engaging in other businesses or activities that might be in direct competition with us.
Our general partner has a call right that may require you to sell your Class A shares at an undesirable time or price.
If at any time more than 80% of our outstanding shares (including Class A shares issuable upon the exchange of Class B
shares) are owned by our general partner, Tallgrass Energy Holdings or their respective affiliates, our general partner has the
right (which it may assign to any of its affiliates, Tallgrass Energy Holdings or us), but not the obligation, to acquire all, but not
less than all, of the remaining Class A shares held by public shareholders at a price equal to the greater of (x) the highest cash
price paid by our general partner, Tallgrass Energy Holdings, or their respective affiliates for any shares purchased within the
90 days preceding the date on which our general partner first mails notice of its election to purchase those shares and (y) the
current market price calculated in accordance with our partnership agreement as of the date three business days before the date
the notice is mailed. As a result, you may be required to sell your Class A shares at an undesirable time or price and may not
receive any return of or on your investment. You may also incur a tax liability upon a sale of your Class A shares.
Tax Risks
The tax treatment of TEP depends on it not being subject to a material amount of entity-level taxation by individual
states. If TEP becomes subject to material additional amounts of entity-level taxation for state tax purposes, it would reduce
the amount of cash available for dividends to us and increase the portion of our dividends treated as taxable dividends.
We own a 55.79% membership interest in Tallgrass Equity, which directly and indirectly owns all of the partnership
interests in TEP. Accordingly, the value of our indirect investment in TEP, as well as the anticipated after-tax economic benefit
of an investment in our Class A shares, depends largely on TEP being treated as a partnership for income tax purposes.
Several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income,
franchise and other forms of taxation. Imposition of such a tax on TEP by any state will reduce the cash available for
distributions to TEP unitholders, likely causing a substantial reduction in the value of our Class A shares.
55
We may incur substantial corporate income tax liabilities on our allocable share of TEP income.
We are classified as a corporation for U.S. federal income tax purposes and, in most states in which TEP does business, for
state income tax purposes. To the extent that TEP allocates to us net taxable income in any year, current law provides that we
will be subject to U.S. federal income tax at a rate of 21%, and to state income tax at rates that vary from state to state. The
amount of cash available for dividends to you will be reduced by the amount of any such income taxes payable by us for which
we establish reserves.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income tax laws and transactional tax laws
such as excise, sales/use, payroll, franchise and ad valorem tax laws. New tax laws and regulations and changes in existing tax
laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Further, taxing
authorities may change their application of existing taxes, so that additional entities or transactions may become subject to an
existing tax. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in
additional tax payments, as well as interest and penalties. In one such audit, Rockies Express has appealed an excise tax
assessment on the gross receipts from certain transactions issued by the Ohio Department of Taxation. If the appeal is
unsuccessful, Rockies Express may be subject to substantial additional excise taxes in the future, and imposition of such excise
taxes could reduce the cash available for dividends to our Class A shareholders.
If the IRS makes audit adjustments to TEP's income tax returns for tax years beginning after 2017, it may collect any
resulting taxes (including any applicable penalties and interest) directly from TEP, in which case TEP may require its
unitholders and former unitholders to reimburse it for such taxes (including any applicable penalties or interest) or, if TEP
is required to bear such payment, TEP's cash available for distribution to TEP's unitholders might be substantially reduced.
If the IRS makes audit adjustments to TEP's income tax returns for tax years beginning after 2017, it may collect any
resulting taxes (including any applicable penalties and interest) directly from TEP. TEP will generally have the ability to shift
any such tax liability to its general partner and its unitholders in accordance with their interests in TEP during the year under
audit, but there can be no assurance that TEP will be able to (or will choose to) do so under all circumstances. If TEP is required
to make payments of taxes, penalties and interest resulting from audit adjustments, it may require its unitholders and former
unitholders to reimburse it for such taxes (including any applicable penalties or interest) or, if TEP is required to bear such
payment, its cash available for distribution to its unitholders might be substantially reduced.
Taxable gain or loss on the sale of our Class A shares could be more or less than expected.
If a holder sells our Class A shares, the holder will recognize a gain or loss equal to the difference between the amount
realized and the holder's tax basis in those Class A shares. To the extent that the amount of our dividends exceeds our current
and accumulated earnings and profits, the dividends will be treated as a tax-free return of capital and will reduce a holder's tax
basis in the Class A shares. Because our dividends in excess of our earnings and profits decrease a holder's tax basis in Class A
shares, such excess dividends will result in a corresponding increase in the amount of gain, or a corresponding decrease in the
amount of loss, recognized by the holder upon the sale of the Class A shares.
Our current tax treatment may change, which could affect the value of our Class A shares or reduce our cash available
for dividends.
Changes in U.S. federal income tax law relating to our tax treatment as a corporation could result in (i) our being subject to
additional taxation at the entity level with the result that we would have less cash available for dividends and (ii) a greater
portion of our dividends being treated as taxable dividends. Moreover, we are subject to tax in numerous jurisdictions. Changes
in current law in these jurisdictions, particularly relating to the treatment of deductions attributable to acquisitions of interests in
Tallgrass Equity, could result in our being subject to additional taxation at the entity level with the result that we would have
less cash available for dividends.
Any decrease in our Class A share price could adversely affect our amount of cash available for dividends.
Changes in certain market conditions may cause our Class A share price to decrease. If the Exchange Right Holders
exercise their Exchange Right when our Class A share price is less than the price at which the Class A shares were sold in the
TGE IPO, the ratio of our income tax deductions to gross income would decline. This decline could result in our being subject
to tax sooner than expected, our tax liability being greater than expected, or a greater portion of our dividends being treated as
taxable dividends.
56
The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income with respect to our
shares for U.S. federal income tax purposes, and failure to report your dividend income in a manner consistent with the IRS
Form 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your U.S. federal
income tax return. If you are a non-U.S. holder of our shares, your broker or other withholding agent may overwithhold
taxes from dividends paid to you, in which case you generally would have to timely file a U.S. tax return or an appropriate
claim for refund in order to claim a refund of the overwithheld taxes.
Dividends we pay with respect to our Class A shares will constitute "dividends" for U.S. federal income tax purposes only
to the extent of our current and accumulated earnings and profits. Dividends we pay in excess of our earnings and profits will
not be treated as "dividends" for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of
capital to the extent of your tax basis in your shares and then as capital gain realized on the sale or exchange of such shares. We
may be unable to timely determine the portion of our dividends that is a "dividend" for U.S. federal income tax purposes.
If you are a U.S. holder of our Class A shares, the IRS Form 1099-DIV may not be consistent with our determination of the
amount that constitutes a "dividend" to you for U.S. federal income tax purposes or you may receive a corrected IRS Form
1099-DIV (and you may therefore need to file an amended federal, state or local income tax return). We will attempt to timely
notify you of available information to assist you with your income tax reporting (such as posting the correct information on our
website). However, the information that we provide to you may be inconsistent with the amounts reported to you by your
broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your
tax return.
If you are a non-U.S. holder of our Class A shares, "dividends" for U.S. federal income tax purposes will be subject to
withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax
treaty) unless the dividends are effectively connected with your conduct of a U.S. trade or business. In the event that we are
unable to timely determine the portion of our dividends that is a "dividend" for U.S. federal income tax purposes, or your
broker or withholding agent chooses to withhold taxes from dividends in a manner inconsistent with our determination of the
amount that constitutes a "dividend" for such purposes, your broker or other withholding agent may overwithhold taxes from
dividends paid to you. In such a case, you generally would have to timely file a U.S. tax return or an appropriate claim for
refund in order to obtain a refund of the overwithheld tax.
We expect that our ability to use net operating losses arising prior to the TEP Merger to offset future income will be
limited as a result of the TEP Merger, and our ability to use net operating losses arising after the TEP Merger to offset
future income may be limited.
We expect that our ability to use any net operating losses ("NOLs") generated by us prior to the TEP Merger to offset
future income will be limited due to experiencing an "ownership change" as defined under Section 382 of the Internal Revenue
Code of 1986, as amended (the "Code"), as a result of the TEP Merger. Our ability to use NOLs arising after the TEP Merger to
offset future income may be substantially limited if we were to experience another ownership change.
In general, an ownership change occurs if our "5-percent shareholders," as defined under Section 382 of the Code,
including certain groups of persons treated as 5-percent shareholders, collectively increased their ownership in Class A shares
by more than 50 percentage points over a rolling three-year period. An ownership change can occur as a result of a public
offering of Class A shares, as well as through secondary market purchases of Class A shares and certain types of reorganization
transactions. As a result of the exchange of TEP common units for Class A shares in the TEP Merger, we expect that the TEP
Merger caused us to experience an ownership change.
A corporation (including any entity such as us that is treated as a corporation for U.S. federal income tax purposes) that
experiences an ownership change will generally be subject to an annual limitation on the use of its pre-ownership change NOLs
(and certain other losses and credits) equal to the equity value of the corporation immediately before the ownership change,
multiplied by the long-term tax-exempt rate (as determined by the Internal Revenue Service) for the month in which the
ownership change occurs. Such a limitation could, for any given year, have the effect of increasing the amount of our U.S.
federal income tax liability, which would negatively impact the amount of after-tax cash available for dividends to holders of
Class A shares and our financial condition.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
A description of our properties is contained in Item 1.—Business, "Our Assets" of this Annual Report.
Our principal executive offices are located at 4200 W. 115th Street, Suite 350, Leawood, KS 66211 and our telephone
number is 913-928-6060.
57
We own two office buildings in Lakewood, Colorado, with a portion being leased to a third party pursuant to a lease with
an initial term through March 2020. In addition, we lease our principal executive offices in Leawood, Kansas.
Item 3. Legal Proceedings
See Note 19 – Legal and Environmental Matters, which is incorporated by reference into this Part I—Item 3 of this Annual
Report.
Item 4. Mine Safety Disclosures
Not applicable.
58
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Market Information
On July 2, 2018, in connection with the TEP Merger, the ticker symbol for our Class A shares listed on the NYSE was
changed from "TEGP" to "TGE." Our Class B shares are not listed or traded on any stock exchange.
Holders
As of February 6, 2019, there were 33 shareholders of record of our Class A shares. This number does not include
shareholders whose shares are held in trust by other entities. The actual number of beneficial shareholders is greater than the
number of holders of record. In addition, as of February 6, 2019, 10 shareholders of record owned all 123,887,893 of our Class
B shares.
Equity Compensation Plan
See Item 12.—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for
information regarding our Equity Compensation Plan.
Distributions of Available Cash
General. Our partnership agreement requires that, within 55 days after the end of each quarter, we distribute our available
cash to Class A Shareholders of record on the applicable record date.
Definition of Available Cash. Available cash is defined in our partnership agreement and generally means, with respect to
any calendar quarter, all cash and cash equivalents on hand at the date of determination of available cash for the distribution in
respect of such quarter (including expected distributions from Tallgrass Equity in respect of such quarter), less the amount of
cash reserves established by our general partner, which are not subject to a cap, to, among other things:
•
•
•
•
comply with applicable law;
comply with any agreement binding upon us or our subsidiaries (exclusive of TEP and its subsidiaries);
provide for future capital expenditures, debt service and other credit needs as well as any federal, state, provincial or
other income tax that may affect us in the future; or
otherwise provide for the proper conduct of our business.
Our available cash includes cash on hand resulting from borrowings made after the end of the quarter.
Our Sources of Available Cash. Our sole cash-generating asset is an approximate 55.79% membership interest in Tallgrass
Equity. Tallgrass Equity's sole cash generating assets consist of its direct and indirect equity interests in its subsidiaries,
including TEP and its 75% membership interest in Rockies Express. Therefore, our cash flow and resulting ability to make
distributions will be completely dependent upon the ability of Tallgrass Equity's subsidiaries and Rockies Express to make
distributions.
The actual amount of cash that Tallgrass Equity's subsidiaries and Rockies Express, and correspondingly Tallgrass Equity,
will have available for distribution will primarily depend on the amount of cash Tallgrass Equity's subsidiaries and Rockies
Express generates from their operations. For a description of factors that may impact our results, please read "Item 1A.—Risk
Factors."
In addition, the actual amount of cash that Tallgrass Equity's subsidiaries, Rockies Express, and Tallgrass Equity will have
available for distribution will depend on other factors, some of which are beyond our control, including:
•
•
•
•
•
•
the level of revenue Tallgrass Equity's subsidiaries and Rockies Express are able to generate from their respective
businesses;
the level of capital expenditures Tallgrass Equity, Tallgrass Equity's subsidiaries, or Rockies Express makes;
the level of Tallgrass Equity, Tallgrass Equity's subsidiaries, and Rockies Express' operating, maintenance and general
and administrative expenses or related obligations;
the cost of acquisitions, if any;
Tallgrass Equity's, Tallgrass Equity's subsidiaries', and Rockies Express' debt service requirements and other liabilities;
Tallgrass Equity's, Tallgrass Equity's subsidiaries' and Rockies Express' working capital needs;
59
•
restrictions on distributions contained in Tallgrass Equity's, Tallgrass Equity's subsidiaries', or Rockies Express' debt
agreements and any future debt agreements;
• Tallgrass Equity's subsidiaries', and Rockies Express' ability to borrow under their respective revolving credit
agreements to make distributions; and
•
the amount, if any, of cash reserves established by our general partner, in its sole discretion, for the proper conduct of
our business.
Performance Graph
The following performance graph compares the performance of our Class A shares with the NYSE Composite Index Total
Return and the Alerian MLP Infrastructure Index Total Return during the period beginning on May 12, 2015, and ending on
December 31, 2018. The graph assumes a $100 investment in our Class A shares and in each of the indices at the beginning of
the period and a reinvestment of distributions/dividends paid on such investments throughout the period.
Recent Sales of Unregistered Equity Securities
None.
Repurchase of Equity by Tallgrass Energy, LP or Affiliated Purchasers
None.
60
Item 6. Selected Financial Data
The historical financial statements included in this Annual Report reflect the consolidated results of operations of TGE's
membership interest in Tallgrass Equity and Tallgrass Equity's membership interest in TEP. In connection with the closing of
the TGE IPO on May 12, 2015, the following transactions (the "Reorganization Transactions") occurred (i) Tallgrass Equity
distributed its interests in Tallgrass Energy Holdings and Tallgrass Energy Holdings distributed its existing limited partner
interest in TGE, respectively, to certain of the Exchange Right Holders, that also collectively own 100% of the voting power of
Tallgrass Energy Holdings; (ii) TGE issued 47,725,000 Class A shares to the public (including 6,225,000 Class A shares issued
in connection with the underwriters' exercise of the overallotment option) for net proceeds of approximately $1.3 billion; (iii)
the existing limited partner interests in TGE held by certain of the Exchange Right Holders were converted into 115,729,440
Class B shares, 6,225,000 of which were automatically cancelled in connection with the underwriters' exercise of its
overallotment option; (iv) Tallgrass Equity issued 41,500,000 Tallgrass Equity units to TGE in exchange for approximately
$1.1 billion in net proceeds from the issuance of TGE's Class A shares to the public and amended the limited liability company
agreement of Tallgrass Equity to, among other things, provide that TGE is the managing member of Tallgrass Equity; (v) TGE
used the net proceeds from the purchase of the 6,225,000 overallotment option shares to purchase a like amount of Tallgrass
Equity units from certain of the Exchange Right Holders; and (vi) Tallgrass Equity entered into a $150 million revolving credit
facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings, together with the net
proceeds from the TGE IPO that Tallgrass Equity received from TGE, to purchase 20 million TEP common units from Tallgrass
Development, LP at $47.68 per TEP common unit (the "Acquired TEP Units") and pay offering expenses and other transaction
costs. Tallgrass Equity distributed the remaining proceeds (the "Excess Proceeds") to certain of the Exchange Right Holders.
The following discussion analyzes the financial condition and results of operations of TGE, which for periods prior to the
completion of the TGE IPO on May 12, 2015 includes the financial condition and results of operations of TGE Predecessor,
which refers to TGE as recast to show the effects of the Reorganization Transactions.
In certain circumstances and for ease of reading we discuss the financial results of these entities prior to their respective
acquisitions as being "our" financial results during historic periods, although Trailblazer was owned by TD from November 13,
2012 to March 31, 2014, Pony Express was wholly-owned by TD from November 13, 2012 to August 31, 2014, and Terminals
and NatGas were owned by TD from November 13, 2012 to December 31, 2016. As used in this Annual Report, unless the
context otherwise requires, "we," "us," "our," the "Partnership," "TGE" and similar terms refer to Tallgrass Energy, LP,
together with its consolidated subsidiaries (including Tallgrass Equity, TEP and their respective subsidiaries). 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 consolidated financial statements and related notes thereto included elsewhere in this Annual Report. A reference to a
"Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8.—Financial
Statements. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for
information regarding certain risks inherent in our business.
The following table shows selected historical financial and operating data of TGE for the periods and as of the dates
indicated. The selected historical financial data for periods prior to the completion of the TGE IPO on May 12, 2015 includes
the financial condition and results of operations of TGE Predecessor, which refers to TGE as recast to show the effects of the
Reorganization Transactions.
We derived the information in the following table from, and that information should be read together with and is qualified
in its entirety by reference to, the consolidated financial statements and the accompanying notes included elsewhere in this
Annual Report.
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Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data
included herein to not be indicative of our future financial condition or results of operations. A discussion of our critical
accounting estimates is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations"
in Item 7.
Year Ended December 31,
Statement of operations data:
Revenue .................................................... $
Operating income...................................... $
Equity in earnings of unconsolidated
investments (1)............................................ $
Net income before tax............................... $
Net income................................................ $
Net income (loss) attributable to TGE,
excluding predecessor operations interest $
Basic net income (loss) per Class A share $
Diluted net income (loss) per Class A
share.......................................................... $
2018
793,259
350,631
306,819
523,380
467,671
137,127
1.27
1.27
Balance sheet data (at end of period):
Property, plant and equipment, net ........... $ 2,802,429
Unconsolidated investments (1) ................. $ 1,861,686
Total assets................................................ $ 5,893,509
Long-term debt, net .................................. $ 3,205,958
Other:
2017
2015
(in thousands, except per share amounts)
2016
$
$
$
$
$
$
$
$
655,898
271,847
237,110
432,443
223,985
$
$
$
$
$
611,662
258,418
54,531
267,780
250,039
(128,729) $
(2.22) $
26,794
0.55
(2.22) $
0.55
$
$
$
$
$
$
$
$
542,661
206,229
2,759
193,071
200,348
24,563 (2)
0.51 (2)
0.51 (2)
2014
377,313
58,970
1,617
65,786
65,786
$
$
$
$
$
N/A
N/A
N/A
$ 2,394,337
$ 2,079,232
$ 2,079,567
$ 1,853,081
$
909,531
$
475,625
$
13,565
$
15,071
$ 4,292,013
$ 3,625,480
$ 3,088,635
$ 2,476,599
$ 2,292,993
$ 1,555,981
$
$
901,000
$
559,000
0.39
N/A
Dividends declared per Class A share....... $
2.02
$
1.35
$
1.00
(1) For more information see Note 7 – Investments in Unconsolidated Affiliates.
(2) The Net income attributed to TGE was based upon the number of days between the closing of the IPO on May 12, 2015 to
December 31, 2015.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
As discussed further in Note 2 – Summary of Significant Accounting Policies, our financial statements for historical
periods prior to January 1, 2017 have been recast to reflect the operations of Terminals and NatGas, which were acquired
effective January 1, 2017.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction
with the consolidated financial statements and related notes thereto included elsewhere in this Annual Report.
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 55.79% membership interest as of February 8, 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
62
• 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.
Additional information about our operations and assets is contained in the business overview included in Item 1.—
Business under "Overview" and "Our Assets."
Financial Presentation
TGE's operations are conducted through our direct and indirect subsidiaries in Tallgrass Equity and TEP. TGE is the
managing member of and therefore controls Tallgrass Equity. Tallgrass Equity, in turn, controls TEP through the direct
ownership of 100% of Tallgrass MLP GP, LLC ("TEP GP"), TEP's general partner. As a result, under GAAP, TGE consolidates
Tallgrass Equity, TEP GP, TEP, and TEP's subsidiaries. As such, TGE's results of operations will not differ materially from the
results of operations of TEP. The most noteworthy reconciling items between TGE's consolidated financial statements and
TEP's consolidated financial statements primarily relate to (i) the inclusion of the Tallgrass Equity revolving credit facility prior
to repayment and termination on July 26, 2018, (ii) the impact of TGE's election to be treated as a corporation for U.S. federal
income tax purposes, and (iii) the presentation of noncontrolling interests in Tallgrass Equity and, prior to the TEP Merger,
TEP. The interests in Tallgrass Equity and TEP that are not directly or indirectly owned by TGE will be reflected as being
attributable to noncontrolling interests in TGE's consolidated financial statements.
Summary of Results for the Year Ended December 31, 2018
During 2018, we completed the TEP Merger as discussed in Note 1 – Description of Business, as well as acquisitions of a
100% membership interest in BNN North Dakota, an additional 2% membership interest in Pony Express, an additional
25.01% membership interest in Rockies Express, a 51% membership interest in Pawnee Terminal and a 100% membership
interest in NGL Water Solutions Bakken, LLC. In addition, we issued $500 million in aggregate principal amount of 4.75%
senior notes due 2023 (the "2023 Notes"), the proceeds of which were used to repay borrowings under TEP's revolving credit
facility.
Net income for the year ended December 31, 2018 was $467.7 million, with Adjusted EBITDA and Cash Available for
Dividends (each as defined below under "Non-GAAP Financial Measures") of $654.4 million and $548.7 million, respectively,
compared to net income for the year ended December 31, 2017 of $224.0 million, with Adjusted EBITDA and Cash Available
for Dividends of $300.3 million and $268.4 million, respectively. The increase in net income, Adjusted EBITDA, and Cash
Available for Dividends was largely driven by our increased ownership in TEP due to the TEP Merger, as well as our
acquisition of an additional 25.01% membership interest in Rockies Express, as discussed further under "Results of Operations"
below.
Recent Developments
TGE Dividend Announced
On January 15, 2019, the Board of Directors of our general partner declared a cash dividend for the quarter ended
December 31, 2018 of $0.5200 per Class A share. The distribution will be paid on February 14, 2019, to Class A shareholders
of record on January 31, 2019.
Powder River Gateway
In January 2019, we closed on an expansion of our joint venture with Silver Creek. Effective January 1, 2019, we own a
51% membership interest in Powder River Gateway, which holds the Iron Horse Pipeline, the PRE Pipeline, and crude oil
terminal facilities in Guernsey, Wyoming. For additional information, see Note 3 – Acquisitions and Dispositions.
Blackstone Acquisition
On January 31, 2019, we announced that BIP had entered into a definitive purchase agreement with Kelso, EMG, and
Tallgrass KC pursuant to which BIP will acquire 100% of the membership interests in our general partner and an approximate
44% economic interest in us. Subject to customary closing conditions, the Blackstone Acquisition is expected to close within
the first quarter of 2019.
Factors and Trends Impacting Our Business
We expect to continue to be affected by certain key factors and trends described below. Our expectations are based on
assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or
interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.
See also Item 1A.—Risk Factors.
63
Long-Term U.S. Crude Oil and Natural Gas Prospects
Crude oil, natural gas, and products derived from both continue to be critical components of energy supply and demand in
the United States. Crude oil and natural gas prices declined significantly from the second half of 2014 through the first half of
2016 and crude oil experienced significant volatility during that time. However, prices generally stabilized during 2017 and
early 2018, experiencing some volatility in the second half of 2018. Although price declines and volatility may occur in
commodity markets at points in the future, we believe long-term prospects for continued domestic crude oil and natural gas
production increases are favorable.
We believe long-term growth will be driven, in part, by a combination of increased domestic demand resulting from
population and economic growth, higher industrial consumption in the U.S. spurred by the lower commodity price of feedstock
and fuel, and a desire to reduce domestic reliance on imports. One example is that we expect natural gas to gradually displace
coal-fired electricity generation due to the low prices of natural gas and stricter environmental regulations on the mining and
burning of coal. Additionally, we believe that the U.S. will continue to increase its total volume exported of both natural gas
and crude oil as new and additional infrastructure is developed to export these commodities. We expect productivity of oil and
natural gas wells to continue increasing over the long-term in some basins across the United States because of the increasing
precision and efficiency of horizontal drilling and hydraulic fracturing in oil and natural gas extraction. We also believe there is
a substantial inventory of drilled but uncompleted wells in the basins we serve, including the Bakken shale and Denver-
Julesburg basin, that are likely to be completed and turned into production as commodity prices stabilize and continue to
recover.
Current Commodity Environment
Starting in the second half of 2014 and through the first half of 2016, the prices of crude oil, natural gas, and NGLs were
extremely volatile and declined significantly. During 2017 and early 2018, price stability appeared to have generally been
restored to the market, but in the second half of 2018 some volatility returned. To the extent some of our customers remain
concerned about extended unfavorably low prices, it may be due to concerns over excess supply, truncation of current OPEC
production cuts and increased mainstream use of alternative sources of energy.
Demand for our services depends, in part, on the development of additional natural gas and crude oil reserves by third
parties. This requires significant capital expenditures by others to install facilities that extract natural gas and crude oil.
However, the possibility for low commodity prices may result in a lack of available capital for these types of expenditures. To
the extent our customers cannot finance these activities, we expect they may be less likely to enter into demand based, long-
term firm fee contracts. Low commodity prices may also negatively impact the financial condition of our customers and could
impact their ability to meet their financial obligations to us.
Additionally, lower commodity prices may lead to reduced utilization of our assets. For example, reduced utilization could
result in increased deficiency balances held by customers of our Pony Express System. For additional information, see Item 1A.
—Risk Factors, "The Throughput and Deficiency Agreements for the Pony Express System and some of our service agreements
with respect to our water business services contain provisions that can reduce the cash flow stability that the agreements were
designed to achieve."
Growth Associated with Acquisitions and Expansion Projects
Growth associated with acquisitions
We believe that we are well-positioned to grow through accretive acquisitions due to our stable financial profile and
diverse asset base that presents many logical strategic opportunities. In the past, we heavily relied on acquiring assets from
TD's portfolio of midstream assets. Now that TD has divested its entire asset portfolio, our growth through acquisitions will
rely almost exclusively on buying assets or businesses from third parties. Third party acquisitions present different risks than
those associated with acquiring assets from TD. Sourcing attractive, accretive opportunities and performing diligence on those
opportunities requires significantly more time from our employees. Most third party acquisitions involve competition from
other buyers, which generally increases the purchase price. If we are able to execute a third-party transaction, we may
encounter challenges when integrating different work cultures and operational systems. During 2018, we executed several third
party acquisitions, including BNN North Dakota, Deeprock North, an interest in Pawnee Terminal, and NGL Water Solutions
Bakken. For additional information, see Note 3 – Acquisitions and Dispositions.
64
Growth associated with expansion projects
We also believe that we are well positioned to increase volumes to our systems through cost-effective capacity expansions
and other methods for improving efficiency. For example, in January 2017, Rockies Express placed in-service the Rockies
Express Zone 3 Capacity Enhancement Project that added an incremental 0.8 Bcf/d of east-to-west capacity within Zone 3 of
the Rockies Express Pipeline. In the second quarter of 2018, Pony Express Pipeline placed in-service the Platteville Extension
Project. During 2017 and 2018, we also announced and are currently executing on the Cheyenne Connector Pipeline and the
Iron Horse Pipeline.
Energy Capital Markets and Interest Rates
During the second half of 2015 and into mid-2016, the energy credit markets experienced a material increase in the yields
for long-term debt, which caused an issuance of senior unsecured notes to be a less attractive financing option until the third
quarter of 2016, when we were able to issue the 2024 Notes. At the same time, the downturn in commodity prices generally
limited the availability of capital through traditional public issuances of common units for much of 2016. While the downturn
did not change our business plans, including our growth through acquisitions and expansion projects, it did temporarily alter
some of our financing strategies. In 2017 and 2018, TEP was able to issue an additional $1.6 billion in aggregate principal
amount of senior notes with rates from 4.75% to 5.5%.
In addition, the Federal Reserve has continued to incrementally increase short-term interest rates, which marginally
impacts the rates on our floating rate revolving credit facility. Changes in the short-term interest rates also affect how our Class
A shares are compared and ranked with other yield-oriented securities for investment decision-making purposes. If the
economy continues to strengthen, it is likely that monetary policy will continue to tighten, resulting in higher interest rates to
counter possible inflation. If this occurs, interest rates on our floating rate credit facilities and future offerings in the debt capital
markets could be at higher rates, causing our financing costs to increase accordingly. Further, investors could require a higher
yield on our Class A shares, potentially decreasing their price, which in turn could limit our ability to complete future equity
offerings at favorable pricing. For additional information, please read Item 7A.—Quantitative and Qualitative Disclosures
About Market Risk.
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.
65
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.
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 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.
66
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:
Reconciliation of Tallgrass Equity Adjusted EBITDA to Net income (loss)
attributable to TGE
Net income (loss) attributable to TGE ............................................................ $
Add:
Interest expense, net (1) ...............................................................................
Depreciation and amortization expense (1) .................................................
Distributions from unconsolidated investments (1).....................................
Deficiency payments, net (1) .......................................................................
Non-cash compensation expense (1)(2).........................................................
Loss on debt retirement ..............................................................................
Deferred income tax expense .....................................................................
Net income attributable to Exchange Right Holders..................................
Less:
Equity in earnings of unconsolidated investments (1).................................
(Gain) loss on disposal of assets (1) ............................................................
Non-cash (gain) loss related to derivative instruments ..............................
Gain on remeasurement of unconsolidated investment (1)..........................
Tallgrass Equity Adjusted EBITDA................................................................ $
Reconciliation of Tallgrass Equity Adjusted EBITDA and Cash Available
for Dividends to Net Cash Provided by Operating Activities
Net cash provided by operating activities ....................................................... $
Add:
Year Ended December 31,
2018
2017
(in thousands)
2016
137,127
$
(128,729) $
33,789
95,465
74,998
302,364
14,443
8,634
2,245
55,709
208,618
(237,197)
(4,630)
(3,340)
—
654,436
$
29,403
26,131
86,551
7,701
2,682
—
208,458
137,849
(66,922)
(189)
64
(2,744)
300,255
16,632
25,567
22,085
9,672
1,862
—
17,741
95,882
(15,287)
526
650
—
$
209,119
672,525
$
571,396
$
413,298
Interest expense, net (1) ...............................................................................
Other, including changes in operating working capital (1)..........................
Tallgrass Equity Adjusted EBITDA
Less:
95,465
(113,554)
654,436
$
29,403
(300,544)
300,255
$
16,632
(220,811)
209,119
$
Cash interest cost (1)....................................................................................
Maintenance capital expenditures, net (1) ...................................................
Cash flow attributable to predecessor operations.......................................
Tallgrass Equity Cash Available for Dividends............................................... $
(91,590)
(14,176)
—
(27,669)
(4,179)
—
548,670
$
268,407
$
(15,168)
(3,270)
(2,743)
187,938
(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.
67
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:
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating
Income in the Natural Gas Transportation Segment (1)
Operating income..................................................................................... $
Add:
Depreciation and amortization expense (2) ..........................................
Distributions from unconsolidated investment (2) ...............................
Other, net (2).........................................................................................
Less:
Adjusted EBITDA attributable to noncontrolling interests.................
Non-cash (gain) loss related to derivative instruments (2) ...................
Tallgrass Equity Segment Adjusted EBITDA.......................................... $
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating
Income in the Crude Oil Transportation Segment (1)
Operating income..................................................................................... $
Add:..........................................................................................................
Depreciation and amortization expense (2) ..........................................
Deficiency payments, net (2) ................................................................
Less:
Adjusted EBITDA attributable to noncontrolling interests.................
Non-cash (gain) loss related to derivative instruments (2) ...................
Tallgrass Equity Segment Adjusted EBITDA.......................................... $
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating
Income in the Gathering, Processing & Terminalling Segment (1)
Operating income (loss)........................................................................... $
Add:
Depreciation and amortization expense (2) ..........................................
Non-cash (gain) loss related to derivative instruments (2) ...................
Distributions from unconsolidated investments (2)..............................
Deficiency payments, net (2) ................................................................
Other, net (2).........................................................................................
Less:
Year Ended December 31,
2018
2017
(in thousands)
2016
69,586
$
67,434
$
56,135
13,102
297,496
2,359
5,421
85,994
1,424
6,099
21,245
1,722
(5,319)
—
377,224
$
20,738
(33)
180,978
$
(10,205)
33
75,029
258,308
$
190,170
$
215,784
36,578
4,858
16,156
7,967
15,211
9,123
(60,414)
—
239,330
$
(73,385)
(123)
140,785
(108,093)
129
$
132,154
51,565
$
33,453
$
(903)
21,665
(3,340)
4,868
8,540
182
4,554
750
557
(458)
142
4,257
(84)
773
550
—
526
(1,041)
4,078
211,261
(2,142)
209,119
(Gain) loss on disposal of assets (2) .....................................................
Adjusted EBITDA attributable to noncontrolling interests.................
Tallgrass Equity Segment Adjusted EBITDA.......................................... $
Total Tallgrass Equity Segment Adjusted EBITDA................................. $
Corporate general and administrative costs ........................................
Total Tallgrass Equity Adjusted EBITDA................................................ $
(4,630)
(19,647)
59,203
675,757
(21,321)
654,436
$
$
$
(189)
(22,726)
16,083
337,846
(37,591)
300,255
$
$
$
(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 20 – Reportable Segments to the accompanying consolidated
financial statements.
(2) Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.
68
Results of Operations
The following provides a summary of our operating metrics for the periods indicated:
Year Ended December 31,
2018
2017
(in thousands, except operating data)
2016
Natural Gas Transportation Segment:
TIGT and Trailblazer average firm contracted volumes (MMcf/d) (1)...
Rockies Express average firm contracted volumes (MMcf/d) (2) ..........
Crude Oil Transportation Segment:
Crude oil transportation average contracted capacity (Bbls/d) .............
Crude oil transportation average throughput (Bbls/d)...........................
Gathering, Processing & Terminalling Segment:
Natural gas processing inlet volumes (MMcf/d) ...................................
Freshwater average volumes (Bbls/d) ...................................................
Produced water gathering and disposal average volumes (Bbls/d) .......
(1) Volumes transported under firm fee contracts, excluding Rockies Express.
(2) Volumes transported under long-term firm fee contracts.
1,636
4,101
306,936
336,314
122
17,849
98,489
1,711
4,101
301,936
267,734
109
69,139
31,511
1,627
3,384
295,435
285,507
103
13,201
11,307
69
The following provides a summary of our consolidated results of operations for the periods indicated:
Revenues:
Crude oil transportation services ................................................... $
Natural gas transportation services................................................
Sales of natural gas, NGLs, and crude oil .....................................
Processing and other revenues.......................................................
Total Revenues .......................................................................
Operating Costs and Expenses:
Cost of sales...................................................................................
Cost of transportation services ......................................................
Operations and maintenance..........................................................
Depreciation and amortization ......................................................
General and administrative............................................................
Taxes, other than income taxes......................................................
Contract termination......................................................................
(Gain) loss on disposal of assets....................................................
Total Operating Costs and Expenses......................................
Operating Income .................................................................................
Other Income (Expense):
Equity in earnings of unconsolidated investments ........................
Interest expense, net ......................................................................
Gain on remeasurement of unconsolidated investment.................
Other (expense) income, net..........................................................
Total Other Income (Expense) ...............................................
Net income before tax...........................................................................
Deferred income tax expense ........................................................
Net income............................................................................................
Net income attributable to noncontrolling interests ......................
Net income (loss) attributable to TGE.................................................. $
Year Ended December 31,
2018
2017
(in thousands)
2016
398,334
$
345,733
$
126,894
168,586
99,445
793,259
114,815
53,068
72,460
110,862
70,656
31,810
—
(11,043)
442,628
350,631
306,819
(133,319)
—
(751)
172,749
523,380
(55,709)
467,671
(330,544)
137,127
122,364
108,503
79,298
655,898
91,213
46,200
62,069
90,800
65,536
28,832
—
(599)
384,051
271,847
237,110
(89,348)
9,728
3,106
160,596
432,443
(208,458)
223,985
(352,714)
(128,729) $
$
374,949
119,962
77,123
39,628
611,662
71,650
47,669
55,070
86,247
57,298
25,400
8,061
1,849
353,244
258,418
54,531
(45,601)
—
432
9,362
267,780
(17,741)
250,039
(216,250)
33,789
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Revenues. Total revenues were $793.3 million for the year ended December 31, 2018 compared to $655.9 million for the
year ended December 31, 2017, which represents an increase of $137.4 million, or 21%, in total revenues. The overall increase
in revenue was largely driven by increased revenues of $93.5 million and $79.9 million in the Gathering, Processing &
Terminalling and Crude Oil Transportation segments, respectively, partially offset by a $35.4 million increase in eliminations of
intersegment revenue and decreased revenues of $0.6 million in the Natural Gas Transportation segment, as discussed further
below.
Operating costs and expenses. Operating costs and expenses were $442.6 million for the year ended December 31, 2018
compared to $384.1 million for the year ended December 31, 2017, which represents an increase of $58.6 million, or 15%. The
overall increase in operating costs and expenses is driven by increased operating costs and expenses of $75.3 million and $11.7
million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by
decreased operating costs and expenses of $25.7 million and $2.7 million in the Corporate and Other and Natural Gas
Transportation segments, as discussed further below. The decrease in Corporate and Other expenses was primarily driven by a
$35.4 million increase in eliminations of intersegment operating costs and expenses, partially offset by a $4.9 million increase
in corporate general and administrative costs and a $4.8 million increase in depreciation and amortization costs due to the
administrative assets acquired from TD in February 2018. The increase in corporate general and administrative costs was
70
primarily due to expenses at TEP and Tallgrass Equity attributable to the Merger Agreement and the transactions contemplated
by the Merger Agreement, as well as Tallgrass Equity's acquisition of an additional 25.01% membership interest in Rockies
Express and additional TEP common units.
Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $306.8 million
and $237.1 million for the years ended December 31, 2018 and 2017, respectively. Equity in earnings of unconsolidated
investments of $306.8 million for the year ended December 31, 2018 primarily reflects our portion of earnings and the $35.9
million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies
Express, inclusive of the additional 25.01% membership interest acquired in February 2018, as well as $4.2 million of equity in
earnings related to our 51% membership interest in Pawnee Terminal. Equity in earnings of unconsolidated investments of
$237.1 million for the year ended December 31, 2017 primarily reflects our portion of earnings and the $23.2 million of
amortization of a negative basis difference associated with our 49.99% membership interest in Rockies Express as well as $1.5
million of equity in earnings related to our 20% membership interest in Deeprock Development prior to our acquisition of a
controlling financial interest in Deeprock Development in July 2017. During the year ended December 31, 2017, Rockies
Express recognized a $150 million gain on settlement of the Ultra litigation as discussed in Note 19 – Legal and Environmental
Matters.
Interest expense, net. Interest expense of $133.3 million for the year ended December 31, 2018 was primarily composed of
interest and fees associated with the Senior Notes, as defined in Note 10 – Long-term Debt, and the TEP and Tallgrass Equity
revolving credit facilities. Interest expense of $89.3 million for the year ended December 31, 2017 was primarily composed of
interest and fees associated with 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 2017 and 2018 acquisitions, as well as the higher
borrowing rate on the Senior Notes, the proceeds of which were used to repay borrowings under TEP's revolving credit facility.
Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.7
million for the year ended December 31, 2017 was related to the remeasurement to fair value of our existing 20% membership
interest in Deeprock Development in connection with our acquisition of a controlling financial interest in Deeprock
Development in July 2017. For additional information, see Note 3 – Acquisitions and Dispositions.
Other (expense) income, net. Other (expense) 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 expense for the year ended
December 31, 2018 was $0.8 million compared to other income of $3.1 million for the year ended December 31, 2017. Other
expense of $0.8 million for the year ended December 31, 2018 included a $2.2 million loss on debt retirement associated with
the write off of deferred financing costs associated with the Amendment to the TEP revolving credit facility and the termination
of the Tallgrass Equity revolving credit facility. Other income of $3.1 million for the year ended December 31, 2017 included a
$1.9 million unrealized gain on derivative instrument related to the change in fair value of the call option received from TD as
part of the acquisition of an additional 31.3% membership interest in Pony Express as discussed further in Note 9 – Risk
Management.
Deferred income tax expense. Deferred income tax expense for the year ended December 31, 2018 was $55.7 million
compared to a deferred income tax expense of $208.5 million for the year ended December 31, 2017. The decrease in deferred
income tax expense was primarily driven by the remeasurement of the deferred tax asset during the year ended December 31,
2017 as a result of the federal rate change under the tax legislation referred to as the Tax Cuts and Jobs Act that was signed into
law on December 22, 2017, partially offset by our increased ownership in TEP due to the TEP Merger and the resulting increase
in income allocated to TGE. For additional information, see Note 17 – Income Taxes.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Revenues. Total revenues were $655.9 million for the year ended December 31, 2017 compared to $611.7 million for the
year ended December 31, 2016, which represents an increase of $44.2 million, or 7%, in total revenues. The overall increase in
revenue was largely driven by increased revenues of $72.7 million and $5.9 million in the Gathering, Processing &
Terminalling and Natural Gas Transportation segments, respectively, partially offset by decreased revenues of $15.9 million in
the Crude Oil Transportation segment, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $384.1 million for the year ended December 31, 2017
compared to $353.2 million for the year ended December 31, 2016, which represents an increase of $30.8 million, or 9%. The
overall increase in operating costs and expenses was driven by increased operating costs and expenses of $38.3 million
and $9.7 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially
offset by decreased operating costs and expenses of $11.8 million in the Corporate and Other segment and $5.4 million in the
Natural Gas Transportation segment, as discussed further below. The decrease in Corporate and Other expenses was primarily
driven by an $18.4 million increase in eliminations of intersegment operating costs and expenses, partially offset by a $6.6
million increase in corporate general and administrative costs primarily due to new equity-based compensation grants issued
71
during the year ended December 31, 2017 as well as payroll taxes associated with the vesting of TEP common units associated
with equity-based compensation grants under the TEP GP Long-term Incentive Plan.
Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $237.1
million and $54.5 million for the years ended December 31, 2017 and 2016, respectively. Equity in earnings of unconsolidated
investments of $237.1 million for the year ended December 31, 2017 primarily reflects our portion of earnings and the $23.2
million of amortization of a negative basis difference associated with our 49.99% membership interest in Rockies Express, as
well as $1.5 million of equity in earnings related to our 20% membership interest in Deeprock Development prior to our
acquisition of a controlling financial interest in Deeprock Development in July 2017, as discussed in Note 3 – Acquisitions and
Dispositions. The equity in earnings for the year ended December 31, 2017 includes recognition of our portion of the $150
million gain on settlement of the Ultra litigation as discussed above. Equity in earnings of unconsolidated investments of $54.5
million for the year ended December 31, 2016 primarily reflects our portion of earnings and the $9.1 million of amortization of
a negative basis difference associated with our acquisition of a 25% membership interest in Rockies Express effective May 6,
2016, as well as $2.8 million related to our 20% membership interest in Deeprock Development during the year ended
December 31, 2016. The equity in earnings for the year ended December 31, 2016 includes recognition of our portion of the
$65 million settlement received by Rockies Express related to the lawsuit between Mineral Management Service, a former unit
of the U.S. Department of Interior (collectively "Interior") and Rockies Express as discussed in Note 19 – Legal and
Environmental Matters.
Interest expense, net. Interest expense of $89.3 million for the year ended December 31, 2017 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. Interest
expense of $45.6 million for the year ended December 31, 2016 was primarily composed of interest and fees associated with
TEP and Tallgrass Equity revolving credit facilities and the 2024 Notes issued on September 1, 2016. The increase in interest
and fees is primarily due to increased borrowings to fund a portion of our acquisitions, as discussed further in Note 3 –
Acquisitions and Dispositions, as well as the higher borrowing rate on the 2024 and 2028 Notes, the proceeds of which were
used to repay borrowings under TEP's revolving credit facility.
Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.7
million for the year ended December 31, 2017 was related to the remeasurement to fair value of our existing 20% membership
interest in Deeprock Development in connection with TEP's acquisition of a controlling financial interest in Deeprock
Development in July 2017. For additional information, see Note 3 – Acquisitions and Dispositions.
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 year ended December 31, 2017
was $3.1 million compared to $0.4 million for the year ended December 31, 2016. Other income of $3.1 million and $0.4
million for the years ended December 31, 2017 and 2016 included a $1.9 million unrealized gain and a $1.3 million unrealized
loss, respectively, on derivative instrument related to the change in fair value of the call option received from TD as part of the
acquisition of an additional 31.3% membership interest in Pony Express as discussed further in Note 9 – Risk Management.
Deferred income tax expense. Deferred income tax expense for the year ended December 31, 2017 was $208.5 million
compared to a deferred income tax expense of $17.7 million for the year ended December 31, 2016. The increase in deferred
income tax expense was primarily driven by the remeasurement of the deferred tax asset as a result of the federal rate change
under the tax legislation referred to as the Tax Cuts and Jobs Act that was signed into law on December 22, 2017, as well as the
increase in taxable income, primarily attributable to the increased equity in earnings associated with Rockies Express as a result
of the Ultra settlement. For additional information, see Note 17 – Income Taxes.
72
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)
2018
2017
2016
Year Ended December 31,
(in thousands)
Revenues:
Natural gas transportation services ......................................................... $
Sales of natural gas, NGLs, and crude oil...............................................
Processing and other revenues ................................................................
131,555
$
129,058
$
125,603
1,195
7,709
3,412
8,551
3,241
6,253
Total revenues.....................................................................................
140,459
141,021
135,097
Operating costs and expenses:
Cost of sales ............................................................................................
Cost of transportation services ................................................................
Operations and maintenance ...................................................................
Depreciation and amortization ................................................................
General and administrative .....................................................................
Taxes, other than income taxes ...............................................................
Total operating costs and expenses ....................................................
1,382
2,990
27,185
19,442
15,279
4,595
70,873
2,767
2,852
28,910
19,180
15,385
4,493
73,587
Operating income......................................................................................... $
69,586
$
67,434
$
3,804
5,051
28,458
20,976
16,335
4,338
78,962
56,135
(1) Segment results as presented represent total revenue and operating income, including intersegment activity. For
reconciliations to the consolidated financial data, see Note 20 – Reportable Segments.
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Revenues. Natural Gas Transportation segment revenues were $140.5 million for the year ended December 31, 2018
compared to $141.0 million for the year ended December 31, 2017, which represents a decrease of $0.6 million in segment
revenues due to a $2.2 million decrease in sales of natural gas driven by decreased volumes sold and a $0.8 million decrease in
other revenues driven by a decrease in the management fee received by NatGas as a result of the Ultra settlement recognized
during the year ended December 31, 2017, as discussed in Note 19 – Legal and Environmental Matters, partially offset by a
$2.5 million increase in natural gas transportation services due to increased revenue associated with increased throughput and
contracted capacity in the second quarter of 2018 and colder weather in the first quarter of 2018, both resulting in higher
volumes transported during the first half of 2018.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $70.9 million
for the year ended December 31, 2018 compared to $73.6 million for the year ended December 31, 2017, which represents a
decrease of $2.7 million, or 4%. The overall decrease in operating costs and expenses was primarily due to a $1.7 million
decrease in operations and maintenance costs driven by decreased pipeline integrity work and a $1.4 million decrease in cost of
sales driven by decreased volumes of natural gas sold, partially offset by a $0.3 million increase in depreciation and
amortization costs.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Revenues. Natural Gas Transportation segment revenues were $141.0 million for the year ended December 31, 2017
compared to $135.1 million for the year ended December 31, 2016, which represents an increase of $5.9 million, or 4%, in
segment revenues due to a $3.5 million increase in natural gas transportation services, a $2.3 million increase in other revenue,
and a $0.2 million increase in sales of natural gas. The $3.5 million increase in natural gas transportation services was driven by
increased tariff rates at TIGT, partially offset by a change in the fuel recovery structure, beginning May 1, 2016 as a result of
the rate case settlement discussed in Note 18 – Regulatory Matters, as well as increased throughput volumes at Trailblazer. The
$2.3 million increase in other revenues was primarily attributable to the increased management fee received by NatGas as a
result of the Ultra settlement discussed above.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $73.6 million
for the year ended December 31, 2017 compared to $79.0 million for the year ended December 31, 2016, which represents a
decrease of $5.4 million, or 7%. The overall decrease in operating costs and expenses was primarily due to a $2.2 million
decrease in the cost of transportation services, a $1.8 million decrease in depreciation and amortization, and a $1.0 million
decrease in cost of sales. The $2.2 million decrease in the cost of transportation services was driven by lower costs associated
73
with fuel reimbursements as a result of changes to TIGT's fuel recovery structure and the $1.8 million decrease in depreciation
and amortization was driven by changes in depreciation rates at TIGT, both as a result of the 2016 rate case settlement
discussed above. The $1.0 million decrease in cost of sales was driven by decreased volumes sold as well as a lower of cost and
net realizable value inventory adjustment during the year ended December 31, 2016.
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)
2018
Year Ended December 31,
2017
(in thousands)
2016
437,653
$
353,395
$
374,949
Revenues:
Crude oil transportation services............................................................. $
Sales of natural gas, NGLs, and crude oil...............................................
Processing and other revenues ................................................................
Total revenues.....................................................................................
Operating costs and expenses:
Cost of sales ............................................................................................
Cost of transportation services ................................................................
Operations and maintenance ...................................................................
Depreciation and amortization ................................................................
General and administrative .....................................................................
Taxes, other than income taxes ...............................................................
6,290
511
444,454
8,334
68,184
12,896
54,237
18,486
24,009
11,179
—
364,574
9,680
57,284
11,838
52,364
20,906
22,332
Total operating costs and expenses ....................................................
186,146
174,404
Operating income......................................................................................... $
258,308
$
190,170
$
(1) Segment results as presented represent total revenue and operating income, including intersegment activity. For
reconciliations to the consolidated financial data, see Note 20 – Reportable Segments.
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
5,554
—
380,503
4,728
55,519
13,075
51,362
20,650
19,385
164,719
215,784
Revenues. Crude Oil Transportation segment revenues were $444.5 million for the year ended December 31, 2018
compared to $364.6 million for the year ended December 31, 2017, which represents an increase of $79.9 million, or 22%, in
segment revenues driven by an $84.3 million increase in crude oil transportation services, partially offset by a $4.9 million
decrease in sales of crude oil primarily due to decreased volumes sold during the year ended December 31, 2018. The increase
in crude oil transportation services revenue was primarily driven by a $55.4 million increase in committed volume shipments, a
$37.2 million increase in walk-up barrels shipped, a $6.4 million increase due to the FERC annual index adjustments effective
July 1, 2018, and a $5.6 million increase in PLA revenue. These increases were partially offset by a $24.4 million net decrease
in revenue from a committed shipper that extended its contract during the fourth quarter of 2017, thereby paying a lower tariff
rate, which was partially offset by increased volumes shipped.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $186.1 million
for the year ended December 31, 2018 compared to $174.4 million for the year ended December 31, 2017, which represents an
increase of $11.7 million, or 7%. The overall increase in operating costs and expenses was primarily driven by a $10.9 million
increase in cost of transportation services driven by higher throughput volumes during the year ended December 31, 2018
compared to the year ended December 31, 2017, a $1.9 million increase in depreciation and amortization costs due to assets
placed into service in 2018, and a $1.7 million increase in taxes, other than income taxes driven by an increase in property tax
assessment estimates. These increases were partially offset by a $2.4 million decrease in general and administrative costs and a
$1.3 million decrease in cost of sales driven by decreased volumes sold.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Revenues. Crude Oil Transportation segment revenues were $364.6 million for the year ended December 31,
2017 compared to $380.5 million for the year ended December 31, 2016, which represents a decrease of $15.9 million, or 4%,
in segment revenues driven by a $21.6 million decrease in crude oil transportation services, primarily due to a $27.1 million
increase in shipper deficiency payments that are not recognized in revenue and a $9.9 million decrease in the incremental
barrels delivered during the year ended December 31, 2017 compared to the year ended December 31, 2016, partially offset by
a $7.8 million increase in committed barrels shipped and a $7.0 million increase in walk-up barrels shipped. The decrease in
74
crude oil transportation services was partially offset by a $5.6 million increase in sales of crude oil primarily due to increased
volumes of crude oil sold during the year ended December 31, 2017 compared to the year ended December 31, 2016.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $174.4
million for the year ended December 31, 2017 compared to $164.7 million for the year ended December 31, 2016 which
represents an increase of $9.7 million, or 6%. The overall increase in operating costs and expenses was primarily driven by a
$5.0 million increase in cost of sales primarily due to increased volumes of crude oil sold during the year ended December 31,
2017, a $2.9 million increase in taxes, other than income taxes, driven by assets placed in-service throughout 2016, and a $1.8
million increase in cost of transportation services as a result of amendments to the Deeprock Terminal lease agreement,
resulting in the non-cash write off of upfront payments in the fourth quarter of 2017, partially offset by lower lease payments
during the third and fourth quarters of 2017. The increased cost of transportation services during the year ended December 31,
2017 as a result of the Deeprock Terminal lease was partially offset by higher electric costs as a result of pressure restrictions
during the year ended December 31, 2016. The cost increases during the year ended December 31, 2017 were partially offset by
a $1.2 million decrease in operations and maintenance costs due to the timing of pipeline integrity work.
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)
2018
2017
2016
Year Ended December 31,
Revenues:
Sales of natural gas, NGLs, and crude oil............................................... $
Processing and other revenues ................................................................
Total revenues.....................................................................................
Operating costs and expenses:
Cost of sales ............................................................................................
Cost of transportation services ................................................................
Operations and maintenance ...................................................................
Depreciation and amortization ................................................................
General and administrative .....................................................................
Taxes, other than income taxes ...............................................................
Contract termination ...............................................................................
(Gain) loss on disposal of assets .............................................................
Total operating costs and expenses ....................................................
(in thousands)
161,101
$
93,998
$
118,564
279,665
105,985
52,327
32,379
32,369
12,877
3,206
—
(11,043)
228,100
92,213
186,211
80,088
20,650
21,321
19,256
10,035
2,007
—
(599)
152,758
Operating income (loss)............................................................................... $
51,565
$
33,453
$
(1) Segment results as presented represent total revenue and operating income, including intersegment activity. For
reconciliations to the consolidated financial data, see Note 20 – Reportable Segments.
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
68,698
44,835
113,533
63,746
3,942
13,537
13,909
7,715
1,677
8,061
1,849
114,436
(903)
Revenues. Gathering, Processing & Terminalling segment revenues were $279.7 million for the year ended December 31,
2018 compared to $186.2 million for the year ended December 31, 2017, which represents a $93.5 million, or 50%, increase in
segment revenues. The increase in segment revenues was primarily due to a $67.1 million increase in sales of natural gas,
NGLs, and crude oil and a $26.4 million increase in processing and other revenues. The increase in sales of natural gas, NGLs,
and crude oil was driven by (i) increased crude oil sales of $30.3 million at Stanchion, (ii) increased sales of NGLs of $24.2
million primarily due to higher throughput volumes and increased volumes sold driven by the Douglas Gathering System
acquisition in June 2017 and higher NGL prices, and (iii) increased sales of natural gas of $12.3 million due to sales of residue
gas from the Douglas Gathering System. The increase in processing and other revenues was driven by (i) increased terminal
services revenue of $16.2 million driven by the acquisition of Deeprock North in January 2018 and the acquisition of a
controlling interest in, and subsequent consolidation of, Deeprock Development in July 2017, (ii) increased water business
services revenue of $7.6 million driven by the acquisition of BNN North Dakota in January 2018 and increased produced water
disposal volumes, partially offset by decreased fresh water transportation volumes, and (iii) increased processing fee income of
$3.9 million primarily driven by changes in the accounting treatment of certain commodities retained as consideration for
75
processing services to processing fee revenue beginning January 1, 2018 as discussed further in Note 12 – Revenue from
Contracts with Customers.
Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were
$228.1 million for the year ended December 31, 2018 compared to $152.8 million for the year ended December 31, 2017,
which represents an increase of $75.3 million, or 49%. The increase in operating costs and expenses was primarily driven by (i)
an increase of $31.7 million in cost of transportation services due to crude oil transportation fees paid by Stanchion, partially
offset by decreased fresh water transportation volumes and associated costs, (ii) a $25.9 million increase in cost of sales
primarily due to higher NGL prices, higher throughput volumes, and increased volumes sold driven by the Douglas Gathering
System acquisition as discussed above, and (iii) increases of $13.1 million, $11.1 million, and $2.8 million in depreciation and
amortization, operations and maintenance costs, and general and administrative costs, respectively, all primarily driven by the
2018 acquisitions of BNN North Dakota and Deeprock North and the 2017 acquisitions of the Douglas Gathering System and
Deeprock Development. The increase in operating costs and expenses was partially offset by the $11.0 million gain on disposal
of assets, primarily driven by the gain on the disposal of TCG during the year ended December 31, 2018, compared to the $0.6
million gain on disposal of assets during the year ended December 31, 2017.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Revenues. Gathering, Processing & Terminalling segment revenues were $186.2 million for the year ended December 31,
2017 compared to $113.5 million for the year ended December 31, 2016, which represents a $72.7 million, or 64% increase in
segment revenues. The increase in segment revenues was primarily due to a $47.4 million increase in processing and other
revenues and a $25.3 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 $29.8 million as a result of increased fresh water
supply and produced water disposal volumes; (ii) increased terminalling services revenue of $11.0 million driven by the
acquisition of a controlling interest in and subsequent consolidation of Deeprock Development in July 2017; and (iii) increased
fee income of $6.1 million driven by the acquisition of the Douglas Gathering System in June 2017. The increase in sales of
natural gas, NGLs, and crude oil was driven by a 36% increase in NGL prices and sales of residue gas from the Douglas
Gathering System, partially offset by lower volumes of NGLs sold during the year ended December 31, 2017 as a result of take
in kind elections in effect for parts of 2017 under two major processing agreements.
Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were
$152.8 million for the year ended December 31, 2017 compared to $114.4 million for the year ended December 31, 2016,
which represents an increase of $38.3 million, or 33%. The increase in operating costs and expenses was driven by (i) a $16.7
million increase in cost of transportation services primarily driven by increased volumes in water business services as discussed
above and crude oil transportation fees paid by Stanchion during the year ended December 31, 2017; (ii) a $16.3 million
increase in cost of sales primarily driven by higher producer settlements and higher NGL sales attributable to the acquisition of
the Douglas Gathering System in 2017 as discussed above; and (iii) increases of $7.8 million, $5.3 million, and $2.3 million in
operations and maintenance costs, depreciation and amortization, and general and administrative costs, respectively, all
primarily driven by the 2017 acquisitions of the Douglas Gathering System, the PRB Crude System, and Deeprock
Development. These increases were partially offset by a $8.1 million contract termination fee as a result of the buyout of an
operating agreement at the Sterling Terminal during the year ended December 31, 2016 and a $2.4 million decrease in (gain)
loss on disposal of assets primarily driven by a gain on disposal of assets from insurance proceeds received during the year
ended December 31, 2017 related to assets destroyed by a fire caused by a lightning strike during the year ended December 31,
2016.
Liquidity and Capital Resources Overview
Our primary sources of liquidity for the year ended December 31, 2018 were cash generated from operations, proceeds
from TEP's issuance of senior notes, and borrowings under TEP's revolving credit facility. We expect our sources of liquidity in
the future to include:
•
•
•
cash generated from our operations;
borrowing capacity available under TEP's revolving credit facility; and
future issuances of additional equity and/or debt securities.
We believe that cash on hand, cash generated from operations, and availability under TEP's revolving credit facility will be
adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements, and our
planned cash 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 TEP's revolving credit facility and
issuances of debt and/or equity securities. For additional information regarding our revolving credit facilities and senior
76
unsecured notes, see Note 10 – Long-term Debt. For additional information regarding our equity transactions, see Note 11 –
Partnership Equity.
Our total liquidity as of December 31, 2018 and 2017 was as follows:
December 31, 2018
December 31, 2017
Cash on hand ................................................................................................... $
Total capacity under the TEP revolving credit facility (1)................................
Less: Outstanding borrowings under the TEP revolving credit facility .....
Less: Letters of credit issued under the TEP revolving credit facility .......
Available capacity under the TEP revolving credit facility ............................
Total capacity under the Tallgrass Equity revolving credit facility ................
Less: Outstanding borrowings under the Tallgrass Equity revolving
credit facility (2) ..........................................................................................
Available capacity under the Tallgrass Equity revolving credit facility .........
Total liquidity .................................................................................................. $
(in thousands)
9,596
$
2,250,000
(1,224,000)
(94)
1,025,906
—
—
—
1,035,502
$
2,593
1,750,000
(661,000)
(94)
1,088,906
150,000
(146,000)
4,000
1,095,499
(1)
In July 2018, the TEP revolving credit facility was amended, increasing the total capacity to $2.25 billion. See Note 10
– Long-term Debt for additional information.
(2) On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility. See
Note 10 – Long-term Debt for additional information.
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 TEP's 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 December 31, 2018, we had a working capital deficit of $146.9 million compared to a working capital deficit of
$101.6 million at December 31, 2017, which represents an increase in the working capital deficit of $45.4 million. The
overall increase in the working capital deficit was primarily attributable to changes in the following components:
•
•
•
•
an increase in accounts payable and accrued liabilities of $110.0 million primarily due to crude oil purchases at
Stanchion, an increase in accrued payroll, an increase in capital expenditures at Terminals, and payables related to
BNN North Dakota and NGL Water Solutions Bakken acquired in January 2018 and November 2018, respectively,
partially offset by a decrease in capital expenditures at Pony Express;
an increase in other current liabilities of $31.7 million, primarily driven by the recognition of a $25 million liability at
PLT as discussed in Note 3 – Acquisitions and Dispositions;
an increase in deferred revenue of $22.6 million primarily from deficiency payments collected by Pony Express and
deferred revenue at BNN Colorado, which was consolidated in December 2018; and
an increase in accrued interest of $14.1 million primarily due to increased borrowings to fund a portion of our 2018
acquisitions, as well as the higher borrowing rate on the Senior Notes, the proceeds of which were used to repay
borrowings under TEP's revolving credit facility.
77
These working capital decreases were partially offset by:
•
•
an increase in accounts receivable of $116.1 million primarily due to crude oil sales at Stanchion, as well as
receivables related to BNN North Dakota assets acquired during 2018, and BNN Colorado, which was consolidated in
December 2018; and
an increase in inventory of $12.7 million primarily due to crude oil purchases at Stanchion and PLA barrels retained at
Pony Express.
A material adverse change in operations, available financing under our revolving credit facility, or available financing from
the equity or debt capital markets could impact our ability to fund our requirements for liquidity and capital resources in the
future.
Cash Flows
The following table and discussion presents a summary of our cash flow for the periods indicated:
Year Ended December 31,
2018
2017
(in thousands)
2016
Net cash provided by (used in):
Operating activities .......................................................... $
Investing activities ........................................................... $
Financing activities .......................................................... $
672,525
$
(987,212) $
$
321,690
571,396
$
(898,541) $
$
327,279
413,298
(595,539)
182,466
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Operating Activities. Cash flows provided by operating activities were $672.5 million and $571.4 million for the years
ended December 31, 2018 and 2017, respectively. The increase in net cash flows provided by operating activities of $101.1
million was primarily driven by the increase in operating results, as discussed above, and a $69.7 million increase in
distributions received from unconsolidated affiliates, primarily Rockies Express, as a result of our increased membership
interest effective March 31, 2017 and February 7, 2018. These increases were partially offset by a net decrease in cash flows
from changes in working capital driven by a $44.2 million decrease in net cash inflows from accounts receivable, primarily due
to crude oil sales at Stanchion, partially offset by a $27.7 million decrease in net cash outflows from accounts payable,
primarily due to crude oil purchases at Stanchion.
Investing Activities. Cash flows used in investing activities were $987.2 million for the year ended December 31, 2018,
primarily driven by:
•
•
•
•
•
•
•
contributions to unconsolidated investments in the amount of $473.9 million, primarily to fund our portion of the
repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018, as well as to fund our share of
capital projects at Iron Horse and BNN Colorado;
capital expenditures of $368.9 million, primarily due to spending on the Cheyenne Connector, a new 70-mile natural
gas pipeline located in Colorado, additional water gathering infrastructure located in North Dakota, a 55-mile
extension on the Pony Express system, construction of the Buckingham Terminal expansion, construction of the
Guernsey, Natoma, and Grasslands Terminals, and pipe replacement and remediation work on the Trailblazer Pipeline
system as discussed in Note 19 – Legal and Environmental Matters;
cash outflows of $95.0 million for the acquisition of a 100% membership interest in BNN North Dakota;
cash outflows of $91.0 million for the acquisition of a 100% membership interest in NGL Water Solutions Bakken;
cash outflows of $30.7 million for the initial capital contribution and formation of PLT;
cash outflows of $30.6 million for the acquisition of a 51% membership interest in Pawnee Terminal; and
cash outflows of $19.5 million for the acquisition of a 38% membership interest in Deeprock North.
These cash outflows were partially offset by cash inflows of:
•
•
$80.2 million of distributions received from unconsolidated affiliates in excess of cumulative earnings recognized,
primarily Rockies Express; and
$50.0 million from the sale of TCG.
78
Cash flows used in investing activities were $898.5 million for the year ended December 31, 2017, primarily driven by:
•
•
•
•
•
•
cash outflows of $400.0 million for the acquisition of an additional 24.99% membership interest in Rockies Express;
capital expenditures of $145.1 million, primarily due to spending on an additional freshwater connection at Water
Solutions, a connection to a refinery complex on the Pony Express System, a 55-mile extension on the Pony Express
System, and remediation digs on the Pony Express System as discussed in Note 19 – Legal and Environmental
Matters;
cash outflows of $140.0 million for the acquisition of Terminals and NatGas;
cash outflows of $128.5 million for the acquisition of the Douglas Gathering System;
cash outflows of $57.2 million for the acquisition of an additional 40% membership interest in Deeprock
Development;
contributions to unconsolidated investments in the amount of $45.9 million, primarily to fund remaining costs
associated with the Zone 3 Capacity Enhancement project at Rockies Express; and
•
cash outflows of $36.0 million for the acquisition of the PRB Crude System.
These cash outflows were partially offset by $69.4 million of distributions received from Rockies Express in excess of
cumulative earnings recognized.
Financing Activities. Cash flows provided by financing activities were $321.7 million for the year ended December 31,
2018, primarily driven by:
•
•
proceeds of $500.0 million from the issuance of TEP's 2023 Notes; and
net borrowings under the revolving credit facilities of $417.0 million.
These financing cash inflows were partially offset by cash outflows of:
•
•
•
distributions to noncontrolling interests of $327.6 million, consisting of Tallgrass Equity distributions to the Exchange
Right Holders of $223.7 million, distributions to TEP unitholders of $97.7 million, and distributions to Deeprock
Development and Pony Express noncontrolling interests of $6.2 million;
dividends paid to Class A shareholders of $206.4 million; and
cash outflows of $50.0 million for the acquisition of an additional 2% membership interest in Pony Express.
Cash flows provided by financing activities were $327.3 million for the year ended December 31, 2017, primarily driven
by:
•
•
proceeds from TEP's issuance of $1.1 billion in aggregate principal amount of 2024 and 2028 Notes; and
net cash proceeds of $112.4 million from the issuance of 2,341,061 TEP common units under its Equity Distribution
Agreements.
These cash inflows were partially offset by cash outflows of:
•
•
•
•
•
•
net repayments under the revolving credit facilities of $356.0 million;
distributions to noncontrolling interests of $317.1 million, consisting of distributions to TEP unitholders of $185.7
million, Tallgrass Equity distributions to the Exchange Right Holders of $125.2 million, and distributions to Pony
Express noncontrolling interests of $6.2 million;
dividends paid to Class A shareholders of $73.3 million;
$72.4 million for the exercise of the remainder of the call option granted by TD covering 1,703,094 TEP common
units;
$35.3 million for the 736,262 TEP common units repurchased from TD; and
deferred financing costs of $22.4 million from the issuance of the 2024 and 2028 Notes and the amendment to TEP's
revolving credit facility.
79
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Operating Activities. Cash flows provided by operating activities were $571.4 million and $413.3 million for the years
ended December 31, 2017 and 2016, respectively. The increase in net cash flows provided by operating activities of $158.1
million was primarily driven by a $182.7 million increase in distributions received from Rockies Express as a result of the Ultra
settlement received in July 2017 as well as our increased membership interest during the year ended December 31, 2017.
Investing Activities. Cash flows used in investing activities were $898.5 million for the year ended December 31, 2017.
Investing cash outflows for the year ended December 31, 2017 were primarily driven by 2017 acquisitions, capital
expenditures, and contributions to Rockies Express, as discussed above.
Cash flows used in investing activities were $595.5 million for the year ended December 31, 2016, primarily driven by:
•
•
•
•
cash outflows of $436.0 million for the acquisition of a 25% membership interest in Rockies Express;
capital expenditures of $84.5 million, primarily due to post in-service spending on Pony Express System projects, the
Pipeline Integrity Management Program at Trailblazer, and costs associated with construction of the Buckingham
Terminal;
contributions to unconsolidated investments in the amount of $50.1 million, primarily to fund costs associated with the
Zone 3 Capacity Enhancement project at Rockies Express; and
cash outflows of $49.1 million for a portion of the acquisition of an additional 31.3% membership interest in Pony
Express, the remainder of which is classified as a financing activity as discussed below.
These cash outflows were partially offset by $24.1 million of distributions received from Rockies Express in excess of
cumulative earnings recognized.
Financing Activities. Cash flows provided by financing activities were $327.3 million for the year ended December 31,
2017, primarily driven by proceeds from the issuance of the 2024 and 2028 Notes and issuance of TEP common units, partially
offset by net repayments under the revolving credit facilities, distributions to noncontrolling interests, dividends paid to Class A
shareholders, the partial exercise of the call option granted by TD, the repurchase of common units from TD, and payments for
deferred financing costs, as discussed above.
Cash flows provided by financing activities were $182.5 million for the year ended December 31, 2016, primarily driven
by:
•
•
•
•
•
proceeds from TEP's issuance of $400.0 million in aggregate principal amount of 2024 Notes;
net cash proceeds of $337.7 million from the issuance of 7,696,708 TEP common units under its Equity Distribution
Agreements;
net borrowings under the TEP revolving credit facility of $262.0 million;
net cash proceeds of $90.0 million from TEP's issuance of 2,416,987 common units representing limited partnership
interests in a private placement transaction; and
contributions from TD of $17.9 million, which consisted of contributions from TD to TEP in order to indemnify TEP
for any out of pocket costs incurred between April 1, 2014 and April 1, 2017 related to repairing or remediating the
Trailblazer Pipeline, as discussed further in Note 19 – Legal and Environmental Matters.
These cash inflows were partially offset by cash outflows of:
•
•
•
•
$425.9 million for the portion of the acquisition of an additional 31.3% membership interest in Pony Express which
exceeds the cumulative capital spending on the underlying assets acquired;
distributions to noncontrolling interests of $249.1 million, consisting of distributions to TEP unitholders of $145.1
million, Tallgrass Equity distributions to the Exchange Right Holders of $97.5 million, and distributions to Pony
Express and Water Solutions noncontrolling interests of $6.5 million;
$204.6 million for TEP's partial exercise of the call option granted by TD covering 4,814,906 TEP common units; and
dividends paid to TGE Class A shareholders of $42.5 million.
80
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" above.
Our dividend for the three months ended December 31, 2018, in the amount of $0.5200 per Class A share, or $81.3
million in the aggregate, was announced on January 15, 2019 and will be paid on February 14, 2019 to Class A shareholders of
record on January 31, 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 $270
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:
Year Ended December 31,
2018
2017
(in thousands)
2016
Maintenance capital expenditures ....................... $
Expansion capital expenditures...........................
Total capital expenditures incurred ................ $
20,956
353,672
374,628
$
$
14,822
135,604
150,426
$
$
11,323
44,348
55,671
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 $21.0 million for the year ended December 31, 2018 from $14.8 million for the year ended December 31, 2017
is primarily driven by increased expenditures in the Corporate and Other and Gathering, Processing & Terminalling segments.
Maintenance capital expenditures for the year ended December 31, 2018 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
as discussed in Note 3 – Acquisitions and Dispositions. 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 $353.7 million for the year
ended December 31, 2018 compared to $135.6 million for the year ended December 31, 2017. Expansion capital expenditures
for the year ended December 31, 2018 consisted primarily of spending on the Cheyenne Connector, additional water gathering
infrastructure located in North Dakota, PLT, a 55-mile extension on the Pony Express system, construction of the Buckingham
Terminal expansion, construction of the Guernsey, Natoma, and Grasslands Terminals, and pipe replacement and remediation
work on the Trailblazer Pipeline system as discussed in Note 19 – Legal and Environmental Matters. Expansion capital
expenditures for the year ended December 31, 2017 consisted primarily of spending on an additional freshwater connection at
Water Solutions, construction of the Grasslands Terminal and the Natoma Terminal, a connection to a third-party refinery
complex on the Pony Express System, and a 55-mile extension on the Pony Express System.
The increase in maintenance capital expenditures to $14.8 million for the year ended December 31, 2017 from $11.3
million for the year ended December 31, 2016 is primarily driven by increased expenditures in the Crude Oil Transportation
and Gathering, Processing & Terminalling segments. Expansion capital expenditures were $135.6 million for the year ended
December 31, 2017 compared to $44.3 million for the year ended December 31, 2016. Expansion capital expenditures for
81
the year ended December 31, 2017 consisted primarily of spending at Water Solutions, the Grasslands Terminal and the Natoma
Terminal, and the Pony Express system, as discussed above. Expansion capital expenditures for the year ended December 31,
2016 consisted primarily of post in-service spending on Pony Express System projects and costs associated with construction of
the Buckingham Terminal.
During the years ended December 31, 2018, 2017, and 2016, we invested cash in unconsolidated affiliates, including
Rockies Express, Iron Horse, and BNN Colorado prior to our consolidation of BNN Colorado in December 2018, of $473.9
million, $45.9 million, and $50.1 million, respectively, to fund our share of capital projects, including (i) a special contribution
of approximately $412.5 million to fund our portion of the repayment of Rockies Express' $550 million of 6.85% senior notes
due July 15, 2018 and (ii) an initial contribution of $3.5 million to Iron Horse, a newly formed unconsolidated affiliate in
February 2018. In connection with our 51% membership interest in Powder River Gateway effective January 1, 2019, we made
commitments to fund our proportionate share of the remaining cost to construct the Iron Horse pipeline, estimated at $25.4
million.
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
Following is a summary of our contractual cash obligations in future periods, representing amounts that were fixed and
determinable as of December 31, 2018:
Payments Due By Period
Contractual Obligations
Debt obligations (1)....................................................
Interest on debt obligations (2)...................................
Operating lease and service contract obligations (3) .
Capital lease obligations (4).......................................
Land site lease and right-of-way (5) ..........................
Other purchase commitments (6) ...............................
Total
Total
Less Than 1
Year
1-3 Years
(in thousands)
3-5 Years
More Than
5 Years
$ 3,224,000
$
— $
— $ 1,724,000
$ 1,500,000
900,065
3,230
20,015
6,029
95,422
158,624
1,074
449
744
53,098
317,391
228,342
195,708
1,405
898
1,408
17,875
387
898
1,088
11,218
364
17,770
2,789
13,231
$ 4,248,761
$
213,989
$
338,977
$ 1,965,933
$ 1,729,862
(1) Debt obligations at December 31, 2018 consisted of borrowings under the TEP revolving credit facility and the Senior
Notes. For additional information, see Note 10 – Long-term Debt.
(2)
Interest on debt obligations is estimated using current borrowings and interest rates as of December 31, 2018. For
additional information, see Note 10 – Long-term Debt.
(3) Operating leases and service contracts consist of leases for office space and equipment. For additional information, see
Note 13 – Commitments & Contingent Liabilities.
(4) Capital lease obligations consist of the PLT land site lease. For additional information, see Note 13 – Commitments &
Contingent Liabilities.
(5) Land site lease and right-of-way contracts consist of payments to landowners, primarily in our Crude Oil Transportation
and Natural Gas Transportation segments. For additional information, see Note 13 – Commitments & Contingent
Liabilities.
(6) Other purchase commitments primarily relate to planned non-reimbursable capital expenditures and operating and
maintenance expenditures.
All of our employees are employed by Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018,
Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings. In connection with the closing of the TEP
initial public offering on May 17, 2013, TEP and TEP GP entered into an Omnibus Agreement with Tallgrass Energy Holdings
and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things,
TEP will reimburse Tallgrass Energy Holdings and its affiliates for all expenses they incur and payments they make on TEP's
82
behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain
centralized corporate functions performed by Tallgrass Energy Holdings and its affiliates, including legal, accounting, cash
management, insurance administration and claims processing, risk management, health, safety and environmental, information
technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the
closing of the TGE initial public offering on May 12, 2015 (the "TGE IPO"), TGE entered into an Omnibus Agreement (the
"TGE Omnibus Agreement") with Tallgrass Energy GP, LLC (formerly known as TEGP Management, LLC), Tallgrass Equity
and Tallgrass Energy Holdings. Effective July 1, 2018, Tallgrass Management was contributed to Tallgrass Equity in
connection with the TEP Merger. As a result, the costs of employer and director compensation and benefits are now incurred
directly by Tallgrass Equity.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Estimates
Our significant accounting policies and the anticipated impact of recently issued accounting standards are described in
Note 2 – Summary of Significant Accounting Policies. Management's discussion and analysis of financial condition and results
of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of
these financial statements requires management to make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The accounting policies
discussed below are considered by management to be critical to an understanding of our financial statements as their
application places the most significant demands on management's judgment. Due to the inherent uncertainties involved with
this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on our
results of operations, equity or cash flows. For additional information concerning our other accounting policies, please read the
notes to the financial statements included in this report.
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Assumptions
Business Combinations
We allocate the cost of each
acquired entity to the assets
and liabilities assumed
based on their estimated
fair values at the date of
acquisition. If the initial
accounting for the business
combination is incomplete
when the combination
occurs, an estimate will be
recorded. We are required
to recognize intangible
assets separately from
goodwill. Any excess
purchase price after the fair
value of the net tangible
and identifiable intangible
assets acquired, as well as
noncontrolling interest, if
applicable, is determined is
recognized as goodwill.
We measure the fair value of assets acquired
and liabilities assumed in business
combinations using widely accepted valuation
techniques, primarily discounted cash flow, cost
approach, and market multiple analyses. These
types of analyses require us to make
assumptions and estimates regarding industry
and economic factors and the profitability of
future business strategies. These analyses
require management to apply significant
judgment in estimating future cash flows as
well as fair values of individual assets,
including forecasting useful lives of the assets,
assessing the probability of different outcomes,
including anticipated volumes, contract
renewals and changes in our regulated rates, and
selecting the discount rate that reflects the risk
inherent in future cash flows.
If estimates or assumptions used to
complete the purchase price allocation and
estimate the fair value of acquired assets,
liabilities and noncontrolling interests
significantly differed from assumptions
made, the allocation of purchase price
between goodwill, intangibles,
noncontrolling interests, equity method
investments and property, plant, and
equipment could significantly differ. Such a
difference would impact future earnings
through depreciation and amortization
expense. In addition, if forecasts supporting
the valuation of the intangible assets or
goodwill are not achieved, impairments
could arise. Further, if customer
relationships terminate prior to the
expected useful life, we will be required to
record a charge to operations to write-off
any remaining unamortized balance of the
intangible asset assigned to that customer.
83
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Assumptions
Using the impairment review methodology
described herein, we have not recorded any
impairment charges on long-lived assets
during the year ended December 31, 2018.
If actual results are not consistent with our
assumptions and estimates or our
assumptions and estimates change due to
new information, we may be exposed to an
impairment charge. A prolonged period of
lower commodity prices may adversely
affect our estimate of future operating
results, which could result in future
impairment due to the potential impact on
our operations and cash flows.
If our assumptions are not appropriate, or
future events indicate that our goodwill is
impaired, our net income would be
impacted by the amount by which the
carrying value exceeds the fair value of the
reporting unit, to the extent of the balance
of goodwill. A prolonged period of lower
commodity prices may adversely affect our
estimate of future operating results, which
could result in future goodwill impairment
for reporting units due to the potential
impact on our operations and cash flows.
We completed our impairment testing of
goodwill in the third quarter of 2018 using
the methodology described herein, and
determined there was no impairment.
We review our long-lived assets for impairment
whenever events or changes in circumstances
indicate that the carrying amount of an asset
may not be recoverable. Our impairment
analyses require management to apply judgment
in estimating future cash flows as well as asset
fair values, including forecasting useful lives of
the assets, assessing the probability of different
outcomes, including anticipated volumes,
contract renewals and changes in our regulated
rates, and selecting the discount rate that
reflects the risk inherent in future cash flows. If
the carrying value is not recoverable, we assess
the fair value of long-lived assets using a
discounted cash flow model and other
commonly accepted techniques.
Impairment of Long-lived Assets
We periodically evaluate
whether the carrying value
of long-lived assets has
been impaired when
circumstances indicate the
carrying value of those
assets may not be
recoverable. This
evaluation is based on
undiscounted cash flow
projections expected to be
realized over the remaining
useful life of the primary
asset. The carrying amount
is not recoverable if it
exceeds the sum of
undiscounted cash flows
expected to result from the
use and eventual disposition
of the asset. If the carrying
value is not recoverable, the
impairment loss is
measured as the excess of
the asset's carrying value
over its fair value.
Impairment of Goodwill
We evaluate goodwill for
impairment annually in the
third quarter, and whenever
events or changes in
circumstances indicate it is
more likely than not that the
fair value of a reporting
unit is less than its carrying
amount.
We use either the qualitative assessment option
or proceed directly to the quantitative
impairment test depending on facts and
circumstances of the reporting unit, including
the forecasted useful lives of the assets, the
probability of different outcomes, including
anticipated volumes, contract renewals and
changes in our regulated rates, and the discount
rate that reflects the risk inherent in future cash
flows. When quantitative assessments are made,
we determine fair value using widely accepted
valuation techniques, primarily discounted cash
flow and market multiple analyses. These types
of analyses require us to make assumptions and
estimates regarding industry and economic
factors and the profitability of future business
strategies. Our impairment analyses require
management to apply judgment in estimating
future cash flows. We incorporate current
market information, as well as historical and
other factors, into our forecasted commodity
prices. Key assumptions in the analysis include
the use of an appropriate discount rate, terminal
year multiples, and estimated future cash flows,
including an estimate of operating and general
and administrative costs. It is our policy to
conduct impairment testing based on our current
business strategy in light of present industry and
economic conditions, as well as future
expectations.
84
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Assumptions
We review our deferred revenue (contract
liabilities) at each balance sheet date to
determine the probability that our customers
will exercise their remaining rights. We
recognize revenue when the probability
becomes remote that the customer will exercise
its remaining rights. Our evaluation requires
management to apply judgment in contract
renewal assumptions and estimating future
system capacity and the ability of our customers
to utilize that capacity.
If actual results are not consistent with our
assumptions and estimates, or our
assumptions and estimates change due to
new information, the timing of our revenue
recognition with respect to deferred
revenue could be impacted and we may
experience material changes in revenue.
Revenue Recognition
The majority of our revenue
is derived from long-term
contracts that can span
several years. Accounting
for long-term contracts
involves the use of various
techniques to estimate total
contract revenue and
determine the timing of
revenue recognition. We
periodically evaluate our
estimates with respect to the
probability of our customers
exercising their rights and
recognize revenue
associated with contract
liabilities when the
probability becomes remote
that the customer will
exercise its remaining
rights.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
For the year ended December 31, 2018, the percentage of our firm fee, volumetric fee, and commodity exposed Adjusted
EBITDA was 90%, 6%, and 4%, respectively. Historically, we have had a limited amount of direct commodity price exposure
related to natural gas collected for electrical compression costs at TIGT, 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.
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.
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 December 31, 2018, assuming a parallel shift in the forward curve:
Fair Value
Effect of 10%
Price Increase
(in thousands)
Effect of 10%
Price Decrease
Crude oil derivative contract assets (1)......................................... $
Crude oil derivative contract liabilities (1).................................... $
3,526
$
(1,642) $
(1,221) $
(424) $
1,221
424
(1) Represents the net forward sale of 362,000 barrels of crude oil in our Gathering, Processing & Terminalling segment
which will settle throughout 2019.
Interest Rate Risk
As described in Note 10 – Long-term Debt, on July 26, 2018, in connection with the Amendment to TEP's Credit
Agreement, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility.
85
As of December 31, 2018, TEP has issued $2.0 billion of Senior Notes and has a $2.25 billion revolving credit facility with
borrowings of $1.22 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 (previously 0.50% to 1.50% prior to the
Amendment) and 1.25% to 2.25% for reserve adjusted Eurodollar rate borrowings (previously 1.50% to 2.50% prior to the
Amendment), based upon TEP's total leverage ratio.
We do not currently hedge the interest rate risk on our borrowings under TEP's 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 $0.6 million based on our outstanding debt under TEP's revolving credit facility as of December 31,
2018.
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 December 31, 2018.
We also have indirect credit risk exposure with respect to our investment in Rockies Express. See Item 1A.—Risk Factors
for additional information.
86
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Board of Directors of Tallgrass Energy GP, LLC, the general partner of Tallgrass Energy, LP, and the shareholders of
Tallgrass Energy, LP
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Tallgrass Energy, LP and its subsidiaries (the "Partnership")
as of December 31, 2018 and 2017, and the related consolidated statements of income, equity and cash flows for each of the three
years in the period ended December 31, 2018, including the related notes (collectively referred to as the "consolidated financial
statements"). We also have audited the Partnership's internal control over financial reporting as of December 31, 2018, based on
criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position
of the Partnership as of December 31, 2018 and 2017, and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of
America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 2 and 12 to the consolidated financial statements, Rockies Express Pipeline LLC, an investment of the
Partnership accounted for under the equity method, changed the manner in which it accounts for revenue in 2018.
Basis for Opinions
The Partnership's management is responsible for these consolidated financial statements, for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in
Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express
opinions on the Partnership's consolidated financial statements and on the Partnership's internal control over financial reporting
based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United
States) ("PCAOB") and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether
due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement
of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.
Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial
reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits
also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
87
being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 8, 2019
We have served as the Partnership's auditor since 2015.
88
TALLGRASS ENERGY, LP
CONSOLIDATED BALANCE SHEETS
December 31, 2018 December 31, 2017
Current Assets:
ASSETS
Cash and cash equivalents ..................................................................................... $
Accounts receivable, net........................................................................................
Inventories .............................................................................................................
Prepayments and other current assets....................................................................
Total Current Assets..........................................................................................
Property, plant and equipment, net.............................................................................
Goodwill.....................................................................................................................
Intangible assets, net ..................................................................................................
Unconsolidated investments.......................................................................................
Deferred financing costs, net......................................................................................
Deferred tax asset .......................................................................................................
Deferred charges and other assets ..............................................................................
Total Assets................................................................................................................. $
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable................................................................................................... $
Accrued taxes ........................................................................................................
Accrued interest.....................................................................................................
Accrued liabilities..................................................................................................
Deferred revenue ...................................................................................................
Other current liabilities..........................................................................................
Total Current Liabilities....................................................................................
Long-term debt, net ....................................................................................................
Other long-term liabilities and deferred credits .........................................................
Total Long-term Liabilities...............................................................................
Commitments and Contingencies
Equity:
Class A Shareholders (156,311,986 and 58,085,002 shares outstanding at
December 31, 2018 and 2017, respectively) .........................................................
Class B Shareholders (123,887,893 and 99,154,440 shares outstanding at
December 31, 2018 and 2017, respectively) .........................................................
Total Partners' Equity........................................................................................
Noncontrolling interests (a) ....................................................................................
Total Equity ......................................................................................................
(in thousands)
9,596
$
236,097
34,316
11,816
291,825
2,802,429
421,983
227,103
1,861,686
10,990
273,531
3,962
5,893,509
$
2,593
119,955
21,609
13,165
157,322
2,394,337
404,838
97,731
909,531
12,563
312,997
2,694
4,292,013
201,512
$
104,224
20,734
39,217
23,287
111,095
42,910
438,755
3,205,958
31,688
3,237,646
1,725,537
—
1,725,537
491,571
2,217,108
19,272
25,167
10,540
88,471
11,202
258,876
2,292,993
18,965
2,311,958
48,613
—
48,613
1,672,566
1,721,179
4,292,013
Total Liabilities and Equity ........................................................................................ $
5,893,509
$
(a) See Note 11 - Partnership Equity for a complete description of our noncontrolling interests.
The accompanying notes are an integral part of these consolidated financial statements.
89
TALLGRASS ENERGY, LP
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
2018
2017
(in thousands, except per unit amounts)
2016
Revenues:
Crude oil transportation services ......................................................... $
Natural gas transportation services......................................................
Sales of natural gas, NGLs, and crude oil ...........................................
Processing and other revenues.............................................................
Total Revenues................................................................................
Operating Costs and Expenses:
Cost of sales.........................................................................................
Cost of transportation services ............................................................
Operations and maintenance................................................................
Depreciation and amortization ............................................................
General and administrative..................................................................
Taxes, other than income taxes............................................................
Contract termination............................................................................
(Gain) loss on disposal of assets..........................................................
Total Operating Costs and Expenses ..............................................
Operating Income .....................................................................................
Other Income (Expense):
Equity in earnings of unconsolidated investments ..............................
Interest expense, net ............................................................................
Gain on remeasurement of unconsolidated investment.......................
Other (expense) income, net................................................................
Total Other Income (Expense)........................................................
Net income before tax ..............................................................................
Deferred income tax expense ..............................................................
Net income ...............................................................................................
Net income attributable to noncontrolling interests ............................
Net income (loss) attributable to TGE ..................................................... $
Allocation of income:
Net income (loss) attributable to TGE................................................. $
Predecessor operations interest in net income.....................................
Net income (loss) attributable to TGE, excluding predecessor
operations interest................................................................................
Basic net income (loss) per Class A share........................................... $
Diluted net income (loss) per Class A share........................................ $
Basic average number of Class A shares outstanding .........................
Diluted average number of Class A shares outstanding ......................
398,334
$
345,733
$
126,894
168,586
99,445
793,259
114,815
53,068
72,460
110,862
70,656
31,810
—
(11,043)
442,628
350,631
306,819
(133,319)
—
(751)
172,749
523,380
(55,709)
467,671
(330,544)
137,127
137,127
—
137,127
1.27
1.27
107,586
109,817
122,364
108,503
79,298
655,898
91,213
46,200
62,069
90,800
65,536
28,832
—
(599)
384,051
271,847
237,110
(89,348)
9,728
3,106
160,596
432,443
(208,458)
223,985
(352,714)
(128,729) $
(128,729) $
—
(128,729)
(2.22) $
(2.22) $
58,076
58,076
$
$
$
$
374,949
119,962
77,123
39,628
611,662
71,650
47,669
55,070
86,247
57,298
25,400
8,061
1,849
353,244
258,418
54,531
(45,601)
—
432
9,362
267,780
(17,741)
250,039
(216,250)
33,789
33,789
(6,995)
26,794
0.55
0.55
48,856
48,889
The accompanying notes are an integral part of these consolidated financial statements.
90
TALLGRASS ENERGY, LP
CONSOLIDATED STATEMENTS OF EQUITY
Partners' Capital
Class A Shares
Class B Shares
Predecessor
Equity
Shares
Amount
Amount
Noncontrolling
Interests
Total Equity
71,564
6,995
47,725
—
$ 422,310
26,794
— $
—
1,599,188
216,250
$ 2,093,062
250,039
Shares
(in thousands)
109,504
$
—
Balance at January 1, 2016 ................................... $
Net Income .........................................................
Acquisition of additional 31.3% membership
interest in Pony Express .....................................
Issuance of TEP units to public, net of offering
costs ....................................................................
Distributions to noncontrolling interests ............
Partial exercise of call option .............................
Issuance of TEP common units in a private
placement, net of offering costs .........................
Deferred tax asset ...............................................
Dividends paid to Class A Shareholders.............
Contributions from noncontrolling interests ......
Noncash compensation expense.........................
Acquisition of membership interest in BNN......
Contributions from TD.......................................
Costs associated with equity issuance ................
TEP LTIP units tendered by employees to
satisfy tax withholding obligations.....................
Distribution of excess TGE IPO proceeds to
Exchange Right Holders.....................................
Contributions from Predecessor Entities, net .....
Conversion of Class B shares to Class A shares.
Balance at December 31, 2016 ............................. $
Acquisition of Terminals and NatGas ................
Net income .........................................................
Issuance of TEP units to public, net of offering
costs ....................................................................
Dividends paid to Class A Shareholders.............
Noncash compensation expense.........................
Issuance of TGE Class A shares under TGE
LTIP plan ............................................................
TEP LTIP units tendered by employees to
satisfy tax withholding obligations.....................
Partial exercise of call option .............................
Repurchase of TEP common units from TD ......
Acquisition of additional 24.99% membership
interest in Rockies Express.................................
Acquisition of additional 40% membership
interest in Deeprock Development .....................
Acquisition of noncontrolling interests ..............
Contributions from TD.......................................
Contributions from noncontrolling interests ......
Distributions to noncontrolling interests ............
Balance at December 31, 2017 ............................. $
Cumulative effect of ASC 606 implementation .
Net income .........................................................
Dividends paid to Class A Shareholders.............
Noncash compensation expense.........................
Acquisition of additional TEP common units
from TD..............................................................
Issuance of Tallgrass Equity units ......................
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3,736
—
82,295
(82,295)
—
— (255,617)
—
—
—
—
—
—
—
—
—
—
—
—
28,762
—
(27,312)
7,592
86,766
(42,499)
—
1,448
(464)
5,827
(986)
(51)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(173,422)
(429,039)
308,909
(249,142)
(211,315)
337,671
(249,142)
(238,627)
82,417
—
—
9,304
7,879
(5,536)
12,067
—
90,009
86,766
(42,499)
9,304
9,327
(6,000)
17,894
(986)
(447)
(498)
(1,603)
—
—
10,350
$ 250,967
58,075
—
(21,314)
— (128,729)
—
—
— (10,350)
99,154
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
10
—
—
—
—
—
—
—
—
—
58,085
$
11,353
(73,321)
1,603
—
(1,317)
(12,052)
(3,618)
23,522
—
669
850
—
—
48,613
4,588
—
—
137,127
— (206,431)
6,296
—
—
—
—
—
—
—
—
—
—
—
—
—
—
99,154
—
—
—
—
—
—
(62,223)
—
10,758
—
$
$
—
—
—
— $
—
—
—
—
—
1,596,152
(36,391)
352,714
(1,603)
3,736
—
$ 1,929,414
(140,000)
223,985
—
—
—
—
—
—
—
—
101,067
—
10,390
112,420
(73,321)
11,993
—
—
(11,616)
(72,890)
(31,717)
(12,933)
(84,942)
(35,335)
40,159
63,681
—
—
—
—
—
— $
45,869
(7,109)
1,451
1,589
(317,102)
1,672,566
45,869
(6,440)
2,301
1,589
(317,102)
$ 1,721,179
—
—
—
—
—
—
39,543
330,544
—
3,197
(189,520)
644,782
44,131
467,671
(206,431)
9,493
(251,743)
644,782
The accompanying notes are an integral part of these consolidated financial statements.
91
TALLGRASS ENERGY, LP
CONSOLIDATED STATEMENTS OF EQUITY
Partners' Capital
Predecessor
Equity
Class A Shares
Class B Shares
Shares
Amount
Shares
(in thousands)
Amount
Noncontrolling
Interests
Total Equity
Acquisition of additional 25.01% membership
interest in Rockies Express.................................
Acquisition of additional 2% membership
interest in Pony Express .....................................
Consolidation of Deeprock North ......................
Consolidation of BNN Colorado........................
Contributions from noncontrolling interests ......
Distributions to noncontrolling interests ............
Issuance of TEP units to the public, net of
offering costs ......................................................
TEP LTIP units tendered by employees to
satisfy tax withholding obligations.....................
Issuance of Class A shares under LTIP plan, net
of units tendered by employees to satisfy tax
withholding obligations......................................
Conversion of Class B shares to Class A shares.
Deferred tax asset ...............................................
Acquisition of additional TEP common units ....
Issuance of Class A shares..................................
Balance at December 31, 2018 ............................. $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
34,116
16,797
(5,268)
—
—
—
—
(98)
(190)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
74,421
108,537
(44,732)
31,843
10,138
1,787
(327,578)
(50,000)
31,843
10,138
1,787
(327,578)
(279)
(377)
(1,531)
(1,721)
—
—
—
—
—
95,386
— 156,312
(30)
19
(8,717)
2,822
—
15,427
— (351,431)
2,113,758
$1,725,537
—
(2,822)
—
—
—
123,887
$
—
—
—
—
—
— $
—
8,717
—
(1,762,327)
—
491,571
(30)
—
15,427
(2,113,758)
2,113,758
$ 2,217,108
The accompanying notes are an integral part of these consolidated financial statements.
92
TALLGRASS ENERGY, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash Flows from Operating Activities:
Net income........................................................................................... $
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation and amortization........................................................
Equity in earnings of unconsolidated investments .........................
Distributions from unconsolidated investments .............................
Deferred income tax expense..........................................................
Gain on remeasurement of unconsolidated investment ..................
Other noncash items, net.................................................................
Changes in components of working capital:
Accounts receivable and other........................................................
Accounts payable and accrued liabilities........................................
Deferred revenue ............................................................................
Other current assets and liabilities..................................................
Other operating, net .............................................................................
Net Cash Provided by Operating Activities .............................................
Cash Flows from Investing Activities:
Contributions to unconsolidated investments......................................
Capital expenditures ............................................................................
Acquisition of BNN North Dakota, net of cash acquired....................
Acquisition of NGL Water Solutions Bakken .....................................
Distributions from unconsolidated investments in excess of
cumulative earnings.............................................................................
Sale of Tallgrass Crude Gathering.......................................................
Acquisition of membership interest in PLT.........................................
Acquisition of membership interest in Pawnee Terminal....................
Acquisition of 38% membership interest in Deeprock North .............
Acquisition of Rockies Express membership interest .........................
Acquisition of Terminals and NatGas .................................................
Acquisition of Douglas Gathering System ..........................................
Acquisition of Deeprock Development, net of cash acquired.............
Acquisition of PRB Crude System ......................................................
Acquisition of Pony Express membership interest..............................
Other investing, net .............................................................................
Net Cash Used in Investing Activities......................................................
Cash Flows from Financing Activities:
Proceeds from issuance of long-term debt ..........................................
Borrowings (repayments) under revolving credit facilities, net..........
Distributions to noncontrolling interests .............................................
Dividends paid to Class A shareholders ..............................................
Acquisition of Pony Express membership interest..............................
Proceeds from public offering of TEP common units, net of offering
costs .....................................................................................................
Year Ended December 31,
2018
2017
2016
(in thousands)
467,671
$
223,985
$
250,039
117,430
(306,819)
306,934
55,709
—
(2,382)
(102,105)
112,474
17,547
(3,079)
9,145
672,525
(473,946)
(368,873)
(95,000)
(91,000)
80,213
50,046
(30,704)
(30,600)
(19,500)
—
—
—
—
—
—
(7,848)
(987,212)
500,000
417,000
(327,578)
(206,431)
(50,000)
98,537
(237,110)
237,192
208,458
(9,728)
9,226
(57,927)
84,731
27,283
(10,542)
(2,709)
571,396
(45,948)
(145,144)
—
—
94,038
(54,531)
54,449
17,741
—
9,711
2,835
10,684
33,815
(5,578)
95
413,298
(50,076)
(84,491)
—
—
69,434
24,120
—
—
—
—
(400,000)
(140,000)
(128,526)
(57,202)
(36,030)
—
(15,125)
(898,541)
1,103,750
(356,000)
(317,102)
(73,321)
—
—
—
—
—
(436,022)
—
—
—
—
(49,118)
48
(595,539)
400,000
262,000
(249,142)
(42,499)
(425,882)
—
112,420
337,671
The accompanying notes are an integral part of these consolidated financial statements.
93
TALLGRASS ENERGY, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Partial exercise of call option ..............................................................
Repurchase of TEP common units from TD .......................................
Payments for deferred financing costs ................................................
Proceeds from private placement of TEP common units, net of
offering costs .......................................................................................
Contribution from TD..........................................................................
Other financing, net .............................................................................
Net Cash Provided by Financing Activities .............................................
Net Change in Cash and Cash Equivalents ..............................................
Cash and Cash Equivalents, beginning of period.....................................
Cash and Cash Equivalents, end of period ............................................... $
—
—
—
—
—
(11,301)
321,690
7,003
2,593
9,596
$
(72,381)
(35,335)
(22,375)
—
—
(12,377)
327,279
134
2,459
2,593
$
(204,634)
—
(10,380)
90,009
17,894
7,429
182,466
225
2,234
2,459
Supplemental Disclosures:
Cash payments for interest, net ........................................................... $
(114,026) $
(72,698) $
(34,367)
Schedule of Noncash Investing and Financing Activities:
Acquisition of additional TEP common units (a)(b)............................... $
Issuance of Class A shares (a) ............................................................... $
Issuance of Tallgrass Equity units (b) ................................................... $
Acquisition of Rockies Express membership interest (b) ..................... $
Contribution of 38% membership interest in Deeprock North to
Deeprock Development ....................................................................... $
Issuance of noncontrolling interests in Deeprock Development in
exchange for 62% membership interest in Deeprock North ............... $
TEP common units issued as partial consideration to acquire
additional 9% membership interest in Deeprock Development .......... $
Increase in accrual for payment of property, plant and equipment ..... $
(2,365,501) $
$
2,113,758
644,782
$
(393,039) $
(19,500) $
(31,843) $
— $
— $
— $
— $
— $
— $
— $
5,755
$
6,617
8,975
$
$
—
—
—
—
—
—
—
—
(a) Represents the acquisition of additional TEP common units in exchange for Class A shares associated with the Merger
Agreement as discussed in Note 1 – Description of Business.
(b) Represents the issuance of Tallgrass Equity units associated with our acquisition of a 25.01% membership interest in
Rockies Express and an additional 5,619,218 TEP common units as discussed in Note 3 – Acquisitions and Dispositions.
The accompanying notes are an integral part of these consolidated financial statements.
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TALLGRASS ENERGY, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business
Tallgrass Energy, LP ("TGE") formerly known as Tallgrass Energy GP, LP, is a limited partnership that owns, operates,
acquires and develops midstream energy assets in North America and has elected to be treated as a corporation for U.S. federal
income tax purposes. "We," "us," "our" and similar terms refer to TGE together with its consolidated subsidiaries.
Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries,
including Tallgrass Equity, LLC ("Tallgrass Equity"), in which we directly own an approximate 55.79% membership interest as
of December 31, 2018. We are located in and provide services to certain key United States hydrocarbon basins, including the
Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime,
Eagle Ford, Bakken, Marcellus, and Utica shale formations.
Our reportable business segments are:
• Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and an
integrated natural gas storage facility;
• Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and
• Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities;
crude oil storage and terminalling facilities; the provision of water business services primarily to the oil and gas
exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs.
Natural Gas Transportation. We provide natural gas transportation and storage services for customers in the Rocky
Mountain, Midwest and Appalachian regions of the United States through: (1) our 75% membership interest in Rockies
Express Pipeline LLC ("Rockies Express"), which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline
system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio (the "Rockies Express Pipeline"), and our
100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas"), which operates the Rockies Express Pipeline, (2)
the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in
Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and (3) the Trailblazer Pipeline system, a FERC-
regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer
Pipeline").
Crude Oil Transportation. We provide crude oil transportation to customers in Wyoming, Colorado, Kansas, and the
surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated crude oil
pipeline commencing in both Guernsey, Wyoming and Weld County, Colorado and terminating in Cushing, Oklahoma (the
"Pony Express System"). In the second quarter of 2018, Pony Express placed into service an extension of the system from an
additional origin point in Weld County, Colorado located near Platteville, Colorado.
Gathering, Processing & Terminalling. We provide natural gas gathering and processing services for customers in
Wyoming through: (1) a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System"), (2) natural
gas processing facilities in Casper and Douglas, and (3) a natural gas treating facility at West Frenchie Draw. We also provide
NGL transportation services in Northeast Colorado and Wyoming. We perform water business services, including freshwater
transportation and produced water gathering and disposal, in Colorado, Texas, Wyoming, and North Dakota through BNN
Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through our 100% membership
interest in Tallgrass Terminals, LLC ("Terminals"), which owns and operates crude oil terminals in Colorado, Oklahoma, and
Kansas. The Gathering, Processing & Terminalling segment also includes Stanchion Energy, LLC ("Stanchion"), which
transacts in crude oil.
The term "Terminals Predecessor" refers to Terminals and the term "NatGas Predecessor" refers to NatGas prior to their
acquisition by Tallgrass Energy Partners, LP ("TEP") on January 1, 2017. Terminals Predecessor and NatGas Predecessor are
collectively referred to as the Predecessor Entities, as further discussed in Note 2 – Summary of Significant Accounting
Policies. Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entities. Predecessor
Equity as presented in the consolidated financial statements represents the capital account activity of Terminals Predecessor and
NatGas Predecessor prior to January 1, 2017. For additional information regarding these acquisitions, see Note 3 – Acquisitions
and Dispositions.
Merger Agreement with Tallgrass Energy Partners, LP
TGE previously entered into a definitive Agreement and Plan of Merger, dated as of March 26, 2018 (the "Merger
Agreement"), with TEP, a Delaware limited partnership, Tallgrass MLP GP, LLC, a Delaware limited liability company and the
general partner of TEP ("TEP GP"), and Razor Merger Sub, LLC, a Delaware limited liability company. The merger transaction
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contemplated by the Merger Agreement (the "TEP Merger") was completed effective June 30, 2018, and as a result, 47,693,097
TEP common units held by the public were converted into the right to receive Class A shares of TGE at an exchange ratio of
2.0 Class A shares for each outstanding TEP common unit, TEP's incentive distribution rights were cancelled, TEP's common
units are no longer publicly traded, and 100% of TEP's equity interests are now owned by Tallgrass Equity and its subsidiaries.
The TEP Merger was accounted for as an acquisition of noncontrolling interest. Following consummation of the TEP Merger,
TGE changed its name from "Tallgrass Energy GP, LP" to "Tallgrass Energy, LP" and began trading on the New York Stock
Exchange under the ticker symbol "TGE" on July 2, 2018.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements and related notes were prepared in conformity with accounting
principles generally accepted in the United States of America ("GAAP"). 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.
As further discussed in Note 3 – Acquisitions and Dispositions, we closed the acquisition of Terminals and NatGas
effective January 1, 2017. As the acquisitions of Terminals and NatGas are considered transactions between entities under
common control, and a change in reporting entity, the financial information presented has been recast to include Terminals and
NatGas for all periods presented. Net equity contributions of the Predecessor Entities included in the consolidated financial
statements represent transfers of cash as a result of Tallgrass Development's ("TD") centralized cash management system prior
to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the
subsidiaries of TD. These loans were then periodically recorded as equity distributions.
The accompanying consolidated financial statements of TGE include historical cost-basis accounts of the assets of
Terminals and NatGas for the periods prior to January 1, 2017, the date we acquired Terminals and NatGas from TD, and
include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the
allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-
alone basis. TGE, TEP, and the Predecessor Entities are all considered "entities under common control" as defined under GAAP
and, as such, the transfers between the entities of the assets and liabilities have been recorded by TGE at historical cost.
The consolidated financial statements include the accounts of TGE and its subsidiaries and controlled affiliates. Significant
intra-entity items have been eliminated in the presentation. Net income or loss from consolidated subsidiaries that are not
wholly-owned by TGE is attributed to TGE and noncontrolling interests in accordance with the respective ownership interests.
A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount
of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the
entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the
obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to
consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant
to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. We have
presented separately in our consolidated balance sheets, to the extent material, the liabilities of our consolidated VIEs for which
creditors do not have recourse to our general credit. Our consolidated VIEs did not have material assets that could only be used
to settle specific obligations of the consolidated VIEs. Prior to June 29, 2018, both Tallgrass Equity and TEP were considered to
be VIEs under the applicable authoritative guidance and included in our consolidated results. As a result of the TEP Merger,
and changes in ownership and their respective partnership arrangements, Tallgrass Equity and TEP are no longer considered to
be VIEs. We continue to consolidate our membership interests in Tallgrass Equity and TEP through the voting interest model.
Use of Estimates
Certain amounts included in or affecting these 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.
Cash and Cash Equivalents
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash
equivalents.
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Net equity contributions of the Predecessor Entities included in the consolidated statements of cash flows represent
transfers of cash as a result of TD's centralized cash management systems prior to January 1, 2017 for Terminals and NatGas,
under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then
periodically recorded as equity distributions.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are carried at their estimated collectible amounts. We make periodic reviews and evaluations of the
appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments
are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are
determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $7.7
million and $0.5 million at December 31, 2018 and 2017, respectively.
Inventories
Inventories primarily consist of crude oil, materials and supplies, gas in underground storage, and natural gas liquids. As
discussed further under "Revenue Recognition" below, a loss allowance is factored into the crude oil tariffs to offset losses in
transit. As crude oil is transported, we earn oil for our services as pipeline loss allowance oil, or PLA, which we can then
sell. As PLA oil is accumulated, it is recorded as inventory at the lower of historical cost and net realizable value using the
average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical
deterioration and obsolescence. Natural gas liquids and gas in underground storage, sometimes referred to as working gas, are
recorded at the lower of historical cost and net realizable value using the average cost method. For additional information, see
"Gas in Underground Storage" below.
Accounting for Regulatory Activities
Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic
prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory
assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be
recovered from or refunded to customers through the ratemaking process. We recorded regulatory assets of approximately $3.2
million and $2.6 million included in "Prepayments and other current assets" and "Deferred charges and other assets" in the
consolidated balance sheets at December 31, 2018 and 2017, respectively. Regulatory assets at December 31, 2018 and
December 31, 2017 were primarily attributable to costs associated with fuel tracker assets at our regulated natural gas pipelines
as well as both Trailblazer's 2013 and 2018 Rate Case Filings and TIGT's 2015 Rate Case Filing. We recorded regulatory
liabilities of approximately $1.9 million and $2.3 million included in "Other current liabilities" in the consolidated balance
sheets at December 31, 2018 and 2017, respectively, related to fuel tracker liabilities at our regulated natural gas pipelines. For
further information regarding our rate case filings and fuel tracker balances, see Note 18 – Regulatory Matters.
Property, Plant and Equipment
Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as
payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs
directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized
and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs related to
the construction of assets, including internal labor costs, interest and engineering costs.
Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated
depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is
recorded in accumulated depreciation and/or the negative salvage liability discussed under "Depreciation and Amortization"
below, as appropriate, with no effect on current period earnings. Gains or losses are recognized upon retirement of non-
regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or
abandoned and costs of removal or salvage are expensed when incurred.
Intangible Assets
We establish identifiable intangible assets when they meet either the separability criterion or the contractual-legal criterion.
Contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as
drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets
arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section
of TIGT's natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational
and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil
conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years, the period of
expected future benefit. During 2018, we recognized additional intangible assets at Plaquemines Liquids Terminal, LLC
("PLT"), a newly formed subsidiary as discussed in Note 3 – Acquisitions and Dispositions, from the acquisition of permits,
97
designs, and other work-product related to the development and construction of a crude oil terminal facility in Louisiana. These
intangible assets will be amortized on a straight-line basis over a period of 35 years, the period of expected future benefit. Also,
during 2018, we recognized an intangible asset associated with customer relationships as part of our acquisition of NGL Water
Solutions Bakken, LLC as discussed in Note 3 – Acquisitions and Dispositions. The customer relationships are amortized on a
straight-line basis over a period of 8 years. Other intangible assets include customer contracts amortized on a straight-line basis
over a period of 2 - 14 years, based on the remaining term of the contracts at the time of acquisition.
Impairment of Long-Lived Assets
We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying
amount of an asset or asset group may not be recoverable. An impairment loss results when the estimated undiscounted future
net cash flows expected to result from the asset or asset group's use and its eventual disposition are less than its carrying
amount. We assess our long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived
asset or asset group is tested for impairment whenever events or changes in circumstances indicate its carrying amount may
exceed its fair value.
Examples of long-lived asset impairment indicators include:
•
•
•
•
•
•
a significant decrease in the market value of a long-lived asset or asset group;
a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its
physical condition;
a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or
asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the
rate-making process;
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction
of the long-lived asset or asset group;
a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or
forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and
a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of
significantly before the end of its previously estimated useful life.
When an impairment indicator is present, we first assess the recoverability of the long-lived assets by comparing the sum
of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset or asset group to its
carrying amount. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the asset or asset
group is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be
recognized.
Gas in Underground Storage
Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and
deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment.
We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our
storage services but do not reflect the value of third-party gas in the accompanying consolidated financial statements. We
occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas
inventory at the lower of cost and net realizable value.
Depreciation and Amortization
For non-regulated assets, we have elected to use the straight-line method of depreciation. For our regulated assets, we have
elected to compute depreciation using a composite method employed by applying a single depreciation rate to a group of assets
with similar economic characteristics. This composite method of depreciation approximates a straight-line method of
depreciation. The depreciation rates for our regulated natural gas pipeline assets include two components, one based on
economic service life (capital recovery) and one based on net costs of removal (negative salvage). The accumulated liability
related to negative salvage is classified as "Other long-term liabilities and deferred credits" in our consolidated balance sheets.
98
The rates of depreciation for the various classes of depreciable assets are as follows:
Crude oil pipelines .....................................................................................................................................
Natural gas pipelines ..................................................................................................................................
Gathering & processing assets ...................................................................................................................
Water business assets..................................................................................................................................
Terminal assets ...........................................................................................................................................
Replacement Gas Facilities (1) ....................................................................................................................
General & other ..........................................................................................................................................
Range of
Depreciation
Rates
2.8%
0.7% - 5.0%
2.2% - 5.0%
2.3% - 20.0%
1.8% - 2.8%
10.0%
2.9% - 25.0%
(1) Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities
necessary to maintain existing natural gas service on the TIGT System after having sold approximately 433 miles of
natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013.
Gas Imbalances
Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts
from and gas deliveries to interconnecting pipelines under various operational balancing and imbalance agreements. Gas
imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements.
Imbalances are valued at applicable average market index prices. Gas imbalances receivable and payable are included in
"Prepayments and other current assets" and "Other current liabilities" in the consolidated balance sheets.
Deferred Financing Costs
Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing
period using the effective interest method. Deferred financing costs associated with long-term debt are presented as a reduction
to the corresponding debt in our consolidated balance sheets. Deferred financing costs associated with our revolving credit
facility are presented as noncurrent assets in our consolidated balance sheets. During the year ended December 31, 2018, we
recognized a $2.2 million loss on debt retirement, recorded as "Other income, net" in the accompanying consolidated
statements of income, associated with the write off of deferred financing costs associated with the Amendment to the TEP
revolving credit facility and the termination of the Tallgrass Equity revolving credit facility as discussed further in Note 10 –
Long-term Debt.
Goodwill
We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an
evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of fair
value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is
August 31. We evaluate goodwill for impairment at the reporting unit level, which is the same as, or one level below, an
operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment
option or proceeding directly to the quantitative impairment test depending on facts and circumstances of the reporting unit. For
the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each
reporting unit at the date of acquisition. If we, after performing the qualitative assessment, determine it is "more likely than
not" that the fair value of a reporting unit is greater than its carrying amount, then goodwill is not considered impaired. When
goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is
compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying
amount exceeds the reporting unit's fair value, then the reporting unit should recognize an impairment charge for the amount by
which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total
amount of goodwill allocated to that reporting unit. See Note 8 – Goodwill and Other Intangible Assets for additional
information regarding impairment testing performed during 2018.
Investment in Unconsolidated Affiliates
We use the equity method to account for investments in 20% or greater owned affiliates that are not variable interest
entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where
we have the ability to exercise significant influence.
We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances
indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in
99
value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an
impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted
techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and
discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated
fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. See Note 7 –
Investments in Unconsolidated Affiliates for additional information regarding our investment in unconsolidated affiliates.
Revenue Recognition
In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with
Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition
guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is
that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that
reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core
principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance
obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations
in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also
mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing
and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include
qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and
assets recognized from the costs to obtain or fulfill a contract.
Management completed its evaluation and implemented the revised guidance using the modified retrospective method as
of January 1, 2018. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018
and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue
guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Consolidated revenues presented in the
comparative consolidated financial statements for periods prior to January 1, 2018 have not been revised.
On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million, increased the carrying amount
of our investment in Rockies Express by $42.8 million, and recognized a receivable from Rockies Express of $1.3 million.
These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of
ASC 606. The cumulative effect adjustment at Rockies Express arose as a result of the allocation of the transaction price to a
series of individual performance obligations in certain long-term transportation contracts with rates that vary throughout the
term of the contract. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased
equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by
NatGas during the periods prior to implementation.
Through our review process, we also identified the following changes to our revenue recognition policies that did not
result in a cumulative effect adjustment on January 1, 2018:
• Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not
represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of
raw gas are accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees
previously recognized in revenue are reported as a reduction to cost of sales under ASC 606.
• Pipeline Loss Allowance. We have determined that PLA collected under certain crude oil transportation arrangements
is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated
with the intent of providing a revenue stream to Pony Express. Under ASC 606, PLA barrels retained from customers
are subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value.
See Note 12 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and the
additional requirements prescribed by the standard. These new disclosures include information regarding the significant
judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities.
Commitments and Contingencies
We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we
determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of
probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the
minimum of the range of probable loss.
Environmental Costs
We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts
that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We
100
do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental
assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides
with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are
based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of
other factors including our prior experience in remediating contaminated sites, other companies' clean-up experience and data
released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new
information.
Fair Value
Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in
an orderly transaction between market participants at the measurement date, or exit price. We apply the fair value measurement
guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial
assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an
asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill.
The fair value measurement accounting guidance requires that we make assumptions that market participants would use in
pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the
obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The
fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in
determining the instruments' fair value. The principal or most advantageous market should be considered from the perspective
of the reporting entity.
Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not
available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of
observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment,
the degree of which is dependent on the price transparency of the instruments or market and the instruments' complexity.
To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize the
inputs used to measure fair value into three categories. An asset or liability's level within the fair value hierarchy is based on the
lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three
levels are defined as follows:
• Level 1 Inputs-quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity
has the ability to access at the measurement date;
• Level 2 Inputs-inputs other than quoted prices included within Level 1 that are observable for the asset or liability,
either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be
observable for substantially the full term of the asset or liability; and
• Level 3 Inputs-unobservable inputs for the asset or liability. These unobservable inputs reflect the entity's own
assumptions about the assumptions that market participants would use in pricing the asset or liability, and are
developed based on the best information available in the circumstances (which might include the reporting entity's
own data).
Any transfers between levels within the fair value hierarchy are recognized at the end of the reporting period. For
information regarding financial instruments measured at fair value on a recurring basis, see Note 9 – Risk Management. For
information regarding the fair value of financial instruments not measured at fair value in the consolidated balance sheets, see
Note 10 – Long-term Debt.
Risk Management Activities
Our operations expose us to a variety of risks including, but not limited to, changes in the prices of commodities that we
buy or sell. We manage these exposures with either physical or financial transactions. We have established a comprehensive
risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage
market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of
senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in
the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and
commodity price risk, including establishing and monitoring exposure limits.
We record derivative contracts at their estimated fair values as of each reporting date and present profit and loss activity on
a net basis in "Processing and other revenues" in our consolidated statements of operations. For more information on our risk
management activities, see Note 9 – Risk Management.
101
Equity-Based Compensation
Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized
over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-
line basis over the requisite service period of each separately vesting portion of the award. As discussed in Note 16 – Equity-
Based Compensation, prior to February 2018 a portion of the expense recognized relating to equity-based compensation grants
was charged to TD.
Income Taxes
Although TGE is organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income
tax purposes and are therefore subject to both U.S. federal and state income taxes. TGE's consolidated subsidiaries consist
primarily of entities that are flow-through entities for income tax purposes. We also own certain C corporation subsidiaries
which have been formed for the purpose of potential pipeline construction and other investment purposes. In addition, Tallgrass
Energy Finance Corp. is a wholly owned subsidiary of TEP that has no material assets and was formed for the sole purpose of
being a co-issuer of TEP's senior notes as discussed in Note 10 – Long-term Debt. These C corporation subsidiaries have not
commenced operations or generated any material income, and as a result no provision for federal or state income taxes has been
recorded in our consolidated financial statements.
Deferred income taxes are provided for temporary differences arising from differences between the consolidated financial
statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates expected to be in
effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than
not that a deferred tax asset will not be realized. In determining the appropriate valuation allowance, we consider projected
realization of tax benefits based on expected levels of future taxable income, available tax planning strategies, and our overall
deferred tax position.
Pursuant to the applicable guidance related to accounting for uncertainty in income taxes, we must recognize the tax
benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination
by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and
precedents of the taxing authority. As of December 31, 2018, we had not recognized any material amounts in connection with
uncertainty in income taxes.
Business Combinations
We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated
fair values at the acquisition date, with any remaining difference recorded as goodwill or gain from a bargain purchase. For
material or complex acquisitions, management typically engages an independent valuation specialist to assist with the
determination of fair value of the assets acquired, liabilities assumed, noncontrolling interest, if any, and goodwill, based on
recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of
the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later
than one year from the acquisition date, we will record any material adjustments to the initial estimate based on new
information obtained about facts and circumstances that existed as of the acquisition date. An income, market or cost valuation
approach may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interest, if
any, in a business combination. We typically use an income approach, such as the multi-period excess earnings method, to
value intangible assets. The income approach requires management to estimate future cash flows: (i) discrete financial
forecasts, which rely on management's estimates of gross margin and operating expenses; (ii) terminal growth rates; and
(iii) appropriate discount rates. We typically use a cost approach to value property, plant and equipment. The cost approach is
based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset.
See Note 3 – Acquisitions and Dispositions for additional information regarding our business combinations.
Accounting Pronouncements Not Yet Adopted
ASU No. 2016-02, "Leases (Topic 842)"
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update
to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by
recognizing 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.
Subsequent to issuing ASU 2016-02, the FASB has issued a series of subsequent updates to the lease guidance in Topic
842, including ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, ASU
No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Leases (Topic 842): Targeted Improvements,
and ASU 2018-20, Leases (Topic 842): Narrow-Scope Improvements for Lessors. The amendments in ASU 2016-02, ASU
102
2018-01, ASU 2018-10, ASU 2018-11, and ASU 2018-20 are effective for public entities for annual reporting periods
beginning after December 15, 2018, and for interim periods within that reporting period.
Management has completed its evaluation and implemented the revised guidance using the modified retrospective method
as of January 1, 2019. The 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. We will
not recast comparative periods in the 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 also elected the practical expedient related to land easements, allowing us to carry forward
our accounting treatment for land easements on existing agreements as property, plant and equipment.
Adoption of the new standard resulted in the recognition of ROU assets and lease liabilities for operating leases as of
January 1, 2019. Excluding ROU assets and lease liabilities relating to agreements between consolidated subsidiaries, the ROU
assets and liabilities recognized as of January 1, 2019 are not expected to be material. Our accounting for finance leases
remained substantially unchanged.
3. Acquisitions and Dispositions
Consolidation of BNN Colorado
Effective December 1, 2018, we obtained control of BNN Colorado Water, LLC ("BNN Colorado") through an amendment
to the voting rights in BNN Colorado's limited liability company agreement. Prior to the amendment, we accounted for our
interest in BNN Colorado under the equity method of accounting. The consolidation was accounted for as a business
combination under ASC 805. No gain or loss was recognized on the remeasurement of our 63% membership interest as of
December 1, 2018, as the carrying value was determined to approximate the fair value. The 37% equity interest in BNN
Colorado held by noncontrolling interests was recorded at its acquisition date fair value of $10.1 million. These fair value
measurements are based on significant inputs, such as forecasted cash flows and discount rates, that are not observable in the
market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.
The following represents the fair value of assets acquired and liabilities assumed (in thousands):
Accounts receivable..................................................................................................................... $
Property, plant and equipment.....................................................................................................
Intangible asset ............................................................................................................................
Accounts payable and accrued liabilities ....................................................................................
Deferred revenue .........................................................................................................................
Net identifiable assets acquired (excluding cash) ..................................................................... $
4,053
18,535
7,922 (1)
(53)
(4,053)
26,404
(1) The $7.9 million intangible asset acquired represents a customer contract. This intangible asset is amortized on a
straight-line basis over a period of approximately 3 years, the remaining term of the underlying contract at the time of
acquisition.
At December 31, 2018, the assets acquired and liabilities assumed were recorded at provisional amounts based on the
preliminary purchase price allocation. We are in the process of identifying and measuring all assets acquired and liabilities
assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any
new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the
measurement of these amounts. Actual revenue and net loss attributable to TGE from BNN Colorado of less than $1.0 million
was recognized in the accompanying consolidated statements of income for the period from December 1, 2018 to December 31,
2018.
Acquisitions of BNN North Dakota
In January 2018, we acquired 100% of the membership interests in Buckhorn Energy Services, LLC and Buckhorn SWD
Solutions, LLC, which were subsequently merged and renamed BNN North Dakota, LLC ("BNN North Dakota"), for
approximately $95.0 million, net of cash acquired. BNN North Dakota owns a produced water gathering and disposal system in
the Bakken basin with approximately 133,000 acres under dedication. The transaction qualifies as an acquisition of a business
and is accounted for as a business combination under ASC 805.
103
The following represents the fair value of assets acquired and liabilities assumed (in thousands):
Accounts receivable ..................................................................................................................... $
Inventory ......................................................................................................................................
Property, plant and equipment .....................................................................................................
Intangible asset.............................................................................................................................
Accounts payable and accrued liabilities.....................................................................................
Net identifiable assets acquired (excluding cash) ..................................................................... $
2,457
67
48,900
46,800 (1)
(3,224)
95,000
(1) The $46.8 million intangible asset acquired represents three major customer contracts. This intangible asset is
amortized on a straight-line basis over a period of 8 - 14 years, the remaining terms of the underlying contracts at the
time of acquisition.
At March 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts
based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation
of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2018. Actual revenue and net
income attributable to TGE from BNN North Dakota of $18.8 million and $4.7 million, respectively, was recognized in the
accompanying consolidated statements of income for the period from January 12, 2018 to December 31, 2018.
In November 2018, we acquired 100% of the membership interests in NGL Water Solutions Bakken, LLC ("NGL Water
Solutions Bakken"), a produced water disposal system in the Bakken basin, for cash consideration of approximately $91.0
million, subject to working capital adjustments. NGL Water Solutions Bakken was subsequently merged into BNN North
Dakota. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.
The following represents the fair value of assets acquired and liabilities assumed (in thousands):
Accounts receivable..................................................................................................................... $
Prepayments and other current assets..........................................................................................
Property, plant and equipment.....................................................................................................
Intangible asset ............................................................................................................................
Accounts payable and accrued liabilities ....................................................................................
Net identifiable assets acquired.................................................................................................
Goodwill ......................................................................................................................................
Net assets acquired.................................................................................................................... $
3,599
5
17,200
54,000 (1)
(949)
73,855
17,145
91,000
(1) The $54.0 million intangible asset acquired represents customer relationships and a customer contract. This intangible
asset is amortized on a straight-line basis over a period of 3 - 8 years.
At December 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts
based on the preliminary purchase price allocation. We are in the process of identifying and measuring all assets acquired and
liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to
reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have
affected the measurement of these amounts. The goodwill recognized of $17.1 million is primarily attributed to synergies
expected from combining the operations of TGE and NGL Water Solutions Bakken. All the goodwill was assigned to our
Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TGE from NGL Water Solutions
Bakken of $1.4 million and $0.5 million, respectively, was recognized in the accompanying consolidated statements of income
for the period from November 30, 2018 to December 31, 2018.
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. The facility is expected to offer 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. We made an initial cash contribution to PLT of $30.7 million in exchange for a 100% preferred
membership interest and a 80% common membership interest in PLT. DHIF contributed any and all assets and rights related to
PLT in exchange for a 20% common membership interest and the right to receive certain special distributions. Our preferred
and common membership interests are considered to be a controlling financial interest and PLT was consolidated accordingly.
The transaction has been accounted for as an asset acquisition, with substantially all the fair value allocated to the assets and
104
liabilities acquired based on their relative fair values. The intangible assets acquired, valued at approximately $35 million,
relate to permits, designs, and other work-product related to the development and construction of a crude oil terminal facility in
Louisiana. The liabilities recognized relate to DHIF's right to receive special distributions totaling $35 million. 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 will construct the facilities.
Acquisition of Pawnee Terminal
In January 2018, we entered into an agreement to acquire a 51% membership interest in the Pawnee, Colorado crude oil
terminal ("Pawnee Terminal") from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $30.6
million. The transaction closed on April 1, 2018. As the 51% membership interest does not represent a controlling interest in
Pawnee, our investment in Pawnee Terminal is recorded under the equity method of accounting and reported as
"Unconsolidated investments" on the consolidated balance sheets.
Acquisitions of 75% Membership Interest in Rockies Express and Additional TEP Common Units
In May 2016, TD assigned us its right to purchase a 25% membership interest in Rockies Express from a unit of Sempra
U.S. Gas and Power ("Sempra") pursuant to the purchase agreement originally entered into between TD's wholly-owned
subsidiary and Sempra in March 2016. Subsequently on May 6, 2016, we closed the purchase of a 25% membership interest in
Rockies Express from Sempra pursuant to the purchase agreement for cash consideration of approximately $436.0 million, after
making the adjustments to the purchase price required by the purchase agreement.
In March 2017, TEP, TD, and Rockies Express Holdings, LLC, entered into a definitive Purchase and Sale Agreement,
pursuant to which TEP acquired an additional 24.99% membership interest in Rockies Express from TD in exchange for cash
consideration of $400 million.
The 2017 transfer of the Rockies Express membership interest between TD and TEP is considered a transaction between
entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of
the transaction, the acquisition resulted in the recognition of a noncash deemed contribution representing the excess carrying
value of the 24.99% membership interest in Rockies Express acquired over the fair value of the consideration paid. For further
discussion, see Note 11 - Partnership Equity.
In February 2018, TD merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity
("Tallgrass Development Holdings"), and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in
Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass
Equity issued 27,554,785 unregistered TGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million
based on the closing price on February 6, 2018, to the limited partners of TD. Subsequent to the closing of the transaction, our
aggregate membership interest in Rockies Express is 75%.
The 2018 transfer of the Rockies Express membership interest between TD and Tallgrass Equity is considered a transaction
between entities under common control, but does not represent a change in reporting entity. As a result of the common control
nature of the transaction, the acquisition resulted in the recognition of a noncash deemed contribution representing the excess
carrying value of the 25.01% membership interest in Rockies Express acquired over the fair value of the consideration paid. For
further discussion, see Note 11 - Partnership Equity. As the aggregate 75% membership interest does not represent a
controlling interest in Rockies Express, TGE's investment in Rockies Express is recorded under the equity method of
accounting and is reported as "Unconsolidated investments" on our consolidated balance sheets. For additional information, see
Note 7 - Investments in Unconsolidated Affiliates.
The acquisition of an additional 5,619,218 TEP common units is considered an acquisition of noncontrolling interest and
resulted in the recognition of a noncash deemed distribution representing the excess purchase price over the $53.8 million
carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018. For further discussion, see Note 11 -
Partnership Equity.
Acquisition and Sale of Outrigger Powder River Operating, LLC
In August 2017, we acquired 100% of the membership interests of Outrigger Powder River Operating, LLC (subsequently
renamed as Tallgrass Crude Gathering, LLC, "TCG"), which owns the PRB Crude System, a crude oil gathering system in the
Powder River Basin with approximately 34 miles of gathering lines as of the acquisition date and approximately 150,000 acres
dedicated on a long-term fee-based contract, for approximately $36 million. The transaction qualifies as an acquisition of a
business and is accounted for as a business combination under ASC 805.
105
The following represents the fair value of assets acquired and liabilities assumed (in thousands):
Accounts receivable ..................................................................................................................... $
Property, plant and equipment .....................................................................................................
Intangible asset.............................................................................................................................
Accounts payable and accrued liabilities.....................................................................................
Net identifiable assets acquired ................................................................................................. $
117
29,306
6,694 (1)
(87)
36,030
(1) The $6.7 million intangible asset acquired represents a major customer contract. This intangible asset is amortized on a
straight-line basis over a period of 8 years, the remaining term of the contract at the time of acquisition.
At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts
based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation
of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. Actual revenue and
net loss attributable to TGE from TCG of less than $1 million was recognized in the accompanying consolidated statements of
income for the period from August 3, 2017 to December 31, 2017.
In February 2018, we entered into an agreement with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to sell
our 100% membership interest in TCG, for approximately $50.0 million. The sale of TCG closed on February 23, 2018. During
the year ended December 31, 2018, we recognized a gain of $9.4 million on the sale which is presented in the line item "Gain
on disposal of assets" in the consolidated statements of income.
Joint Venture with Silver Creek
In February 2018, we entered into an agreement with Silver Creek to form Iron Horse Pipeline, LLC ("Iron Horse"), which
owns a new 80-mile crude oil pipeline currently under construction that will transport crude oil from the Powder River Basin to
Guernsey, Wyoming ("Iron Horse Pipeline"). During the year ended December 31, 2018, we contributed an initial $3.5 million
and committed to funding our proportionate share of the remaining costs of construction in exchange for a 75% membership
interest in Iron Horse. As the 75% membership interest does not represent a controlling interest in Iron Horse, our investment in
Iron Horse is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the
consolidated balance sheets.
In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the
contribution by us and Silver Creek of cash and additional Powder River Basin assets. These additional contributions closed in
January 2019. We contributed our 75% membership interest in Iron Horse, $37 million in cash, and various other assets,
including terminal facilities currently under construction in Guernsey, Wyoming. Silver Creek contributed the Powder River
Express Pipeline ("PRE Pipeline") and their 25% membership interest in Iron Horse. The expanded joint venture operates under
the name Powder River Gateway, LLC ("Powder River Gateway"), and owns the Iron Horse Pipeline, the PRE Pipeline, a 70-
mile crude oil pipeline that transports crude oil from the Powder River Basin to Guernsey, Wyoming, and crude oil terminal
facilities in Guernsey, Wyoming. Effective January 1, 2019, 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.
Acquisitions of Additional Interests in Deeprock Development, LLC
In July 2017, we acquired an additional 40% membership interest in Deeprock Development from Kinder Morgan
Cushing, LLC for cash consideration of approximately $57.2 million, net of cash acquired. We subsequently acquired an
additional 9% membership interest in Deeprock Development from Deeprock Energy Resources LLC ("DER") on July 21,
2017, as discussed further below.
Upon closing of the acquisition of the 40% membership interest on July 20, 2017, we obtained a controlling financial
interest in Deeprock Development and accordingly have accounted for the transaction as a step acquisition under ASC 805. On
the acquisition date, we remeasured our previously held 20% equity interest in Deeprock Development to its fair value of $22.9
million, recognized a gain of $9.7 million in "Gain on remeasurement of unconsolidated investment" in the consolidated
statements of income, and consolidated Deeprock Development in our consolidated financial statements. The 40% equity
interest in Deeprock Development held by noncontrolling interests was recorded at its acquisition date fair value of $45.9
million. The fair values of the previously held equity interest and the noncontrolling interest were determined using a
discounted cash flow analysis and adjusted for lack of control. These fair value measurements are based on significant inputs,
such as forecasted cash flows and discount rates, that are not observable in the market and thus represent fair value
measurements categorized within Level 3 of the fair value hierarchy under ASC 820.
106
The following represents the fair value of assets acquired and liabilities assumed (in thousands):
Accounts receivable ..................................................................................................................... $
Other current assets......................................................................................................................
Property, plant and equipment .....................................................................................................
Accounts payable .........................................................................................................................
Deferred revenue..........................................................................................................................
Net identifiable assets acquired .................................................................................................
Goodwill ......................................................................................................................................
968
598
70,148
(712)
(6,546)
64,456
61,550
Net assets acquired (excluding cash)......................................................................................... $
126,006
At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts
based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation
of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. The goodwill
recognized of $61.6 million is primarily attributed to synergies expected from combining our operations with the operations of
Deeprock Development. All the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue
and net income attributable to TGE from Deeprock Development of $10.5 million and $0.9 million, respectively, was
recognized in the accompanying consolidated statements of income for the period from July 20, 2017 to December 31, 2017.
In July 2017, subsequent to the acquisition of an additional 40% membership interest discussed above, we acquired an
additional 9% membership interest in Deeprock Development from DER for total consideration valued at approximately $13.1
million, consisting of approximately $6.4 million in cash and the issuance of 128,790 TEP common units (valued at
approximately $6.7 million based on the July 20, 2017 closing price of TEP's common units), which was accounted for as an
acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate membership interest in
Deeprock Development is 69%.
Acquisition of Deeprock North and Merger with Deeprock Development
In January 2018, we acquired an approximate 38% membership interest in Deeprock North, LLC ("Deeprock North") from
Kinder Morgan Deeprock North Holdco LLC for cash consideration of $19.5 million. Immediately following the acquisition,
Deeprock North was merged into Deeprock Development, and the members of Deeprock North and Deeprock Development
received adjusted membership interests in the combined entity. As a result, we recognized additional noncontrolling interests in
Deeprock Development of $31.8 million. The acquisition of Deeprock North by Deeprock Development has been accounted for
as an asset acquisition, with substantially all of the fair value allocated to the long-lived assets acquired based on their relative
fair values. After the acquisition and merger, we own an approximate 60% membership interest in the combined entity.
Acquisition of DCP Douglas, LLC
In June 2017, we acquired 100% of the membership interests in DCP Douglas, LLC (subsequently renamed as Tallgrass
Midstream Gathering, LLC), which owns the Douglas Gathering System, a natural gas gathering system in the Powder River
Basin with approximately 1,500 miles of gathering pipeline connected to the Douglas processing plant, for approximately
$128.5 million. The acquisition has been accounted for as an asset acquisition, with substantially all the fair value allocated to
the long-lived assets acquired based on their relative fair values.
Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC
In January 2017, we acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the
issued and outstanding membership interests in NatGas from TD for total cash consideration of $140 million. These
acquisitions are considered transactions between entities under common control, and a change in reporting entity. As a result of
the common control nature of the transaction, the acquisitions resulted in the recognition of a noncash deemed distribution
representing the excess fair value of the consideration paid over the carrying value of Terminals and NatGas net assets acquired.
For further discussion, see Note 11 - Partnership Equity.
Acquisitions of Pony Express
In January 2016, we acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration
of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015
closing price of our common units) issued to TD, for total consideration of approximately $743.6 million. The transaction
increased our aggregate membership interest in Pony Express to 98% effective January 1, 2016. As part of the transaction, TD
granted us an 18-month call option covering the newly issued 6,518,000 common units at a price of $42.50. On the effective
date of the acquisition, the call option was valued at $46.0 million. As discussed in Note 9 – Risk Management, in July 2016
107
and October 2016, we partially exercised the option covering 3,563,146 and 1,251,760 of the common units, respectively. In
February 2017, we exercised the remainder of the call option covering an additional 1,703,094 common units, leaving no
remaining common units subject to the call option as of such date. As a result of the partial exercises in 2016 and 2017, we
derecognized a portion of the derivative asset balance, recognizing approximately $34.0 million and $12.6 million through
equity for the years ended December 31, 2016 and 2017, respectively, as discussed further in Note 9 – Risk Management.
The acquisition of the additional 31.3% membership interest in Pony Express represents a transaction between entities
under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the
transaction has not been recast to reflect the additional 31.3% membership interest. As a result of the common control nature of
the transaction, the acquisition resulted in the recognition of a noncash deemed distribution representing the excess fair value of
the consideration paid over the carrying value of the 31.3% membership interest in Pony Express acquired. For further
discussion, see Note 11 - Partnership Equity.
Cash outflows to acquire an additional noncontrolling interest in Pony Express are classified as an investing activity in the
accompanying consolidated statements of cash flows to the extent the consideration paid was used to directly fund the
construction of the underlying assets by the noncontrolling member. Cash outflows to acquire an additional noncontrolling
interest in excess of the cost to construct the underlying assets are classified as financing activities. For the year ended
December 31, 2016, $49.1 million of the $475 million paid to acquire the additional 31.3% membership interest in Pony
Express was classified as an investing activity and $425.9 million was classified as a financing activity.
In February 2018, we acquired the remaining 2% membership interest in Pony Express, along with administrative assets
consisting primarily of information technology assets, from TD for cash consideration of approximately $60 million, bringing
our aggregate membership interest in Pony Express to 100%. The acquisition of the remaining 2% membership interest in Pony
Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a
result, financial information for periods prior to the transaction has not been recast to reflect the additional 2% membership
interest. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash
deemed distribution representing the excess fair value of the consideration paid over the carrying value of the 2% membership
interest in Pony Express acquired. For further discussion, see Note 11 – Partnership Equity.
Pro Forma Financial Information
Unaudited pro forma revenue and net income (loss) attributable to TGE for the years ended December 31, 2018 and 2017
is presented below as if the acquisitions of BNN North Dakota, NGL Water Solutions Bakken, and BNN Colorado had been
completed on January 1, 2017. Unaudited pro forma revenue and net (loss) income attributable to TGE for the years ended
December 31, 2017 and 2016 is presented below as if the acquisitions of TCG and Deeprock Development had been completed
on January 1, 2016.
Year Ended December 31,
2018
2017
(in thousands)
2016
Revenue................................................................................... $
Net income (loss) attributable to TGE .................................... $
813,286
140,005
$
$
686,803
$
(129,155) $
632,528
34,311
The pro forma financial information is not necessarily indicative of what the actual results of operations or financial
position of TGE would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they
purport to project the results of operations or financial position of TGE for any future periods or as of any date. The pro forma
financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result
from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma
revenue and net income (loss) includes adjustments to give effect to the estimated results of operations of BNN North Dakota,
NGL Water Solutions Bakken, BNN Colorado, TCG, and Deeprock Development for the periods presented. The pro forma net
income (loss) also includes adjustments to eliminate the equity in earnings and gain on remeasurement of unconsolidated
investment associated with our previously held 20% membership interest in Deeprock Development and to eliminate the equity
in earnings associated with our 63% membership interest in BNN Colorado which was previously accounted for as an equity
method investment.
108
Historical Financial Information
The results of our acquisitions of Terminals and NatGas are included in the consolidated balance sheets as of December 31,
2018 and December 31, 2017 and in the consolidated statements of income for the years ended December 31, 2018, 2017, and
2016. The following table presents the previously reported consolidated statements of income for the year ended December 31,
2016 adjusted for the acquisitions of Terminals and NatGas:
Year Ended December 31, 2016
TGE (As
previously
reported)
Consolidate
Terminals
Consolidate
NatGas
Elimination
TGE (As
currently
reported)
Revenues:
Crude oil transportation services ............. $ 374,949
119,962
Natural gas transportation services..........
Sales of natural gas, NGLs, and crude
oil.............................................................
Processing and other revenues.................
Total Revenues....................................
605,122
32,817
77,394
$
Operating Costs and Expenses:
Cost of sales.............................................
Cost of transportation services ................
Operations and maintenance....................
Depreciation and amortization ................
General and administrative......................
Taxes, other than income taxes................
Contract termination................................
Loss on disposal of assets........................
Total Operating Costs and Expenses ..
Operating Income (Expense)........................
Other Income (Expense):
Equity in earnings of unconsolidated
investments ..............................................
Interest expense, net ................................
Other income, net ....................................
Total Other Income .............................
Net income before tax ..................................
Deferred income tax expense ..................
Net income ...................................................
71,920
58,341
53,386
84,896
55,829
24,727
—
1,849
350,948
254,174
51,780
(45,601)
432
6,611
260,785
(17,741)
243,044
Net income attributable to
noncontrolling interests ...........................
Net income attributable to TGE ................... $
(216,250)
26,794
$
(in thousands)
$
— $
—
—
6,228
6,228
—
—
—
—
—
—
—
—
—
6,228
—
—
—
—
6,228
—
6,228
—
$
6,228
$
—
—
99
12,043
12,142
100
788
1,684
1,351
1,469
673
8,061 (3)
—
14,126
(1,984)
2,751
—
—
2,751
767
—
767
—
767
—
—
$
374,949
119,962
(370) (1)
(11,460) (2)
(11,830)
(370) (1)
(11,460) (2)
—
—
—
—
—
—
(11,830)
—
—
—
—
—
—
—
—
—
—
77,123
39,628
611,662
71,650
47,669
55,070
86,247
57,298
25,400
8,061
1,849
353,244
258,418
54,531
(45,601)
432
9,362
267,780
(17,741)
250,039
(216,250)
33,789
$
(1) Represents the elimination of revenue and cost of sales associated with the purchase of crude oil from Pony Express by
Terminals.
(2) Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal
facilities by Pony Express.
(3) Represents a one-time charge related to the termination of an operating agreement at the Sterling Terminal.
109
4. Related Party Transactions
As a result of our relationship with Tallgrass Energy Holdings, LLC ("Tallgrass Energy Holdings") and its affiliates, we
have entered into a number of related party transactions. The following disclosure includes those related party transactions
which are not otherwise disclosed in these notes to our consolidated financial statements.
All of our employees are employed by Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018,
Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings. In connection with the closing of the TEP
initial public offering on May 17, 2013, TEP and TEP GP entered into an Omnibus Agreement with Tallgrass Energy Holdings
and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things,
TEP will reimburse Tallgrass Energy Holdings and its affiliates for all expenses they incur and payments they make on TEP's
behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain
centralized corporate functions performed by Tallgrass Energy Holdings and its affiliates, including legal, accounting, cash
management, insurance administration and claims processing, risk management, health, safety and environmental, information
technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the
closing of the TGE initial public offering on May 12, 2015 (the "TGE IPO"), TGE entered into an Omnibus Agreement (the
"TGE Omnibus Agreement") with Tallgrass Energy GP, LLC (formerly known as TEGP Management, LLC), Tallgrass Equity
and Tallgrass Energy Holdings.
Effective July 1, 2018, Tallgrass Management was contributed to Tallgrass Equity in connection with the TEP Merger. As a
result, the costs of employer and director compensation and benefits are now incurred directly by Tallgrass Equity.
Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows:
Processing and other revenues (1) ....................................................... $
Cost of transportation services (2)
$
Charges to TGE: (3)
Property, plant and equipment, net ............................................. $
Other deferred charges................................................................ $
Operations and maintenance....................................................... $
General and administrative ......................................................... $
Year Ended December 31,
2018
2017
2016
(in thousands)
7,483
$
— $
— $
— $
— $
— $
8,516
10,476
2,679
25
29,881
41,676
$
$
$
$
$
$
6,228
18,585
3,084
44
25,431
40,321
(1) Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline.
(2) Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock
Development during the third quarter of 2017, as discussed in Note 3 – Acquisitions and Dispositions.
(3) Charges to TGE, inclusive of Tallgrass Equity and TEP, include indirectly charged wages and salaries, other
compensation and benefits, and shared services for periods prior to January 1, 2018. Effective January 1, 2018, these
costs are incurred by TEP directly and, in the case of certain employee compensation and benefits, paid on TEP's
behalf by its affiliate, Tallgrass Management, LLC, pursuant to the TEP Omnibus Agreement.
110
Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable" in the consolidated
balance sheets are as follows:
December 31, 2018 December 31, 2017
(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC................................................................... $
Iron Horse Pipeline, LLC ...........................................................................
Pawnee Terminal, LLC...............................................................................
3,447
$
186
115
Total receivable from related parties................................................... $
3,748
$
Accounts payable to related parties:
Tallgrass Operations, LLC (1) ..................................................................... $
Total accounts payable to related parties ............................................ $
— $
— $
1,340
—
—
1,340
5,342
5,342
(1) Reflects accounts payable for charges to TGE, inclusive of Tallgrass Equity and TEP, including indirectly charged
wages and salaries, other compensation and benefits, and shared services prior to January 1, 2018 as discussed above.
Gas imbalances with affiliated shippers are as follows:
Affiliate gas imbalance receivables................................................................... $
Affiliate gas imbalance payables....................................................................... $
19
742
$
$
18
442
December 31, 2018 December 31, 2017
(in thousands)
5.
Inventory
The components of inventory at December 31, 2018 and 2017 consisted of the following:
December 31, 2018
December 31, 2017
Crude oil ...................................................................................................... $
Materials and supplies .................................................................................
Gas in underground storage.........................................................................
Natural gas liquids.......................................................................................
(in thousands)
23,205
$
8,206
2,740
165
Total inventory........................................................................................ $
34,316
$
12,792
5,891
1,984
942
21,609
6. Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
December 31, 2018 December 31, 2017
(in thousands)
Crude oil pipelines............................................................................................. $
Gathering, processing and terminalling assets (1) ..............................................
Natural gas pipelines .........................................................................................
General and other (2) ..........................................................................................
Construction work in progress...........................................................................
Accumulated depreciation and amortization .....................................................
Total property, plant and equipment, net (3) .................................................. $
1,313,976
$
1,220,379
889,168
607,343
180,299
191,994
(380,351)
2,802,429
$
675,092
581,400
98,680
97,978
(279,192)
2,394,337
(1)
Includes approximately $53.6 million and $46.2 million of assets associated with the acquisitions of BNN North
Dakota in January and November 2018 and Deeprock North in January 2018, respectively.
111
(2)
Includes approximately $30.7 million of land associated with the PLT capital lease as discussed in Note 3 –
Acquisitions and Dispositions.
(3) Property, plant and equipment, net includes approximately $455.8 million of assets at our regulated natural gas
pipelines at December 31, 2018.
Depreciation expense was approximately $102.7 million, $86.9 million, and $83.2 million for the years ended
December 31, 2018, 2017, and 2016, respectively. Capitalized interest was approximately $5.2 million, $1.1 million, and $0.6
million for the years ended December 31, 2018, 2017, and 2016, respectively.
Under various lease agreements, TMID, as lessor, leases capacity on NGL pipelines that were constructed for third parties,
and Deeprock Development, as lessor, leases capacity on certain of its storage facilities under lease agreements acquired as part
of the Deeprock North acquisition on January 2, 2018. Rental income for these arrangements was approximately $10.9 million,
$3.8 million, and $3.2 million for the years ended December 31, 2018, 2017, and 2016, respectively, and was recorded as
"Processing and other revenues" in the accompanying consolidated statements of income. Under a lease agreement initially
effective November 13, 2012, TIGT, as lessor, leases a portion of its office space to a third party. Rental income was
approximately $0.8 million for the years ended December 31, 2018, 2017, and 2016 and was recorded as "Other income, net"
in the accompanying consolidated statements of income.
As of December 31, 2018, future minimum rental income under non-cancelable operating leases as the lessor were as
follows (in thousands):
Year
2019......................................................................................
$
2020......................................................................................
2021......................................................................................
2022......................................................................................
2023......................................................................................
Thereafter .............................................................................
Total
7,742
3,952
3,773
3,773
3,773
7,353
Total......................................................................................
$
30,366
7.
Investments in Unconsolidated Affiliates
Rockies Express
Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated
investments" on our consolidated balance sheets. As of May 6, 2016, the difference between the fair value of our 25%
membership interest in Rockies Express of $436.0 million and the book value of the underlying net assets resulted in a negative
basis difference of approximately $404.7 million. As discussed in Note 3 – Acquisitions and Dispositions, we acquired an
additional 24.99% and 25.01% membership interest in Rockies Express from TD on March 31, 2017 and February 7, 2018,
respectively. As of March 31, 2017, the negative basis difference carried over from TD from the transfer of the 24.99% Rockies
Express membership interest was approximately $386.8 million. As of February 7, 2018, the negative basis difference carried
over from TD from the transfer of the 25.01% Rockies Express membership interest was approximately $376.5 million. The
transfer of the 24.99% Rockies Express membership interest between TD and TEP and the 25.01% Rockies Express
membership interest between TD and Tallgrass Equity are considered transactions between entities under common control, but
does not represent a change in reporting entity. As a result of the common control nature of the transactions, the 24.99% and
25.01% membership interests in Rockies Express were transferred to TEP and Tallgrass Equity, respectively, at TD's historical
carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the
investments and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD.
112
The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years, which equates to
the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment.
The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. At December 31,
2018, the basis difference for our membership interests in Rockies Express was allocated as follows:
Basis Difference
(in thousands)
Amortization Period
Long-term debt ............................................................................................ $
Property, plant and equipment .....................................................................
Total basis difference .............................................................................. $
47,182
(1,146,984)
(1,099,802)
2 - 25 years
35 years
During the year ended December 31, 2018, we recognized equity in earnings associated with our aggregate 75%
membership interest in Rockies Express of $303.4 million, inclusive of the amortization of the negative basis difference, and
received distributions from and made contributions to Rockies Express of $380.7 million and $432.0 million, respectively.
In July 2018, we made a special contribution of approximately $412.5 million to fund our portion of the repayment of
Rockies Express' $550 million of 6.85% senior notes due July 15, 2018.
BNN Colorado Water, LLC
As discussed in Note 3 – Acquisitions and Dispositions, we consolidated BNN Colorado effective December 1, 2018 and
no longer account for our investment in BNN Colorado under the equity method of accounting.
Deeprock Development
As discussed in Note 3 – Acquisitions and Dispositions, on July 20, 2017, we acquired an additional 40% membership
interest in Deeprock Development. As a result of the acquisition, we consolidated Deeprock Development and effective July 20,
2017 we no longer account for our investment in Deeprock Development under the equity method of accounting.
Summarized Financial Information of Unconsolidated Affiliates
Combined summarized financial information for all our unconsolidated affiliates is shown in the tables below. Summarized
financial information for Deeprock Development is presented from January 1, 2016 to July 20, 2017, the date we acquired a
controlling interest in Deeprock Development. Summarized financial information for Rockies Express is presented from the
date of the initial acquisition of May 6, 2016 to December 31, 2018. Summarized financial information for BNN Colorado is
presented from the date of the acquisition, June 23, 2017 to December 1, 2018, the date we acquired a controlling interest in
BNN Colorado. Summarized financial information for Iron Horse is presented from the date of the acquisition, February 23,
2018 to December 31, 2018. Summarized financial information for Pawnee Terminal is presented from the date of the
acquisition, April 1, 2018 to December 31, 2018.
Current assets .......................................................................................... $
Noncurrent assets .................................................................................... $
Current liabilities..................................................................................... $
Noncurrent liabilities............................................................................... $
Members' equity...................................................................................... $
December 31, 2018
December 31, 2017
(in thousands)
132,213
6,031,066
694,951
1,502,906
3,965,422
$
$
$
$
$
122,362
5,974,926
714,037
2,049,189
3,334,062
Revenue................................................................................... $
Operating income .................................................................... $
Net income to Members .......................................................... $
930,771
524,607
376,934
$
$
$
860,115
480,337
465,592
$
$
$
440,838
203,801
184,314
Year Ended December 31,
2018
2017
(in thousands)
2016
113
8. Goodwill and Other Intangible Assets
Reconciliation of Goodwill
The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the reporting
period:
Year Ended December 31, 2018
Year Ended December 31, 2017
Natural Gas
Transportation
Gathering,
Processing &
Terminalling
Total
Natural Gas
Transportation
(in thousands)
Gathering,
Processing &
Terminalling
Total
Balance at beginning of
period..................................... $
Goodwill acquired .................
Balance at end of period ........ $
255,558
—
255,558
$
$
149,280
17,145 (1)
166,425
$ 404,838
17,145
$ 421,983
$
$
255,558
—
255,558
$
$
87,730
61,550 (2)
149,280
$ 343,288
61,550
$ 404,838
(1) The $17.1 million of goodwill was recorded in connection with the acquisition of NGL Water Solutions Bakken on
November 30, 2018 as discussed further in Note 3 – Acquisitions and Dispositions.
(2) The $61.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Deeprock
Development on July 20, 2017 as discussed further in Note 3 – Acquisitions and Dispositions.
Annual Goodwill Impairment Analysis
In 2018, we elected to apply the qualitative assessment option for four of our five reporting units. In conducting the
qualitative assessment we considered relevant factors and circumstances that affect the fair value or carrying amount of the
reporting entity. Such factors included changes in discount rates, projected cash flows, macroeconomic considerations, industry
and market considerations, overall financial performance, prior quantitative results, and entity and reporting unit specific
events. For each of these reporting units, the results of the qualitative assessment indicated that it was more likely than not that
the fair value of the reporting units exceeded their respective book values. As such, we did not perform a quantitative
impairment analysis, and we concluded that no impairment was indicated as of August 31, 2018.
We did not elect to apply the qualitative assessment option for one reporting unit during our 2018 annual goodwill
impairment testing; instead we proceeded directly to the quantitative impairment test. We compared the fair value of the
reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow
analysis. The fair value of the reporting unit was determined on a stand-alone basis from the perspective of a market participant
and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-
term forecasts of future operating results and various other assumptions and estimates, the most significant of which are
revenue, operating expenses, general and administrative expenses, terminal growth rates, maintenance capital expenditures, and
the weighted average cost of capital. The fair value of the reporting unit was determined using significant unobservable inputs,
considered Level 3 under the fair value hierarchy in the Codification. For this reporting unit, the results of the quantitative
impairment test indicated no impairment as the fair value of the reporting unit was greater than its respective book value. As a
result, in accordance with the Codification guidance, we did not record a goodwill impairment during the year ended December
31, 2018. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted
cash flow model and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a
triggering event occurs and will perform additional goodwill impairment analyses as necessary.
114
Other Intangible Assets
A summary of amortized intangible assets is as follows:
December 31, 2018 December 31, 2017
Pony Express oil conversion use rights ............................................................. $
Customer contracts ............................................................................................
Customer relationships ......................................................................................
Plaquemines Liquids Terminal use rights and permits......................................
Accumulated amortization.................................................................................
Intangible assets, net..................................................................................... $
(in thousands)
105,973
$
105,973
60,348
52,100
35,000
(26,318)
227,103
$
8,064
—
—
(16,306)
97,731
Amortization of intangible assets was approximately $8.1 million, $3.8 million, and $3.0 million for the years ended
December 31, 2018, 2017, and 2016, respectively.
Estimated future amortization for the intangible assets is as follows (in thousands):
Year
2019......................................................................................
2020......................................................................................
2021......................................................................................
2022......................................................................................
2023......................................................................................
Thereafter .............................................................................
Total (1)..................................................................................
$
$
Total
16,528
16,347
16,294
13,144
13,144
116,646
192,103
(1) Excludes the $35 million intangible asset at PLT, as discussed in Note 3 – Acquisitions and Dispositions, that will be
amortized over 35 years beginning on the in-service date of the project facilities.
9. 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.
Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of
crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of
crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales,
(ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and
changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included in the consolidated balance sheets:
Balance Sheet
Location
December 31, 2018
December 31, 2017
Crude oil derivative contracts (1).... Prepayments and other current
assets .............................................
Crude oil derivative contracts (2).... Other current liabilities .................
$
$
(in thousands)
3,526
1,642
$
$
—
2,368
(1) As of December 31, 2018, the fair value shown for crude oil derivative contracts represents the forward purchase of
2,105,146 barrels of crude oil, consisting of fixed price and floating price contracts, which will settle throughout 2019.
115
(2) As of December 31, 2018, the fair value shown for crude oil derivative contracts represents the forward sale of
1,274,500 barrels of crude oil, consisting of fixed price and floating price contracts, which will settle throughout the
first quarter of 2019. As of December 31, 2017, the fair value shown for crude oil derivative contracts represents the
forward sale of 356,000 barrels of crude oil, consisting of fixed price and floating price contracts, which settled in the
first quarter of 2018.
Effect of Derivative Contracts in the Statements of Income
The following table summarizes the impact of derivative contracts not designated as hedging contracts for the years ended
December 31, 2018, 2017 and 2016:
Location of
gain (loss) recognized
in income on derivatives
Amount of gain (loss) recognized in income on derivatives
Year Ended December 31,
2018
2017
(in thousands)
2016
Sales of natural gas, NGLs, and
crude oil.....................................
Crude oil derivative
contracts ........................
Sales of natural gas, NGLs, and
Natural gas derivative
crude oil.....................................
contracts ........................
Call option derivative.... Other income, net ......................
$
$
$
Call Option Derivative
29,510
$
— $
— $
39
75
1,885
$
$
$
(40)
74
(1,291)
As part of our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD
granted TEP an 18 month call option at an exercise price of $42.50 per TEP common unit covering the 6,518,000 TEP common
units issued to TD as a portion of the consideration. In July 2016 and October 2016, TEP partially exercised the call option
covering 3,563,146 and 1,251,760 common units, respectively, for cash payments of $151.4 million and $53.2 million,
respectively. On February 1, 2017, TEP exercised the remainder of the call option covering an additional 1,703,094 common
units for a cash payment of $72.4 million. These common units were deemed canceled upon the exercise of the call option and
as of the applicable exercise date were no longer issued and outstanding.
Credit Risk
We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our commodity derivatives
consist of market participants and major financial institutions. This concentration of counterparties may impact our overall
exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in
economic, regulatory or other conditions. The counterparty to our call option derivative was TD.
Our derivative contracts are entered into with counterparties through central trading organizations such as futures, options
or stock exchanges or counterparties outside of central trading organizations. While we typically enter into derivative
transactions with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk in the future. The maximum potential exposure to credit losses on
our crude oil derivative contracts at December 31, 2018 was:
Gross.................................................................................................................................................. $
Netting agreement impact..................................................................................................................
Cash collateral held ...........................................................................................................................
Net exposure...................................................................................................................................... $
3,526
—
—
3,526
As of December 31, 2018, we did not have any cash in margin accounts or outstanding letters of credit in support of our
commodity derivatives. As of December 31, 2017, we had $3.0 million of cash in margin accounts and outstanding letters of
credit in support of our commodity derivative contracts.
Asset Position
(in thousands)
116
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 December 31, 2018 and
2017, based on the fair value hierarchy:
Asset Fair Value Measurements Using
Quoted prices in
active markets
for identical
assets
(Level 1)
Significant
other observable
inputs
(Level 2)
Significant
unobservable
inputs
(Level 3)
(in thousands)
Total
As of December 31, 2018:
Crude oil derivative contracts........................ $
3,526
$
— $
3,526
$
—
Liability Fair Value Measurements Using
Quoted prices in
active markets
for identical
assets
(Level 1)
Significant
other observable
inputs
(Level 2)
Significant
unobservable
inputs
(Level 3)
(in thousands)
Total
As of December 31, 2018:
Crude oil derivative contracts ..................... $
1,642
As of December 31, 2017:
Crude oil derivative contracts ..................... $
2,368
$
$
— $
1,642
— $
2,368
$
$
—
—
10. Long-term Debt
Long-term debt consisted of the following at December 31, 2018 and 2017:
December 31, 2018 December 31, 2017
Tallgrass Equity revolving credit facility (1) ...................................................... $
TEP revolving credit facility .............................................................................
TEP 4.75% senior notes due October 1, 2023...................................................
TEP 5.50% senior notes due September 15, 2024.............................................
TEP 5.50% senior notes due January 15, 2028 .................................................
Less: Deferred financing costs, net (2) .............................................................
Plus: Unamortized premium on 2028 Notes ...................................................
Total long-term debt, net ................................................................................... $
(in thousands)
— $
1,224,000
500,000
750,000
750,000
(21,421)
3,379
3,205,958
$
146,000
661,000
—
750,000
750,000
(17,737)
3,730
2,292,993
(1) On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility.
(2) Deferred financing costs, net as presented above relate solely to the Senior Notes (as defined below). Deferred
financing costs associated with our revolving credit facilities are presented in noncurrent assets on our consolidated
balance sheets.
117
TEP Senior Unsecured Notes
On September 26, 2018, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"),
the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 26,
2018 (the "2023 Indenture") pursuant to which the Issuers issued $500 million in aggregate principal amount of 4.75% senior
notes due 2023 (the "2023 Notes").
The 2023 Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted
subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or
merge with or into, or sell substantially all TEP's properties to, another person.
The Issuers have also previously issued $500 million in aggregate principal amount of 5.50% senior notes due 2028 (the
"2028 Notes") on September 15, 2017 and an additional $250 million in aggregate principal amount of the 2028 Notes on
December 11, 2017. The 2028 Notes issued on September 15, 2017 and December 11, 2017 are treated as a single class of debt
securities and have identical terms, other than the issue date and offering price. The 2028 Notes are governed by an Indenture
dated September 15, 2017 (the "2028 Indenture") which contains covenants that, among other things, limit TEP's ability and the
ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii)
consolidate with or merge with or into, or sell substantially all TEP's properties to, another person.
In addition, the Issuers have previously issued $400 million in aggregate principal amount of 5.50% senior notes due 2024
(the "2024 Notes") on September 1, 2016 and an additional $350 million in aggregate principal amount of the 2024 Notes on
May 16, 2017. The 2024 Notes issued on September 1, 2016 and May 16, 2017 are treated as a single class of debt securities
and have identical terms, other than the issue date, offering price and first interest payment date.
The 2024 Notes are governed by an Indenture dated September 1, 2016 (the "2024 Indenture") which contains covenants
that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee
additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests
in the event of default or noncompliance with the covenants required, repurchase equity securities or redeem subordinated
securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries;
(vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise
dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates.
The 2023 Notes, 2024 Notes, and 2028 Notes are together referred to as the "Senior Notes." As of December 31, 2018,
TEP was in compliance with the covenants required under the 2023 Indenture, the 2024 Indenture, and the 2028 Indenture.
TEP Revolving Credit Facility
The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of December 31,
2018 and 2017:
December 31, 2018 December 31, 2017
(in thousands)
Total capacity under the TEP revolving credit facility...................................... $
Less: Outstanding borrowings under the TEP revolving credit facility .......
Less: Letters of credit issued under the TEP revolving credit facility..........
Available capacity under the TEP revolving credit facility............................... $
2,250,000
(1,224,000)
(94)
1,025,906
$
$
1,750,000
(661,000)
(94)
1,088,906
On July 26, 2018, TEP and certain of its subsidiaries entered into Amendment No. 1 (the "Amendment") to its existing
revolving credit facility with Wells Fargo Bank, National Association, as administrative agent and collateral agent, and a
syndicate of lenders (the "Credit Agreement"). The Amendment modified certain provisions of the Credit Agreement to, among
other things, (i) increase the available amount of the TEP revolving credit facility to $2.25 billion, (ii) reduce certain applicable
margins in the pricing grids used to determine the interest rate and revolving credit commitment fees, (iii) modify the use of
proceeds to allow TEP to pay off the Tallgrass Equity revolving credit facility, and (iv) increase the maximum total leverage
ratio to 5.50 to 1.00.
TEP's revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or
restrict TEP's ability (as well as the ability of its restricted subsidiaries) to incur or guarantee additional debt, incur certain liens
on assets, dispose of assets, make certain distributions, including distributions from available cash, if a default or event of
default under the credit agreement then exists or would result therefrom, change the nature of its business, engage in certain
mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate
certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not
more than 5.50 to 1.00 (5.00 to 1.00 prior to the Amendment), a consolidated senior secured leverage ratio of not more than
118
3.75 to 1.00 and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of December 31, 2018, TEP was in
compliance with the covenants required under its revolving credit facility. The consummation of the Blackstone Acquisition
would constitute an event of default under TEP's revolving credit agreement. The closing conditions of the Blackstone
Acquisition include TEP obtaining the consent or waiver of the required lenders under TEP's revolving credit facility in
connection with the transactions contemplated by the Blackstone Acquisition.
The unused portion of TEP's revolving credit facility is subject to a commitment fee, which ranges from 0.250% to 0.375%
(0.250% to 0.500% prior to the Amendment), based on TEP's total leverage ratio. As of December 31, 2018, the weighted
average interest rate on outstanding borrowings under the TEP revolving credit facility was 3.96%. During the year ended
December 31, 2018, the weighted average effective interest rate under the TEP revolving credit facility, including the interest
on outstanding borrowings under TEP's revolving credit facility, commitment fees, and amortization of deferred financing
costs, was 4.11%.
Fair Value
The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value
in the consolidated balance sheets as of December 31, 2018 and 2017, but for which fair value is disclosed:
Fair Value
Quoted prices
in active markets
for identical assets
(Level 1)
Significant
other observable
inputs
(Level 2)
Significant
unobservable
inputs
(Level 3)
(in thousands)
Total
Carrying
Amount
As of December 31, 2018:
Revolving credit facility..... $
2023 Notes.......................... $
2024 Notes.......................... $
2028 Notes.......................... $
As of December 31, 2017:
Revolving credit facilities .. $
2024 Notes.......................... $
2028 Notes.......................... $
— $
— $
— $
— $
— $
— $
— $
1,224,000
485,285
737,745
726,503
807,000
771,645
758,168
$
$
$
$
$
$
$
— $ 1,224,000
$ 1,224,000
— $
485,285
— $
737,745
— $
726,503
— $
807,000
— $
771,645
— $
758,168
$
$
$
$
$
$
494,603
741,196
746,159
807,000
739,824
746,169
The long-term debt borrowed under the revolving credit facilities is carried at amortized cost. As of December 31, 2018
and 2017, the fair value of borrowings under the revolving credit facilities approximates the carrying amount of the borrowings
using a discounted cash flow analysis. The Senior Notes are carried at amortized cost, net of deferred financing costs. The
estimated fair value of the Senior Notes is based upon quoted market prices adjusted for illiquid markets. We are not aware of
any factors that would significantly affect the estimated fair value subsequent to December 31, 2018.
119
11. Partnership Equity
TGE Dividends to Holders of Class A Shares
The following table details the dividends for the periods indicated:
Date Paid
Three Months Ended
December 31, 2018 .............................. February 14, 2019 (1)....
September 30, 2018.............................. November 14, 2018 .....
June 30, 2018........................................ August 14, 2018...........
March 31, 2018 .................................... May 15, 2018...............
December 31, 2017 .............................. February 14, 2018........
September 30, 2017.............................. November 14, 2017 .....
June 30, 2017........................................ August 14, 2017...........
March 31, 2017 .................................... May 15, 2017...............
December 31, 2016 .............................. February 14, 2017........
September 30, 2016.............................. November 14, 2016 .....
June 30, 2016........................................ August 12, 2016...........
March 31, 2016 .................................... May 13, 2016...............
Dividends to Class A
Shareholders
Dividends per Class A
Share
$
81,304
$
79,717
77,052
28,316
21,346
20,617
19,891
16,697
16,116
12,528
11,693
10,022
0.5200
0.5100
0.4975
0.4875
0.3675
0.3550
0.3425
0.2875
0.2775
0.2625
0.2450
0.2100
(1) The dividend announced on January 15, 2019 for the fourth quarter of 2018 will be paid on February 14, 2019 to Class
A shareholders of record at the close of business on January 31, 2019.
Subsidiary Distributions
TEP Distributions. The following table shows the distributions for the periods indicated:
Three Months Ended
Date Paid
Limited Partner
Common Units
Distributions
General Partner
Incentive
Distribution
Rights
General
Partner
Units
Distribution
per Limited
Partner
Common
Unit
Total
March 31, 2018 ........ May 15, 2018 .............
December 31, 2017 .. February 14, 2018 ......
September 30, 2017 . November 14, 2017....
June 30, 2017 ........... August 14, 2017 .........
March 31, 2017 ........ May 15, 2017 .............
December 31, 2016 .. February 14, 2017 ......
September 30, 2016 . November 14, 2016....
June 30, 2016 ........... August 12, 2016 .........
March 31, 2016 ........ May 13, 2016 .............
(in thousands, except per unit amounts)
$
71,370
$
39,816
$ 1,267
$112,453
$
70,638
69,174
67,671
60,486
58,793
57,332
54,442
48,238
39,125
37,744
36,342
29,840
28,358
26,987
24,262
19,816
1,251
1,219
1,186
1,040
1,008
976
911
830
111,014
108,137
105,199
91,366
88,159
85,295
79,615
68,884
0.9750
0.9650
0.9450
0.9250
0.8350
0.8150
0.7950
0.7550
0.7050
As a result of the TEP Merger, Tallgrass Equity and its wholly-owned subsidiary, Tallgrass Equity Investments, LLC, will
receive all distributions paid by TEP for the second quarter of 2018 and subsequent periods.
120
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 year ended December 31, 2018,
2,821,332 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. As of February 8, 2019, the Exchange Right Holders primarily consist of Kelso & Company and its affiliated
investment funds ("Kelso"), The Energy & Minerals Group and its affiliated investment funds ("EMG"), and Tallgrass KC,
LLC ("Tallgrass KC"), which is an entity owned primarily by certain members of TGE's management.
As discussed in Note 22 – Subsequent Events, on January 31, 2018, we announced that affiliates of Blackstone
Infrastructure Partners (collectively, "BIP") had entered into a definitive purchase agreement with Kelso, EMG, and Tallgrass
KC (collectively, the "Sellers"), pursuant to which BIP will acquire from the Sellers 100% of the membership interests in our
general partner and an approximately 44% economic interest in us (the "Blackstone Acquisition"). One or more affiliates of
GIC Special Investment Pte. Ltd., the infrastructure and private equity arm of GIC Pte. Ltd., Singapore's sovereign wealth fund,
will be a minority investor in the Blackstone Acquisition. Following consummation of the Blackstone Acquisition, the
Exchange Rights Holders are expected to consist of BIP and certain members of TGE's management.
Equity Distribution Agreements
Neither TGE or TEP currently have equity distribution agreements in place. TEP was previously a party to equity distribution
agreements pursuant to which it sold from time to time through a group of managers, as its sales agents, TEP common units
representing limited partner interests. Following the TEP Merger, these agreements were terminated effective July 2, 2018. During
the year ended December 31, 2018, TEP did not issue any common units under its equity distribution agreements.
During the year ended December 31, 2017, TEP issued and sold 2,341,061 common units with a weighted average sales
price of $48.82 per unit under its equity distribution agreement for net cash proceeds of approximately $112.4 million (net of
approximately $1.9 million in commissions and professional service expenses). TEP used the net cash proceeds for general
partnership purposes as described above.
During the year ended December 31, 2016, TEP issued and sold 7,696,708 common units with a weighted average sales
price of $44.46 per unit under its equity distribution agreements for net cash proceeds of approximately $337.7 million (net of
approximately $4.5 million in commissions and professional service expenses). TEP used the net cash proceeds for general
partnership purposes as described above.
Repurchase of TEP Common Units Owned by TD
Following an offer received from TD with respect to TEP common units owned by TD not subject to the call option, TEP
repurchased 736,262 TEP common units from TD at an aggregate price of approximately $35.3 million, or $47.99 per common
unit, on February 1, 2017, which was approved by the conflicts committee of the board of directors of TEP's general partner.
These common units were deemed canceled upon TEP's purchase and as of such transaction date were no longer issued and
outstanding.
Secondary Offering
On November 17, 2016, TGE entered into an Underwriting Agreement (the "Underwriting Agreement"), by and among
TGE and certain selling shareholders named in the Underwriting Agreement (the "Selling Shareholders"), on one hand, and
Goldman, Sachs & Co., as the sole underwriter (the "Underwriter"), on the other hand, providing for the offer and sale by the
Selling Shareholders (the "Secondary Offering"), and purchase by the Underwriter, of 9,000,000 Class A shares at a price to the
public of $22.00 per share. Pursuant to the Underwriting Agreement, the Selling Shareholders also granted the Underwriter an
option for a period of 30 days to purchase up to an additional 1,350,000 Class A shares, on the same terms, which the
Underwriter exercised in full.
121
In connection with the Secondary Offering, Class A shares were issued to the Selling Shareholders upon the exercise by
each Selling Shareholder of its right to exchange all or a portion of its Tallgrass Equity units into Class A shares at an exchange
ratio of one Class A share for each Tallgrass Equity unit exchanged (the "Exchange Right"). Pursuant to the terms of the
Exchange Right, simultaneously therewith, the exercising Selling Shareholder transferred to TGE Class B shares in an amount
equal to the number of Tallgrass Equity units exchanged by such exercising Selling Shareholder. Upon each such exchange,
TGE cancelled the Class B shares received from the exercising Selling Shareholder. Immediately prior to the Secondary
Offering, we and the Exchange Right Holders owned approximately 30.35% and 69.65% of the Tallgrass Equity units,
respectively. At the completion of the Secondary Offering, we and the Exchange Right Holders owned 36.94% and 63.06% of
the Tallgrass Equity units, respectively.
Private Placement
On April 28, 2016, TEP issued an aggregate of 2,416,987 common units for net cash proceeds of $90 million in a private
placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C. The units were subsequently registered
pursuant to our Form S-3/A (File No. 333-210976) filed with the SEC on May 6, 2016, which became effective May 17, 2016.
Noncontrolling Interests
As of December 31, 2018, noncontrolling interests in our subsidiaries consisted of a 44.21% interest in Tallgrass Equity
held by the Exchange Right Holders, an approximate 40% membership interest in Deeprock Development, and a 37%
membership interest in BNN Colorado. During the year ended December 31, 2018, we recognized contributions from and
distributions to noncontrolling interests of $1.8 million and $327.6 million, respectively. Contributions from noncontrolling
interests consisted primarily of contributions from DER to Deeprock Development. Distributions to noncontrolling interests
consisted of Tallgrass Equity distributions to the Exchange Right Holders of $223.7 million, distributions to TEP unitholders of
$97.7 million, and distributions to Deeprock Development and Pony Express noncontrolling interests of $6.2 million.
During the year ended December 31, 2017, we recognized contributions from and made distributions to noncontrolling
interests of $1.6 million and $317.1 million, respectively. Contributions from noncontrolling interests consisted primarily of
contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders
of $185.7 million, Tallgrass Equity distributions to the Exchange Right Holders of $125.2 million, and distributions to Pony
Express and Deeprock Development noncontrolling interests of $6.2 million.
During the year ended December 31, 2016, we recognized contributions from and made distributions to noncontrolling
interests of $9.3 million and $249.1 million, respectively. Contributions from noncontrolling interests consisted primarily of
contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders
of $145.1 million, Tallgrass Equity distributions to the Exchange Right Holders of $97.5 million, and distributions to Pony
Express and Water Solutions noncontrolling interests of $6.5 million.
Other Contributions and Distributions
During the year ended December 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.
During the year ended December 31, 2017, TGE recognized the following other contributions and distributions:
• TEP was deemed to have made a noncash capital distribution of $57.7 million, which represents the excess purchase
price over the $82.3 million carrying value of the Terminals and NatGas net assets acquired January 1, 2017;
• TEP was deemed to have received a noncash capital contribution of $63.7 million, which represents the excess
carrying value of the additional 24.99% membership interest in Rockies Express acquired March 31, 2017 over the
fair value of the consideration paid; and
• TEP received contributions from TD of $2.3 million primarily to indemnify TEP for costs associated with Trailblazer's
Pipeline Integrity Management Program, as discussed in Note 19 – Legal and Environmental Matters.
122
During the year ended December 31, 2016, TGE recognized the following other contributions and distributions:
• TEP was deemed to have made noncash capital distributions of $280.0 million, which represent the excess purchase
price over the $417.7 million carrying value of the additional 31.3% membership interest in Pony Express acquired
effective January 1, 2016, partially offset by the 6,518,000 TEP common units (valued at approximately $268.6
million based on the December 31, 2015 closing price of our common units) issued to TD;
• TEP received contributions from TD of $17.9 million primarily to indemnify TEP for costs associated with
Trailblazer's Pipeline Integrity Management Program, as discussed above.
• TGE distributed the remaining $1.6 million in remaining proceeds from the TGE IPO to the Exchange Right Holders
that had been retained for short-term working capital needs.
12. Revenue from Contracts with Customers
As discussed in Note 2 – Summary of Significant Accounting Policies, we adopted the guidance in ASC Topic 606 effective
January 1, 2018 using the modified retrospective method of adoption. As a result, revenue reported for the years ended
December 31, 2017 and 2016 have not been revised. The following tables provide the impact of ASC Topic 606 on our
consolidated balance sheet as of December 31, 2018 and the consolidated statements of income for the year ended December
31, 2018:
Unconsolidated investments ............................................................. $
1,861,686
$
1,773,849
$
87,837 (1)
As currently
reported
December 31, 2018
Under
previous
guidance
(in thousands)
Impact of
ASC Topic
606
Year Ended December 31, 2018
As currently
reported
Under
previous
guidance
(in thousands)
Impact of
ASC Topic
606
Crude oil transportation services ...................................................... $
Sales of natural gas, NGLs, and crude oil ........................................ $
Processing and other revenues.......................................................... $
Cost of sales...................................................................................... $
Equity in earnings of unconsolidated investments ........................... $
Net income attributable to TGE........................................................ $
Basic net income per Class A share .................................................. $
Diluted net income per Class A share ............................................... $
398,334
168,586
99,445
114,815
306,819
137,127
1.27
1.27
$
$
$
$
$
$
$
$
398,329
173,055
104,117
123,458
261,848
121,402
1.13
1.13
$
$
$
$
$
$
$
$
5 (2)
(4,469) (3)
(4,672) (1)(3)
(8,643) (2)(3)
44,971 (1)
15,725
0.14
0.14
(1) Reflects the impact on our investment in Rockies Express and the management fee collected by NatGas of the
cumulative effect adjustment at Rockies Express, which arose as a result of the allocation of the transaction price to a
series of individual performance obligations in certain long-term transportation contracts with rates that vary
throughout the term of the contract. The adjustment increases the carrying amount of our investment in Rockies
Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue
that would have been earned by NatGas.
(2) Reflects the impact to revenue and cost of sales to value PLA barrels collected under certain crude oil transportation
arrangements at their contract inception fair value in revenue and record an associated lower of cost or net realizable
value adjustment in cost of sales.
(3) Reflects the reclassification of certain gathering and processing fees collected under arrangements determined to be
supply arrangements, rather than customer arrangements under ASC 606, to cost of sales and the reclassification of
certain commodities retained as consideration for processing services to processing fee revenue.
123
Disaggregated Revenue
A summary of our revenue by line of business is as follows:
Year Ended December 31, 2018
Natural Gas
Transportation
segment
Crude Oil
Transportation
segment
Gathering,
Processing, &
Terminalling
segment
(in thousands)
Corporate
and Other
Total
Revenue
Crude oil transportation - committed
shipper revenue ....................................... $
Natural gas transportation - firm service.
Water business services...........................
Natural gas gathering & processing fees.
All other (1)...............................................
Total service revenue..........................
Natural gas liquids sales..........................
Natural gas sales......................................
Crude oil sales .........................................
Total commodity sales revenue ..........
Total revenue from contracts with
customers.......................................
Other revenue (2) ......................................
— $
392,276
$
128,041
—
—
11,223
139,264
—
1,195
—
1,195
—
—
—
45,888
438,164
—
—
6,290
6,290
140,459
444,454
—
—
— $
—
52,333
24,109
18,444
94,886
101,382
29,558
652
131,592
226,478
53,187
Total revenue (3).............................. $
140,459
$
444,454
$
279,665
$
— $
392,276
(4,585)
—
—
(53,950)
(58,535)
—
—
—
—
123,456
52,333
24,109
21,605
613,779
101,382
30,753
6,942
139,077
(58,535)
(12,784)
(71,319) $
752,856
40,403
793,259
(1)
(2)
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.
Includes lease and derivative revenue not subject to ASC 606.
(3) Excludes $930.8 million of revenue recognized at Rockies Express, BNN Colorado, and Pawnee Terminal for the year
ended December 31, 2018. See Note 7 – Investments in Unconsolidated Affiliates for additional information.
Performance Obligations
A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of
account in ASC Topic 606. A contract's transaction price is allocated to each distinct performance obligation and recognized as
revenue when, or as, the performance obligation is satisfied. The majority of our contracts have a single performance obligation
and are billed and collected monthly.
All of our segments engage in commodity sales, in which our performance obligations include an obligation to deliver the
specified volume of a commodity to the designated receipt point. Revenue from commodity sales is recognized at a point in
time when the customer obtains control of the commodity, typically upon delivery to the designated delivery point when the
customer accepts and takes possession of the commodity.
In the Natural Gas Transportation segment, our performance obligations typically include an obligation to stand ready to
provide natural gas transportation, storage, or an integrated transportation and storage service over the life of the contract,
which is a series. These performance obligations are satisfied over time using each day of service to measure progress toward
satisfaction of the performance obligation.
In the Crude Oil Transportation segment, our performance obligations typically include an obligation to provide crude oil
transportation services over the life of the contract, which is a series. These performance obligations are satisfied over time
using barrels delivered to measure progress toward satisfaction of the performance obligation.
In the Gathering, Processing & Terminalling segment, the performance obligations vary based on the operating asset and
type of contract. In our natural gas gathering and processing arrangements, performance obligations typically include an
obligation to provide an integrated processing service over the life of the contract, which is a series. These performance
obligations are satisfied over time using each unit of gas processed to measure progress toward satisfaction of the performance
124
obligation. In our freshwater supply arrangements, performance obligations typically include an obligation to deliver a
specified volume of water to the designated receipt point. These performance obligations are satisfied at a point in time when
the customer obtains control of the water. In our produced water gathering and disposal arrangements, performance obligations
typically include an obligation to provide an integrated produced water gathering and disposal service over the life of the
contract, which is a series. These performance obligations are satisfied over time using barrels disposed to measure progress
toward satisfaction of the performance obligation.
On December 31, 2018, we had $1.6 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 future periods as follows (in thousands):
Year
2019...................................................................................................................................................
2020...................................................................................................................................................
2021...................................................................................................................................................
2022...................................................................................................................................................
2023...................................................................................................................................................
Thereafter ..........................................................................................................................................
Total..............................................................................................................................................
$
$
Estimated Revenue
532,549
357,226
170,713
163,852
140,101
210,625
1,575,066
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.
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 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
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remote. We also recognize contract liabilities, in the form of deferred revenue, under certain water business services contracts
in the Gathering, Processing & Terminalling segment. Contract balances as of December 31, 2018 were as follows:
Accounts receivable from contracts with customers ................................... $
Other accounts receivable............................................................................
Receivable from related parties ...................................................................
Accounts receivable, net......................................................................... $
Deferred revenue from contracts with customers (1) .................................... $
December 31, 2018
January 1, 2018
(in thousands)
80,935
$
151,414
3,748
236,097
111,095
$
$
61,888
56,727
1,340
119,955
88,471
(1) Revenue recognized during the year ended December 31, 2018 that was included in the deferred revenue balance at
the beginning of the period was $12.0 million. This revenue primarily represented the utilization of shipper
deficiencies at Pony Express.
13. Commitments & Contingent Liabilities
Leases and Right of Way Agreements
Rent expense under operating leases and right of way agreements totaled approximately $1.4 million, $9.5 million, and
$16.5 million for the years ended December 31, 2018, 2017, and 2016, respectively.
At December 31, 2018, future minimum rental commitments under major, non-cancelable leases and right of way
("ROW") agreements were as follows (in thousands):
Year
2019.......................................................................................................................
2020.......................................................................................................................
2021.......................................................................................................................
2022.......................................................................................................................
2023.......................................................................................................................
Thereafter ..............................................................................................................
Total.......................................................................................................................
Operating Lease
and ROW
Obligations
Capital Lease
Obligations
$
$
1,818
1,757
1,056
796
679
3,153
9,259
$
$
449
449
449
449
449
17,770
20,015
Operating leases consist of leases for office space and equipment. Prior to the acquisition of a controlling interest in
Deeprock Development in July 2017, as discussed in Note 3 - Acquisitions and Dispositions, rent expense included payments
made by Pony Express to Deeprock Development for the use by Pony Express of storage capacity at the Deeprock tank storage
facility near Cushing, Oklahoma. Capital lease obligations consist of the PLT land site lease, as discussed in Note 3 -
Acquisitions and Dispositions. The PLT land site lease includes a bargain purchase option exercisable after the initial lease
term. PLT satisfied the capital lease obligation of $30.7 million at lease inception, and as a result has no imputed interest on the
future minimum rental commitments in the table above. These future commitments represent certain administrative fees and
estimated payments to the Plaquemines Port & Harbor Terminal District which approximate the ad valorem taxes that would be
assessed if PLT acquired the land directly.
Capital Expenditures
We had committed approximately $39.6 million for the future purchase of property, plant and equipment at December 31,
2018.
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Other Purchase Obligations
At December 31, 2018, future minimum commitments under long-term, non-cancelable contracts for other purchase
obligations were as follows (in thousands):
Year
2019......................................................................................
$
2020......................................................................................
2021......................................................................................
2022......................................................................................
2023......................................................................................
Thereafter .............................................................................
Total......................................................................................
$
Total
13,467
11,198
6,677
5,604
5,614
13,231
55,791
14. 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 February 8, 2019, the Exchange
Right Holders primarily consist of Kelso, EMG and Tallgrass KC. Following consummation of the Blackstone Acquisition, the
Exchange Right Holders will primarily consist of BIP and certain members of TGE's management.
Pursuant to the TGE partnership agreement and the Tallgrass Equity limited liability company agreement, our capital
structure and the capital structure of Tallgrass Equity will generally replicate one another in order to maintain the one-for-one
exchange ratio between the Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other
hand. As a result, the exchange of any Class B shares for Class A shares does not have a dilutive effect on basic net income per
Class A share. However, for the years ended December 31, 2018 and 2016, the potential issuance of TGE Equity Participation
Shares would have had a dilutive effect on basic net income per Class A share. The potential issuance of TGE Equity
Participation Shares would not have had a dilutive effect on the basic net loss per Class A share for the year ended December
31, 2017.
All net income or loss from Terminals and NatGas prior to TEP's acquisition on January 1, 2017 is allocated to predecessor
operations in the consolidated statements of income. Accordingly, no net income or loss from Terminals and NatGas is
allocated to our Class A shareholders. We present the financial results of any transferred business prior to the transaction date in
the line item "Predecessor operations interest in net income" in the consolidated statements of income.
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The following table illustrates the calculation of net income per Class A share for the years ended December 31, 2018,
2017, and 2016:
Basic Net Income per Class A Share:
Net income (loss) attributable to TGE, excluding predecessor
operations interest ..................................................................................... $
Basic weighted average Class A Shares outstanding ................................
Basic net income (loss) per Class A share................................................. $
Diluted Net Income per Class A Share:
Net income (loss) attributable to TGE, excluding predecessor
operations interest ..................................................................................... $
Incremental net income attributable to TGE including the effect of
the assumed issuance of Equity Participation Shares...........................
Net income (loss) attributable to TGE including incremental net income
from assumed issuance of Equity Participation Shares ............................ $
Basic weighted average Class A Shares outstanding ................................
Equity Participation Shares equivalent shares .....................................
Diluted weighted average Class A Shares outstanding .............................
Diluted net income (loss) per Class A Share............................................. $
15. Major Customers and Concentration of Credit Risk
Year Ended December 31,
2018
2017
(in thousands, except per unit amounts)
2016
137,127
107,586
1.27
$
$
(128,729) $
58,076
(2.22) $
26,794
48,856
0.55
137,127
$
(128,729) $
26,794
2,108
—
139,235
$
107,586
2,231
109,817
(128,729) $
58,076
—
58,076
1.27
$
(2.22) $
9
26,803
48,856
33
48,889
0.55
During the years ended December 31, 2018 and 2017, one non-affiliated customer, Continental Resources, Inc.
("Continental Resources"), accounted for $81.9 million (10%) and $100.2 million (15%), of our total operating revenues,
respectively. During the year ended December 31, 2016, two non-affiliated customers, Continental Resources and Shell Trading
(US) Company ("Shell"), accounted for $97.8 million (16%) and $76.2 million (12%) of our total operating revenues,
respectively. Revenues from Continental Resources for the year ended December 31, 2018 were earned in our Crude Oil
Transportation and Gathering, Processing & Terminalling segments. Revenues from Continental Resources for the years ended
December 31, 2017 and 2016 were earned in our Crude Oil Transportation segment. Revenues from Shell for the year ended
December 31, 2016 were earned in our Natural Gas Transportation, Crude Oil Transportation, and Gathering, Processing &
Terminalling segments.
For the year ended December 31, 2018, the percentage of segment revenues from the top ten non-affiliated customers for
each segment was as follows:
Natural Gas Transportation ...............................................
Crude Oil Transportation ..................................................
Gathering, Processing & Terminalling..............................
58%
84%
60%
Percentage of
Segment Revenue
We attempt to mitigate credit risk by seeking credit support, such as letters of credit, prepayments or other financial
guarantees from customers with specific credit concerns.
16. Equity-Based Compensation
Long-term Incentive Plan
We have two long-term incentive plans. The Tallgrass Energy GP, LLC Long-Term Incentive Plan (f/k/a the TEGP
Management, LLC Long-Term Incentive Plan), was originally adopted by our general partner effective as of May 1, 2015, and
was amended and restated effective August 2, 2018 (as amended, the "TGE LTIP"). In addition, the Tallgrass MLP GP, LLC
Long-Term Incentive Plan was originally adopted by TEP GP effective as of May 13, 2013, and was amended and restated
effective August 2, 2018 (as amended, the "Legacy LTIP" and together with the TGE LTIP, the "Plans"). In connection with the
completion of the TEP Merger effective June 30, 2018, the Legacy LTIP was assumed by our general partner.
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Awards under the Plans may consist of, among others, unrestricted shares, restricted shares, equity participation shares,
options and share appreciation rights which may be granted to (i) the employees of our general partner and its affiliates who
perform services for us, (ii) the non-employee directors of our general partner and (iii) the consultants who perform services for
us. The TGE LTIP limits the number of shares that may be delivered pursuant to awards to 3,144,589 Class A shares, and the
Legacy LTIP limits the number of shares that may be delivered pursuant to awards under such plan to 20,000,000 Class A
shares, subject in each case to any adjustment due to recapitalization, reorganization or a similar event permitted under the
applicable Plan. Shares that are forfeited or withheld to satisfy exercise price or tax withholding obligations are available for
delivery pursuant to other awards under the applicable Plan. The Plans are administered by the board of directors of our general
partner or a committee thereof, which is referred to as the plan administrator.
Equity Participation Shares
Vesting of the Equity Participation Shares granted to date is contingent on certain service and performance conditions. The
Equity Participation Shares are non-participating; as such participants are not entitled to receive any dividends with respect to
the Equity Participation Shares unless the participant receives a separate grant of Distribution Equivalent Rights. At this time,
no grants of Distribution Equivalent Rights have been made.
The Equity Participation Share grants under the Plans are measured at their grant date fair value. The Equity Participation
Shares are non-participating; therefore, the grant date fair value is discounted from the grant date fair value of TGE's Class A
shares for the present value of the expected future dividends during the vesting period. Effective June 30, 2018 with the
completion of the TEP Merger, as discussed in Note 1 – Description of Business, TEP's outstanding Equity Participation Units
were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity
Participation Unit. Total equity-based compensation cost related to the Equity Participation Share grants was approximately
$7.6 million, $1.6 million, and $1.4 million for the years ended December 31, 2018, 2017, and 2016 respectively, excluding
costs associated with TEP's Equity Participation Units prior to the TEP Merger. Of the total compensation cost, $7.6 million,
$0.2 million, and $0.2 million for the years ended December 31, 2018, 2017, and 2016 respectively, were recognized as
compensation expense at TGE and the remainder was allocated to TEP and TD. As of December 31, 2018, $34.3 million of
total compensation cost related to non-vested Equity Participation Shares is expected to be recognized over a weighted-average
period of 3.2 years.
The following table summarizes the changes in the Equity Participation Shares outstanding for the years ended December
31, 2018, 2017 and 2016:
Equity
Participation
Shares
Weighted Average
Grant Date Fair
Value
Outstanding at January 1, 2016 .........................................................................
Granted .........................................................................................................
Outstanding at December 31, 2016 ...................................................................
Granted .........................................................................................................
Vested............................................................................................................
Outstanding at December 31, 2017 ...................................................................
Granted .........................................................................................................
Converted (1)..................................................................................................
Vested............................................................................................................
Forfeited........................................................................................................
Outstanding at December 31, 2018 ...................................................................
160,000
$
45,000
205,000
30,000
(10,002)
224,998
1,138,200
1,786,310
(20,664)
(79,200)
3,049,644
$
27.97
18.22
25.83
23.66
(14.26)
25.91
17.01
18.20
(19.19)
(20.62)
18.25
(1) Reflects TEP's outstanding Equity Participation Units that were converted to Equity Participation Shares at a ratio of
2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit upon completion of the TEP
Merger as discussed above.
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17. Income Taxes
Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions
in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of
assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when
taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be
recovered, a valuation allowance is established. We record a valuation allowance to reduce our deferred tax assets to the
amount we believe is more likely than not to be realized. In making these determinations we consider historical and projected
taxable income, and ongoing prudent and feasible tax planning strategies, in assessing the appropriateness of a valuation
allowance. Changes in tax legislation are included in the relevant computations in the period in which such changes are
effective.
U.S. Federal and State Taxes
Although we are organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income
tax purposes and are therefore subject to both U.S. federal and state income taxes. We are projecting a loss for both U.S. federal
and state income taxes for the tax year ended December 31, 2018. As a result, there is no current provision for income taxes for
the year ended December 31, 2018.
Tax Components
Components of the deferred income tax expense are as follows:
Year Ended December 31,
2018
2017
(in thousands)
2016
Deferred income tax expense:
Federal income tax ....................................................................... $
State income tax ...........................................................................
Total deferred income tax expense.................................................... $
41,585
14,124
55,709
$
$
200,787
7,671
208,458
$
$
15,587
2,154
17,741
The difference between tax expense based on the statuary federal income tax rate and our effective tax expense is
summarized as follows:
Net income before tax ....................................................................... $
Less: Predecessor operations interest in net income ....................
Net income before tax, excluding predecessor operations interest ...
Less: Net income attributable to noncontrolling interests............
Net income subject to tax.................................................................. $
Federal statutory income tax rate ......................................................
Income tax at statutory rate ............................................................... $
State income taxes, net of federal benefit .........................................
Change in state tax rate .....................................................................
Other..................................................................................................
Valuation allowance ..........................................................................
Total income tax expense before change in tax legislation............... $
Impact of federal tax legislation on deferred tax asset......................
Impact of federal tax legislation on valuation allowance..................
Total income tax expense.................................................................. $
Effective tax rate ...............................................................................
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Year Ended December 31,
2018
2017
(in thousands)
523,380
$
432,443
$
—
523,380
(330,544)
192,836
21%
40,496
5,419
8,705
1,089
—
$
$
—
432,443
(352,714)
79,729
35%
27,905
2,392
1,353
—
3,926
$
$
2016
267,780
(6,995)
260,785
(216,250)
44,535
35%
15,587
1,592
562
—
—
55,709
$
35,576
$
17,741
—
—
172,037
845
—
—
55,709
$
208,458
$
17,741
10.6%
48.2%
6.8%
Deferred tax assets result from the following:
December 31, 2018 December 31, 2017
(in thousands)
Deferred tax assets:
Investment in partnerships............................................................................ $
Net operating losses......................................................................................
Deferred tax assets before valuation allowance ................................................ $
Valuation allowance......................................................................................
Total deferred tax assets .................................................................................... $
198,290
80,012
278,302
(4,771)
273,531
$
$
$
269,136
48,632
317,768
(4,771)
312,997
Deferred tax liability: ........................................................................................
Equity earnings adjustment pursuant to ASC 606 ........................................ $
817
$
—
On May 12, 2015, as a result of the transfer of the ownership interest in Tallgrass Equity as part of the Reorganization
Transactions in connection with the TGE IPO, we recognized a deferred tax asset of $445.2 million. In November 2016, we
completed the Secondary Offering as discussed in Note 11 – Partnership Equity. In connection with the resulting transfer of
Tallgrass Equity Units, we recognized an additional deferred tax asset of $86.8 million. During 2018, a portion of the Exchange
Right Holders exercised their Exchange Right as discussed in Note 11 – Partnership Equity. In connection with the resulting
transfer of Tallgrass Equity Units, we recognized an additional deferred tax asset of $15.4 million. These transfers of ownership
were accounted for at the historical carrying basis for GAAP accounting purposes, but recorded at the value of the
consideration paid for U.S. federal income tax purposes. The tax rates that apply when the deferred tax balances ultimately
reverse are inherent in the realization of the deferred tax balances. State tax rates can change from year to year based upon
changes in both state apportionment percentages and state tax laws.
As of December 31, 2018, we had a federal net operating loss carry forward of $328.2 million and various state net
operating loss carry forwards. The determination of the state net operating loss carry forwards is dependent upon apportionment
percentages and state laws that can change from year to year and impact the amount of such carry forwards. If not utilized, the
federal net operating loss carry forward will expire between 2035 and 2037 and the state operating loss carry forwards will
expire between 2025 and 2037. We believe that it is more likely than not that the benefit from certain state operating loss
carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance on the deferred tax assets
relating to these carryforwards.
On December 22, 2017, legislation referred to as the "Tax Cuts and Jobs Act" ("TCJA") was signed into law. Substantially
all provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes amendments
to the Internal Revenue Code of 1986 that significantly change the taxation of individuals and business entities. Pursuant to
ASC Topic 740, Income Taxes (ASC 740), we recognized the tax effect of the TCJA changes during the year ended December
31, 2017, the period in which the law was enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the
enacted tax rate expected to apply when temporary differences are to be realized or settled. Accordingly, we remeasured our
deferred tax asset based on the new tax rates, resulting in an increase to our tax provision of $172.9 million for the year ended
December 31, 2017.
The 2015 through 2018 tax years are open to examination for federal and state tax.
18. Regulatory Matters
There are no regulatory proceedings challenging the rates of Pony Express, Rockies Express, or TIGT. 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
Petition for Declaratory Order – FERC Docket No. RP13-969-000
In June 2013, in Docket No. RP13-969-000, Rockies Express filed with the FERC a Petition for Declaratory Order which
sought a ruling that the "most favored nations" or "MFN" provisions contained in Rockies Express' negotiated rate agreements
("NRAs") with its Foundation and Anchor Shippers would not prevent Rockies Express from providing firm transportation
service at rates lower than Foundation and Anchor Shippers' rates that (1) have an east-to-west primary path; (2) are for a term
of one year or longer; and (3) are limited to service in one rate zone and therefore do not utilize all of the same facilities or rate
131
zones as the service provided pursuant to the Foundation and Anchor Shipper NRAs. In November 2013, the FERC issued a
declaratory order finding that the potential transactions would not trigger the MFN rights of Rockies Express' Foundation and
Anchor Shippers. Various parties filed requests for rehearing of the FERC's declaratory order.
In September 2014 and December 2015, the FERC accepted amended contracts with the shippers holding MFN rights on
Rockies Express, which reflect the terms of settlements between these shippers and Rockies Express. The settlements provide
additional clarity with respect to the applicability of the settling shippers' MFN rights, sharing by Rockies Express of certain
transportation revenues, and the withdrawal of the settling shippers from the Petition for Declaratory Order proceeding. On
September 27, 2017, FERC issued an order denying the requests for rehearing of the declaratory order issued in November
2013, and no party sought judicial appeal of the FERC order denying rehearing within the statutory deadline.
Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000
On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the FERC an application for (1) authorization
to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio
(Seneca Lateral Facilities described in Docket Nos. CP13-539-000 and CP14-194-000) from Natural Gas Policy Act of 1978
Section 311 authority to NGA Section 7 jurisdiction, and (2) issuance of a certificate of public convenience and necessity
authorizing Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC issued a
Certificate to Rockies Express granting its requested authorizations and on June 1, 2016 Rockies Express commenced NGA
service on the Seneca Lateral.
Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000
On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to
construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur
County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain
ancillary facilities. The facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 0.8 Bcf/d. Pursuant to
the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the
project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity
authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the
project facilities. The project was placed in-service for the full 0.8 Bcf/d on January 6, 2017.
2016 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP16-702-000 and RP17-240-000
On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in
Docket No. RP16-702-000. The FERC issued an order accepting the filing on March 25, 2016. On December 1, 2016, Rockies
Express made an interim fuel tracker filing with a proposed effective date of January 1, 2017 in Docket No. RP17-240-000. The
FERC issued an order accepting the filing on December 29, 2016.
Electric Power Charge Clarification - FERC Docket No. RP17-285-000
On December 21, 2016, in Docket No. RP17-285-000, Rockies Express proposed certain revisions to the General Terms
and Conditions of its tariff to clarify that the electric power costs associated with the operation of gas coolers installed in
association with the Zone 3 Capacity Enhancement Project at both electric and gas powered stations, will be included in the
Power Cost Tracker. Several shippers submitted comments on the proposal. The FERC issued an order on January 19, 2017
accepting the proposed revisions permitting the recovery of electric power costs from the operation of both gas and electric
powered compressor stations, subject to certain clarifications.
2017 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP17-401-000 and RP17-1064-000
On February 13, 2017, in Docket No. RP17-401-000, Rockies Express made its annual fuel and power cost tracker filing
with a proposed effective date of April 1, 2017. The FERC issued an order accepting the filing, including certain requested
waivers, on March 21, 2017. On September 20, 2017, Rockies Express made its interim fuel tracker filing in Docket No.
RP17-1064-000 with a proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on
October 18, 2017.
Increased Frequency of FL&U and PCT Adjustments - FERC Docket No. RP18-228-000
On December 1, 2017, in Docket No. RP18-228-000, Rockies Express made a filing with the FERC to increase the
frequency in which it may adjust fixed fuel and lost and unaccounted for retainages and power cost tracker charges during the
year so that its recovery of fixed fuel and lost and unaccounted for charges and power costs more closely track usage. Rockies
Express proposed an effective date of April 1, 2018. The comment period ended on December 13, 2017, and no parties opposed
Rockies Express' filing. On April 4, 2018, the FERC issued a letter order accepting Rockies Express' proposal, subject to
certain modifications. Rockies Express submitted a compliance filing reflecting the approved tariff provisions and requested
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modifications on April 10, 2018. No comments on the compliance filing were submitted by the comment deadline of April 16,
2018. On April 18, 2018, the FERC issued an order accepting Rockies Express' compliance filing effective April 19, 2018.
2018 Annual FERC Fuel Tracking Filing - FERC Docket No. RP18-453-000
On February 20, 2018, in Docket No. RP18-453-000, Rockies Express made its annual fuel and power cost tracker filing
with a proposed effective date of April 1, 2018. The FERC issued an order accepting the filing on March 19, 2018.
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.
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. The filing remains pending
before the FERC.
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.
TIGT
General Rate Case Filing - FERC Docket No. RP16-137-000, et seq.
On October 30, 2015, in Docket No. RP16-137-000, et seq., TIGT filed a general rate case with the FERC pursuant to
Section 4 of the NGA. The general rate case was ultimately resolved via settlement, which the FERC approved on November 2,
2016, and a compliance filing that modernized TIGT's FERC Gas Tariff, consistent with prior FERC orders, which the FERC
accepted on March 16, 2017. Per the terms of the settlement, TIGT is required to file a new general rate case on May 1, 2019
(provided that such rate case is not pre-empted by a pre-filing settlement).
2017 Annual Fuel Tracker Filing - FERC Docket No. RP17-428-000
On February 27, 2017, in Docket No. RP17-428-000, TIGT made its annual fuel tracker filing with a proposed effective
date of April 1, 2017. The filing incorporated the FL&U tracker and power cost tracker mechanisms agreed to in the TIGT Rate
Case Settlement. The FERC accepted the filing on March 21, 2017.
Electric Power Charge Clarification - FERC Docket No. RP17-1051-000
On September 15, 2017, in Docket No. RP17-1051-000, TIGT proposed certain revisions to its tariff to clarify, amongst
other things, that the electric power costs associated with the operation of gas coolers at both electric and gas powered stations
are properly included in the Power Cost Tracker. The FERC issued an order on October 3, 2017 accepting the proposed
revisions.
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2018 Annual Fuel Tracker Filing - FERC Docket No. RP18-533-000
On March 1, 2018, in Docket No. RP18-533-000, TIGT made its annual fuel tracker filing with a proposed effective date
of April 1, 2018. The FERC accepted the filing on March 22, 2018.
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.
Trailblazer
2016 Annual Fuel Tracker Filing – FERC Docket Nos. RP16-814-000 and RP16-814-001
On April 1, 2016, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2016 in Docket
No. RP16-814-000. The FERC accepted this filing on April 18, 2016. On May 19, 2016, Trailblazer filed its refund report
associated with the April 1, 2016 annual fuel tracker filing, which the FERC accepted on July 11, 2016. On September 7, 2016,
Trailblazer filed an adjustment to its April 1, 2016 filing in Docket No. RP16-814-001, which the FERC accepted on October 3,
2016. Trailblazer filed a corresponding refund report on October 14, 2016, which the FERC accepted on November 16, 2016.
2017 Annual and Interim Fuel Tracker Filings - FERC Docket Nos. RP17-549-000 and RP17-1052-000
On March 22, 2017, in Docket No. RP17-549-000, Trailblazer made its annual fuel tracker filing with a proposed effective
date of May 1, 2017. The FERC accepted the filing on April 19, 2017. On September 15, 2017, Trailblazer made its interim fuel
tracker filing in Docket No. RP17-1052-000 with a proposed effective date of November 1, 2017. The FERC accepted the
filing on October 13, 2017.
2018 Annual Fuel Tracker Filing - FERC Docket No. RP18-580-000
On March 22, 2018, in Docket No. RP18-580-000, Trailblazer made its annual fuel tracker filing with a proposed effective
date of May 1, 2018. The FERC accepted the filing on April 20, 2018.
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
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. The briefs remain
pending before the FERC. On August 28, 2018, the participants attended an initial settlement conference. On September 12,
2018, the Chief Administrative Law Judge issued an order continuing settlement judge procedures. On November 15, 2018, the
participants attended a second settlement conference. On December 31, 2018, Trailblazer filed a motion with the FERC to
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move the suspended tariff records into effect as of January 1, 2019. In January 2019, the participants attended a third settlement
conference. A fourth settlement conference is scheduled in late February 2019.
Pony Express
On May 25, 2016, Pony Express made a tariff filing with the FERC in Docket No. IS16-326-000 to update its non-contract
rates under its Local Pipeline Tariff for local non-contract rates from all origins, by an amount reflecting the most recent FERC
annual index adjustment of approximately 0.9799 effective July 1, 2016, which resulted in a reduction of the Pony Express
non-contract rates of 2.01%.
On May 22, 2017 and May 31, 2017, Pony Express made tariff filings with the FERC in Docket Nos. IS17-263-000,
IS17-464-000, and IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the FERC annual
index adjustment of approximately 0.2%, which became effective July 1, 2017.
On November 30, 2017, Pony Express filed with the FERC in Docket No. IS18-60-000 certain changes to its tariffs to
reflect the addition of two new destination points, which became effective January 1, 2018.
On December 29, 2017, Pony Express filed with the FERC in Docket No. IS18-113-000 certain changes to its tariffs to
reflect a new origin point in Rooks County, Kansas, which became effective on February 1, 2018.
On February 28, 2018, Pony Express filed with the FERC in Docket No. IS18-199-000 certain changes to its tariffs to
reflect a new origin point in Platteville, Colorado, which became effective on April 1, 2018.
On March 1, 2018, Pony Express submitted proposed revisions to its Rules and Regulations Tariff in Docket No.
IS18-204-000 to establish the right to accept "Specialty Batches" of oil that do not conform to the Quality Specifications
reflected in the tariff, provided that the acceptance is operationally feasible. These tariff changes became effective on April 1,
2018.
On April 11, 2018, Pony Express filed with the FERC in Docket No. IS18–267–000 certain changes to its tariffs to reflect
additional contract rates from a new origin point in Platteville, Colorado, which became effective May 1, 2018.
On May 2, 2018, Pony Express filed with the FERC in Docket No. IS18-297-000 certain changes to its rules and
regulations applicable to new intermediate off-system storage points, which became effective May 15, 2018.
On May 31, 2018, Pony Express made tariff filings with the FERC in Docket No. IS18-570-000 to increase the contract
and non-contract rates by an amount reflecting the FERC annual index adjustment of approximately 4.4% which became
effective July 1, 2018.
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 Petition is pending before the FERC.
19. 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 December 31, 2018 and 2017.
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
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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. While it is
difficult to accurately predict how the Ohio Supreme Court will decide the case, Rockies Express is optimistic about the
ultimate outcome.
As of December 31, 2018, Rockies Express has paid public utility excise taxes to the state of Ohio totaling $7.1 million,
accrued an additional $3.3 million for amounts expected to be assessed through the year ended December 31, 2018, and has
recognized a $10.4 million deposit representing the anticipated refund of the public utility excise taxes paid.
Mineral Management Service Lawsuit
On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S.
Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements
for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA")
conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay.
On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was
liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for
the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in
this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on
June 23, 2016.
Ultra Resources
In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2
Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14,
2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, seeking
approximately $303 million in damages and other relief. On April 29, 2016, Ultra and certain of its debtor affiliates filed for
protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District
of Texas, which operated as a stay of the Harris County state court proceeding.
On January 12, 2017, Rockies Express and Ultra entered into an agreement to settle Rockies Express' approximately $303
million claim against Ultra. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of
$150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express
commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37 per dth/d, or
approximately $26.8 million annually. We received our proportionate distribution from the cash settlement payment in July
2017.
Michels Corporation
On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the
Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral
Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract,
negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe
and Noble Counties, asserting $24.2 million as the amount due.
On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $10 million cash payment by
Rockies Express. The cash payment was inclusive of approximately $5.9 million that Rockies Express had been withholding
from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement
and Rockies Express made the $10 million cash payment to Michels on February 16, 2017.
Environmental, Health and Safety
We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality,
waste disposal, and other environmental matters. We 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 $7.4 million and $7.7 million at December 31,
2018 and 2017, respectively.
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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. Total cost of remediation was approximately $6.1 million prior
to any insurance recoveries. Permanent repairs were completed in September 2018. As of February 8, 2019, Rockies Express
has recovered a significant majority of these costs from insurance.
TMID
Casper Plant, EPA Notice of Violation
In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of
the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass
Midstream, LLC ("TMID") received a letter from the EPA alleging violations of the Standards of Performance of Equipment
Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the EPA
concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and
Department of Justice beginning in July 2014. Settlement negotiations are continuing, including the expected inclusion of TIGT
as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant
site.
Casper Mystery Bridge Superfund Site
The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery
Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and we have requested that the portion
of the site attributable to us be delisted from the National Priorities List. On July 3, 2017, our partial delisting request was
published by the EPA in the Federal Register. On August 3, 2017, there were no adverse public comments, therefore on August
29, 2017, the Casper Gas Plant portion of the Casper Mystery Bridge Superfund Site was delisted from the National Priorities
List.
Casper Gas Plant
On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the
Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with
WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues
and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as
well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely.
Settlement negotiations with WDEQ are currently ongoing.
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.
Trailblazer
Pipeline Integrity Management Program
Starting in 2014 Trailblazer's operating capacity was decreased as a result of smart tool surveys that identified
approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred
approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To
date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing
137
subscription levels or had a material adverse financial impact on us. However, Trailblazer continued performing remediation to
increase and maximize its operating capacity over the long-term and spent approximately $21 million during 2018 for this pipe
replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating
capacity. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a
general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
In connection with TEP's acquisition of Trailblazer in April 2014, TD agreed to indemnify TEP for certain out of pocket
costs related to repairing or remediating the Trailblazer Pipeline. The contractual indemnity was capped at $20 million and
subject to a $1.5 million deductible. TEP received the entirety of the $20 million from TD pursuant to the contractual indemnity
as of December 31, 2017.
Pony Express
Pipeline Integrity
In connection with certain crack tool runs on the Pony Express System completed in 2015, 2016, and 2017, Pony Express
completed approximately $18 million of remediation for anomalies identified on the Pony Express System associated with the
initial conversion and commissioning of portions of the pipeline converted from natural gas to crude oil service. Remediation
work was substantially complete as of March 31, 2018.
Terminals
System Failures
In January 2017, approximately 10,000 bbls of crude oil were released at the Sterling Terminal as the result of a defective
roof drain system on a storage tank. The release was restricted to the containment area designed for such purpose and
approximately 9,000 bbls were recovered. Remediation was complete as of June 30, 2017. The total cost to remediate the
release was approximately $600,000.
20. 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, and equity-based compensation
expense.
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 aggregate 75% membership
interest in Rockies Express, inclusive of the additional 25.01% membership interest acquired effective February 7, 2018.
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.
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. During the second quarter of 2018, upon completion of the TEP Merger,
management updated TGE's internal reporting. Beginning in the second quarter of 2018, we consider Adjusted EBITDA, as
described below, to be our primary segment performance measure.
138
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 picture of our overall financial and operational results.
The following tables set forth our segment information for the periods indicated:
2018
2017
2016
Year Ended December 31,
Revenue:
Total
Revenue
Inter-
Segment
External
Revenue
Total
Revenue
Inter-
Segment
External
Revenue
Total
Revenue
Inter-
Segment
External
Revenue
(in thousands)
Natural Gas
Transportation.......... $140,459
Crude Oil
Transportation..........
444,454
Gathering,
Processing &
Terminalling ............
279,665
Total revenue ........... $864,578
$ (4,661) $135,798
$141,021
$ (6,694) $134,327
$135,097
$ (5,641) $129,456
(39,319)
405,135
364,574
(10,676)
353,898
380,503
(370)
380,133
(27,339)
252,326
186,211
$(71,319) $793,259
$691,806
(18,538)
167,673
$(35,908) $655,898
113,533
$629,133
(11,460)
102,073
$(17,471) $611,662
139
Year Ended December 31,
Tallgrass Equity
Adjusted EBITDA:
Total
Adjusted
EBITDA
2018
Inter-
Segment
External
Adjusted
EBITDA
Total
Adjusted
EBITDA
2017
Inter-
Segment
(in thousands)
External
Adjusted
EBITDA
Total
Adjusted
EBITDA
2016
Inter-
Segment
External
Adjusted
EBITDA
Natural Gas
Transportation .............. $377,224
Crude Oil
Transportation ..............
239,330
$(4,251) $ 372,973
$180,978
$(2,176) $ 178,802
$ 75,029
$(1,633) $ 73,396
(8,147)
231,183
140,785
4,878
145,663
132,154
4,881
137,035
Gathering, Processing
& Terminalling .............
Corporate and Other .....
Reconciliation to Net
Income:
Add: ..............................
Equity in earnings
of unconsolidated
investments (1) ..........
Gain (loss) on
disposal of assets(1) ..
Non-cash gain (loss)
related to derivative
instruments (1) ..........
Gain on
remeasurement of
unconsolidated
investment (1)............
Less:.........................
Interest expense,
net(1) .........................
Depreciation and
amortization
expense (1) ................
Distributions from
unconsolidated
investments (1) ..........
Non-cash
compensation
expense (1) ................
Deficiency
payments, net (1).......
Loss on debt
retirement.................
Deferred income tax
expense ....................
Net income
attributable to
Exchange Right
Holders ....................
Net income (loss)
attributable to TGE ..
59,203
12,398
71,601
(21,321)
— (21,321)
16,083
(37,591)
(2,702)
13,381
— (37,591)
4,078
(2,142)
(3,248)
—
830
(2,142)
237,197
4,630
3,340
—
(95,465)
(74,998)
(302,364)
(8,634)
(14,443)
(2,245)
(55,709)
(208,618)
$ 137,127
66,922
189
(64)
2,744
(29,403)
(26,131)
(86,551)
(2,682)
(7,701)
—
(208,458)
(137,849)
$(128,729)
15,287
(526)
(650)
—
(16,632)
(25,567)
(22,085)
(1,862)
(9,672)
—
(17,741)
(95,882)
$ 33,789
(1) Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.
140
Capital Expenditures:
Natural Gas Transportation .................................................... $
Crude Oil Transportation........................................................
Gathering, Processing & Terminalling...................................
Corporate and Other ...............................................................
Total capital expenditures....................................................... $
Unconsolidated Investments:
Year Ended December 31,
2018
2017
(in thousands)
2016
112,529
$
16,705
$
65,745
185,732
4,867
57,022
71,417
—
368,873
$
145,144
$
28,475
29,893
26,123
—
84,491
December 31, 2018 December 31, 2017
(in thousands)
Natural Gas Transportation ........................................................................................ $
Crude Oil Transportation............................................................................................
Gathering, Processing & Terminalling.......................................................................
Total unconsolidated investments .............................................................................. $
1,794,987
$
35,467
31,232
1,861,686
$
895,873
—
13,658
909,531
Assets:
December 31, 2018 December 31, 2017
(in thousands)
Natural Gas Transportation ........................................................................................ $
Crude Oil Transportation............................................................................................
Gathering, Processing & Terminalling.......................................................................
Corporate and Other ...................................................................................................
Total assets ................................................................................................................. $
2,606,696
$
1,423,740
1,522,559
340,514
1,606,666
1,407,758
943,340
334,249
5,893,509
$
4,292,013
21. Selected Quarterly Financial Data (Unaudited)
The following tables summarize our unaudited quarterly financial data for 2018 and 2017:
Quarter Ended 2018
First
Second
Third
Fourth
(in thousands, except per unit amounts)
Total revenues...................................................................... $
Operating income ................................................................ $
Net income........................................................................... $
Net income allocable to noncontrolling interests ................ $
Net income attributable to TGE........................................... $
Basic net income per Class A Share .................................... $
Diluted net income per Class A Share ................................. $
179,094
81,913
$
$
114,313
$
(97,578) $
$
16,735
0.29
0.29
$
$
193,589
79,275
$
$
109,701
$
(108,638) $
$
1,063
0.02
0.02
$
$
200,320
90,084
$
$
118,712
$
(59,162) $
$
59,550
0.38
0.38
$
$
220,256
99,359
124,945
(65,166)
59,779
0.38
0.38
During the second quarter of 2018, we recognized increased deferred income tax expense as a result of our increased
ownership in TEP due to the TEP Merger and the resulting increase in income allocated to TGE.
141
Quarter Ended 2017
First
Second
Third
Fourth
(in thousands, except per unit amounts)
Total revenues...................................................................... $
Operating income ................................................................ $
Net income........................................................................... $
Net income allocable to noncontrolling interests ................ $
Net income (loss) attributable to TGE................................. $
Basic net income (loss) per Class A Share .......................... $
Diluted net income (loss) per Class A Share ....................... $
144,400
63,226
$
$
$
67,238
(55,209) $
$
12,029
0.21
0.21
$
$
160,863
66,944
$
$
$
79,167
(70,414) $
$
8,753
0.15
0.15
$
$
175,869
74,003
$
$
$
170,777
(154,911) $
$
15,866
0.27
0.27
$
$
174,766
67,674
(93,197)
(72,180)
(165,377)
(2.85)
(2.85)
During the third quarter of 2017, we recognized equity in earnings relating to our proportionate share of the Ultra
settlement discussed in Note 19 – Legal and Environmental Matters. During the fourth quarter of 2017, we remeasured our
deferred tax asset based on the new tax rates as a result of the federal rate change under the TCJA signed into law on December
22, 2017, resulting in an increase to our tax provision. For additional information, see Note 17 – Income Taxes.
22. Subsequent Events
Powder River Gateway
In January 2019, we closed on an expansion of our joint venture with Silver Creek. Effective January 1, 2019, we own a
51% membership interest in Powder River Gateway, which owns the Iron Horse Pipeline, the PRE Pipeline, and crude oil
terminal facilities in Guernsey, Wyoming. For additional information, see Note 3 – Acquisitions and Dispositions.
Blackstone Acquisition
On January 31, 2019, we announced that BIP had entered into a definitive purchase agreement with Kelso, EMG, and
Tallgrass KC pursuant to which BIP will acquire 100% of the membership interests in our general partner and an approximate
44% economic interest in us. Subject to customary closing conditions, the Blackstone Acquisition is expected to close within
the first quarter of 2019.
142
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of
our management, including our principal executive officer and principal financial officer, the effectiveness of the design and
operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of
the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable
assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such
information is accumulated and communicated to our management, including our principal executive officer and principal
financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon their evaluation of those
controls and procedures performed as of December 31, 2018, our principal executive officer and principal financial officer
concluded that our disclosure controls and procedures were effective.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as
defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process
designed under the supervision of our principal executive officer and principal financial officer to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes
in accordance with generally accepted accounting principles.
As of December 31, 2018, the Partnership's management assessed the effectiveness of our internal control over financial
reporting based on the criteria for effective internal control over financial reporting established in Internal Control - Integrated
Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this
assessment and those criteria, management determined that we maintained effective internal control over financial reporting as
of December 31, 2018.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our independent registered public accounting firm, PricewaterhouseCoopers LLP, audited the effectiveness of our internal
control over financial reporting as of December 31, 2018, as stated in their report included in Item 8.—Financial Statements
and Supplementary Data of this Annual Report.
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 December 31, 2018 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
143
Item 10. Directors, Executive Officers and Corporate Governance
PART III
We are a limited partnership and have no officers or directors. Unless otherwise indicated, references to our officers and
directors in Items 10 through 14 of this Annual Report refer to the officers and directors of our general partner.
Management of Tallgrass Energy, LP
Our general partner's board of directors and executive officers manage our operations and activities. Our general partner is
not elected by our Class A shareholders and will not be subject to re-election in the future. Directors of our general partner
oversee our operations. Class A shareholders are not entitled to elect the directors of our general partner or directly or indirectly
participate in our management or operations.
Unlike shareholders in a publicly traded corporation, our shareholders are not entitled to select our general partner or elect
the members of the board of directors of our general partner. Tallgrass Energy Holdings is the sole owner of our general partner
and has the right to appoint the entire board of directors of our general partner, including our independent directors. As of
February 8, 2019, EMG, Kelso and Tallgrass KC own, in the aggregate, approximately 100% of the outstanding membership
interests in Tallgrass Energy Holdings. Following consummation of the Blackstone Acquisition, the membership interests in our
general partner will be owned by BIP. As of February 8, 2019, all the executive officers and certain of the directors of our
general partner are also officers and/or directors of Tallgrass Energy Holdings.
As of December 31, 2018, the board of directors of our general partner had nine directors, four of whom the board has
determined meet the independence standards established by the NYSE. The four independent directors are Jeffrey A. Ball,
Thomas A. Gerke, Roy N. Cook and Terrance D. Towner. The NYSE does not require a publicly-traded limited partnership like
ours to have a majority of independent directors on the board of directors of its general partner or to establish a compensation
or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of
at least three members, and all its members are required to meet the independence and experience standards established by the
NYSE and the Exchange Act. As of December 31, 2018, the audit committee of the board of directors of our general partner
had four members, each of whom meet the independence and experience standards established by the NYSE and the Exchange
Act.
In evaluating director candidates, Tallgrass Energy Holdings assesses whether a candidate possesses the integrity,
judgment, knowledge, experience, skill and expertise that are likely to enhance the board's ability to manage and direct our
affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.
All the executive officers of our general partner are also officers of TEP GP, Tallgrass Equity, and Tallgrass Energy
Holdings. Our officers will devote such portion of their business time to our business and affairs as they deem reasonably
required to manage and conduct our operations. Our general partner and its affiliates do not currently receive any management
fee in connection with the management of our business, but Tallgrass Equity reimburses our general partner for all expenses it
incurs and payments it makes on our behalf pursuant to our partnership agreement. In addition, Tallgrass Equity reimburses
Tallgrass Energy Holdings and its affiliates for all expenses it incurs and payments it makes on our behalf pursuant to the TGE
Omnibus Agreement, including the costs of employee and director compensation and benefits as well as the cost of the
provision of certain corporate, general and administrative services in each case to the extent properly allocable to us. Any direct
expenses associated with being a separate publicly traded entity are borne by Tallgrass Equity. Neither our partnership
agreement nor the TGE Omnibus Agreement limits the amount of expenses for which our general partner, Tallgrass Energy
Holdings and their respective affiliates may be reimbursed. For more information, see "Certain Relationships and Related
Party Transactions, and Director Independence-Omnibus Agreement."
144
Directors and Executive Officers of Our General Partner
The following table sets forth certain information with respect to the executive officers and directors of our general partner
as of February 8, 2019.
Name
Age
Position with Our General Partner
David G. Dehaemers, Jr.
William R. Moler
Gary J. Brauchle
Christopher R. Jones
Gary D. Watkins
Frank J. Loverro
Stanley de J. Osborne
Jeffrey A. Ball
John T. Raymond
Thomas A. Gerke
Roy N. Cook
Terrance D. Towner
58
53
45
42
46
49
48
44
48
62
61
60
President, Chief Executive Officer and Director
Executive Vice President, Chief Operating Officer and Director
Executive Vice President and Chief Financial Officer
Executive Vice President, General Counsel and Secretary
Vice President and Chief Accounting Officer
Director
Director
Director
Director
Director
Director
Director
Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors are
duly elected or qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any
of the directors or executive officers of our general partner.
David G. Dehaemers, Jr. has been a director and the President and Chief Executive Officer of our general partner since
February 2015. Mr. Dehaemers has served as the President and Chief Executive Officer of TEP GP and Tallgrass Equity since
February 2013 and as a director and the President and Chief Executive Officer of Tallgrass Energy Holdings since August 2012.
Previously, Mr. Dehaemers served as a director of TEP GP from February 2013 to June 2018. Prior to joining our general
partner, Mr. Dehaemers served as Co-Founder, Chief Executive Officer and Chief Investment Officer of Tallgrass MLP Fund I,
L.P., a private MLP Investment Fund from 2008 to 2012. Mr. Dehaemers also served as Executive Vice President of corporate
development at Inergy, LP, or NRGY, from 2003 to 2007. Mr. Dehaemers played a role in NRGY's corporate development
group, where he focused on developing its long-term expansion strategies in the midstream area, which included acquisitions
and expansion projects in excess of $500 million. Mr. Dehaemers also was an owner of Inergy Holdings, L.P., or NRGP, when
that entity went public in 2005. Before Inergy, Mr. Dehaemers was part of the executive management team of Kinder Morgan,
Inc. and Kinder Morgan Energy Partners, LP from 1997 to 2003, where he served as the Chief Financial Officer from 1997 to
2000. In 2000, Mr. Dehaemers assumed responsibility for Kinder Morgan's corporate development efforts, in which role he and
his team developed and executed Kinder Morgan's growth strategies. Mr. Dehaemers holds an undergraduate degree in
Accounting from Creighton University in Omaha, Nebraska and is a Certified Public Accountant. He also holds a Juris
Doctorate in Law from University of Missouri-Kansas City. We believe that Mr. Dehaemers' education and experience, coupled
with the leadership qualities demonstrated by his executive background, bring important experience and skill to the boards of
directors of our general partner.
William R. Moler has been a director, Executive Vice President and Chief Operating Officer of our general partner since
February 2015. Mr. Moler has also served as Executive Vice President and Chief Operating Officer of TEP GP and Tallgrass
Equity since February 2013 and as a director, Executive Vice President and Chief Operating Officer of Tallgrass Energy
Holdings since October 2012. Previously, Mr. Moler served as a director of TEP GP from February 2013 to June 2018. From
2004 until his departure in October 2012, Mr. Moler served in various capacities with Inergy, L.P. and its affiliates, most
recently as Senior Vice President and Chief Operating Officer of Inergy Midstream, L.P. and President and Chief Operating
Officer—Natural Gas Midstream Operations of Inergy, L.P. Prior to joining Inergy, L.P., Mr. Moler was with Westport
Resources Corporation from 2002 to 2004, where he served as both General Manager of Marketing and Transportation Services
and General Manager of Westport Field Services, LLC. Prior to Westport, Mr. Moler served in various leadership positions at
Kinder Morgan, Inc. and its predecessors from 1988 to 2002. Mr. Moler has also served on the Board of the National
Parkinson's Foundation Heartland Region and served as its President from 2015 to 2017. Mr. Moler earned a Bachelor of
Science degree in Mechanical Engineering from Texas Tech University in 1988. We believe that as a result of his background
and knowledge, as well as the attributes of leadership demonstrated by his executive experience, Mr. Moler brings substantial
experience and skill to the boards of directors of our general partner.
145
Gary J. Brauchle has been Executive Vice President and Chief Financial Officer of our general partner since February
2015. Mr. Brauchle has also served as Executive Vice President and Chief Financial Officer of TEP GP and Tallgrass Equity
since February 2013 and of Tallgrass Energy Holdings since November 2012. Prior to joining Tallgrass, Mr. Brauchle was Vice
President and Chief Accounting Officer at McDermott International, Inc., a global engineering and construction company
serving the oil and gas industry during 2012 and as Corporate Controller from 2010 to 2012. He joined McDermott in 2003 and
served in various positions of increasing responsibility, including as Director of Internal Audit from 2005 to 2007 and as
Director of Operational Accounting and Assistant Controller for an operating subsidiary from 2007 to 2008 and 2008 to 2010,
respectively. Mr. Brauchle also served in the Houston office of PricewaterhouseCoopers' energy and utilities practice from 1997
to 2003, including as a Manager from 2001 to 2003, and with a focus on midstream master limited partnerships, or MLPs.
Mr. Brauchle was a postgraduate technical assistant at the Financial Accounting Standards Board (FASB) from 1996 to 1997.
Mr. Brauchle is a Certified Public Accountant and a graduate of Texas A&M University, where he received a Master of Science
in Accounting in 1996 and a Bachelor of Business Administration in Accounting in 1995.
Christopher R. Jones has been Executive Vice President, General Counsel and Secretary of our general partner since
February 2018. Mr. Jones has also served as Executive Vice President, General Counsel and Secretary of TEP GP and Tallgrass
Energy Holdings since February 2018. Previously, Mr. Jones served as Vice President, General Counsel and Secretary of our
general partner, TEP GP and Tallgrass Energy Holdings from May 2016 to February 2018 and was an Assistant General
Counsel at Tallgrass from October 2012 to May 2016. Prior to joining Tallgrass, Mr. Jones was an attorney with the law firm
that is now known as Stinson Leonard Street LLP from 2003 to 2012, becoming a partner in 2008. Mr. Jones holds an
undergraduate degree and a Juris Doctorate in Law from the University of Kansas.
Gary D. Watkins has been Vice President and Chief Accounting Officer and the principal accounting officer of our general
partner since February 2015. Mr. Watkins has also served as Vice President and Chief Accounting Officer of TEP GP since
April 2014 and of Tallgrass Equity and Tallgrass Energy Holdings since February 2015. Previously, Mr. Watkins served as Vice
President, Controller and principal accounting officer of DCP Midstream Partners, LP and DCP Midstream, LLC from May
2011 until April 2014. Prior to that, Mr. Watkins had held the positions of Senior Director—Marketing Accounting and Director
of Corporate Accounting with DCP Midstream, LLC. Prior to joining DCP Midstream, LLC in November 2004, Mr. Watkins
held various positions of increasing responsibility at Advanced Energy Industries, Inc. Mr. Watkins also served in the Denver
offices of Arthur Andersen LLP and KPMG LLP from 1996 through 2002.
Frank J. Loverro has served as a director of our general partner since February 2015 and as a director of Tallgrass Energy
Holdings since August 2012. Previously, Mr. Loverro served as a director of TEP GP from February 2013 to June 2018.
Mr. Loverro joined Kelso in 1993, has been Managing Director since 2004 and a Member of Kelso's Management Committee
since 2013, and in 2016 became Co-CEO. He spent the preceding three years in the private equity investment and high yield
groups at The First Boston Corporation. Mr. Loverro is also a director of Delphin Shipping LLC, Physicians Endoscopy, LLC,
Poseidon Containers Holdings LLC and Zenith Energy U.S., L.P. Mr. Loverro was also a director of Buckeye GP LLC.
Mr. Loverro received a B.A. in Economics with Distinction from the University of Virginia in 1991. Mr. Loverro has extensive
experience in corporate financing and in evaluating the financial performance and operations of companies across a variety of
business sectors, including the energy sector. We believe that this background, in addition to Mr. Loverro's valuable experience
serving on the boards of various public and private companies, provides an important source of insight and perspective to the
board of directors of our general partner.
Stanley de J. Osborne has served as a director of our general partner since February 2015 and as a director of Tallgrass
Energy Holdings since August 2012. Previously, Mr. Osborne served as a director of TEP GP from February 2013 to June 2018.
Mr. Osborne joined Kelso in 1998 and has been Managing Director since 2007. He spent the preceding two years as an
Associate at Summit Partners. He spent the previous three years at J.P. Morgan & Co. as an Associate in the Private Equity
Group and an Analyst in the Financial Institutions Group. Mr. Osborne is also a director of LBM Acquisition, LLC, Southern
Carlson and Traxys S.a.r.l. Mr. Osborne was also previously a director of CVR Energy, Inc. and Global Geophysical Services,
Inc. Mr. Osborne received a B.A. in Government from Dartmouth College in 1993. Mr. Osborne has extensive experience in
corporate financing and in evaluating the financial performance and operations of companies across a variety of business
sectors, including the energy sector. We believe that this background, in addition to Mr. Osborne's valuable experience serving
on the boards of various public and private companies, provides an important source of insight and perspective to the board of
directors of our general partner.
Jeffrey A. Ball has served as a director of our general partner since February 2015 and as the Chairman of the audit
committee of our general partner since April 2015. Further, Mr. Ball has served as a director of Tallgrass Energy Holdings since
August 2012. Previously, Mr. Ball served as a director of TEP GP from May 2013 to June 2018 and as the Chairman of the
audit committee of TEP GP from May 2013 to June 2018. Mr. Ball is a Managing Director at EMG, a diversified natural
resource private equity fund manager, and is responsible for transaction origination, structuring and execution, portfolio
company management and investment realization. Prior to joining EMG in October 2007, Mr. Ball was a Director in the
investment banking group at Credit Suisse Securities (USA), LLC, covering the energy industry with a particular focus on
146
MLPs and the midstream sector. Mr. Ball has completed over $55 billion of mergers and acquisitions and capital markets
financing transactions during his career in the energy and minerals sector. Mr. Ball currently serves on the Boards of Ferus Inc.,
Ferus GP LLC, Ferus Natural Gas Fuels Inc., Ferus Natural Gas Fuels GP, LLC, Ascent Resources, LLC, Sable Permian
Resources, LLC and is a board observer of MarkWest Utica EMG, LLC. Mr. Ball received a B.S. in Economics with honors
from the Wharton School at the University of Pennsylvania. We believe that Mr. Ball's experience with mergers & acquisitions
and financings of a variety of MLPs and other midstream assets provides a valuable resource to the board of directors of our
general partner.
John T. Raymond has served as a director of our general partner since February 2015 and as a director of Tallgrass Energy
Holdings since August 2012. Previously, Mr. Raymond served as a director of TEP GP from February 2013 to June 2018. Mr.
Raymond is an owner and founder of The Energy & Minerals Group. EMG is a diversified natural resource private equity fund
manager with approximately $16.0 billion of regulatory assets under management (RAUM) as of September 30, 2018. EMG
has allocated approximately $11.0 billion in commitments across the energy sector since inception. Mr. Raymond has been
Managing Partner and CEO since EMG's inception in 2006. Prior to that time, Mr. Raymond held leadership positions with
various energy companies, including President and CEO of Plains Resources Inc., President and Chief Operating Officer of
Plains Exploration and Production Company and Director of Development for Kinder Morgan, Inc. Mr. Raymond currently
serves on numerous other boards, including the board of directors of each of NGL Energy Holdings, LLC, the general partner
of NGL Energy Partners, LP, Plains All American GP LLC, the general partner of Plains All American Pipeline, LP, and PAA
GP Holdings LLC, the general partner of Plains GP Holdings, LP. Mr. Raymond received a BSM degree from the A.B. Freeman
School of Business at Tulane University with dual concentrations in finance and accounting. We believe that Mr. Raymond's
experience with investment in and management of a variety of upstream and midstream assets and operations provides a
valuable resource to the board of directors of our general partner.
Thomas A. Gerke has served as a director of our general partner and as a member of the audit committee of our general
partner since August 2015. Mr. Gerke has served as the General Counsel and Chief Administrative Officer at H&R Block, a
global consumer tax services provider since May 2016 and prior to that starting in January 2012, he served as Chief Legal
Officer. In addition, in 2017 while H&R Block went through a CEO transition, Mr. Gerke served as interim President and Chief
Executive Officer from August 1, 2017 to October 8, 2017. Prior to joining H&R Block, from January 2011 to April 2011, Mr.
Gerke served as Executive Vice President, General Counsel and Secretary of YRC Worldwide, a leading transportation service
provider. From July 2009 to December 2010, Mr. Gerke served as Executive Vice Chairman of CenturyLink, a Fortune 500
integrated communications business. From December 2007 to June 2009, he served as President and Chief Executive Officer at
Embarq, then a Fortune 500 integrated communications business. He also held the position of Executive Vice President and
General Counsel, Law and External Affairs at Embarq from May 2006 to December 2007. From October 1994 through May
2006, Mr. Gerke held several executive and legal positions with Sprint, serving as Executive Vice President and General
Counsel for over two years. Mr. Gerke currently serves as a member of the board of directors at Consolidated Communications
Holdings, Inc. (NASDAQ: CNSL). He is also a former member of the boards of CenturyLink, Embarq and United States
Telecom Association. In addition, he is a former member of the board of trustees for Rockhurst University and the Kansas City
Local Investment Commission (LINC). Mr. Gerke earned his Bachelor of Science degree in Business Administration from the
University of Missouri in Columbia, his Masters of Business Administration degree from Rockhurst University, and his Juris
Doctorate from the University of Missouri School of Law in Kansas City. We believe that Mr. Gerke's leadership roles and
board experience at a number of Fortune 500 and other large public companies, as well as his legal acumen and background
outside of the energy industry, provides a valuable resource to the board of directors of our general partner.
Roy N. Cook has served as a director of our general partner and as a member of the audit committee of our general partner
since September 2018. Previously, Mr. Cook served as a director of TEP GP from September 2013 to June 2018 and as a
member of the audit committee of TEP GP from December 2017 to June 2018. From 2001 to 2013, Mr. Cook was employed
by, and held a variety of roles within, the terminals division of Kinder Morgan, focusing on acquisitions, management, design
and operations and specializing in the dry bulk side of the terminals business. Prior to 2001, Mr. Cook owned and managed
several businesses in the service industry, including Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminals, Inc., each of
which were sold to Kinder Morgan in 2001. Mr. Cook currently owns several small businesses across diverse industries,
including a self-storage business, an electrical service company and a commercial real estate management and development
company. He graduated from Kansas State University in 1979 with a B.S. degree in Agriculture Economics. We believe that
Mr. Cook's MLP experience, and his intricate knowledge of the terminals business provides valuable strategic and practical
insight, and perspective to the board of directors of our general partner.
Terrance D. Towner has served as a director of our general partner and as a member of the audit committee of our general
partner since September 2018. Previously, Mr. Towner served as a director of TEP GP and as a member of the audit committee
of TEP GP from August 2013 to June 2018. Mr. Towner currently serves as the Executive Chairman of Jaguar Management Inc.
and its affiliates, which makes direct investments in and provides advisory services to various private companies and clients.
Mr. Towner is also a director of Base, Inc., Cando Rail Services Holdings, Inc., West Memphis Transload, West Memphis Base
147
Railroad and SilverCreek RCM. Prior to joining Jaguar Management, Inc. in November 2018, Mr. Towner provided business
advisory services. Between 2000 and December 2014, Mr. Towner was employed by Watco Companies, a Kansas based
transportation company, in various capacities, including Vice Chairman, President, COO and CFO. As President and COO, Mr.
Towner was responsible for all operations, safety, quality, human resources, information services and the financial performance
of Watco's transportation, mechanical, and terminal and port divisions. Prior to joining Watco, Mr. Towner spent thirteen years
in banking including three years as President and CEO of First State Bank & Trust Company of Pittsburg, Kansas. He also
served for five years as President of Pitsco, a company that develops and markets computer based education products, and
approximately two years as a financial and strategic consultant with Grant Thornton. Following his departure from Grant
Thornton, Mr. Towner acquired Joplin.com, an internet service provider located in Joplin, Missouri and subsequently sold the
company to Empire District Electric Company, a public utility. Mr. Towner earned his bachelor's degree in Economics from
Pittsburg State University in 1981 and his MBA from Pittsburg State University in 1993. We believe that Mr. Towner's business
acumen, and a unique perspective on the midstream services industry, helps provide valuable strategic and practical guidance,
insight, and perspective to the board of directors of our general partner.
Audit Committee
The board of directors of our general partner has a standing audit committee which is currently comprised of four directors,
Jeffrey A. Ball, Thomas A. Gerke, Roy N. Cook, and Terrance D. Towner. Each audit committee member has past experience in
accounting or related financial management experience. The board has determined that all our audit committee members are
independent under Section 303A.02 of the NYSE listing standards and Rule 10A-3 of the Securities Exchange Act of 1934, as
amended. In making the independence determination, the board considered the requirements of the NYSE, the SEC and our
Code of Business Conduct and Ethics. Among other factors, the board considered current or previous employment with us, our
auditors or their affiliates by the director or his immediate family members, ownership of our voting securities and other
material relationships with us. The audit committee has adopted a charter, which has been ratified and approved by the board of
directors.
Jeffrey A. Ball has been designated by the board as the audit committee's financial expert meeting the requirements
promulgated by the SEC and set forth in Item 407(d) of Regulation S-K of the Securities Exchange Act of 1934, as amended,
based upon his education and employment experience as more fully detailed in Mr. Ball's biography set forth above. Mr. Ball
also acts as the Chairman of our audit committee.
A copy of the Audit Committee Charter is available to any person, free of charge, at our website at
www.tallgrassenergy.com.
Conflicts Committee
Our general partner may, from time to time, have a conflicts committee to which the board of directors will appoint at least
two independent directors and which may be asked to review specific matters that the board believes may involve conflicts of
interest between us and our general partner or the owners of our general partner. The conflicts committee will determine if the
resolution of any conflict of interest referred to it by our general partner is in the best interests of our partnership. There is no
requirement that our general partner seek the approval of the conflicts committee for the resolution of any conflict. The
members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees
of its affiliates, may not hold an ownership interest in the general partner or its affiliates other than shares or awards under any
long-term incentive plan, equity compensation plan or similar plan implemented by the general partner or us, and must meet the
independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a
board of directors.
Any matters approved by the conflicts committee will be conclusively deemed to have been approved by all of our
partners, and shall not constitute a breach by our general partner of any duties it may owe us or our shareholders. Any
shareholder challenging any matter approved by the conflicts committee will have the burden of proving that the members of
the conflicts committee did not subjectively believe that the matter was in the best interests of our partnership. Moreover, any
acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants,
appraisers, management consultants and investment bankers, where our general partner (or any members of the board of
directors of our general partner including any member of the conflicts committee) reasonably believes the advice or opinion to
be within such person's professional or expert competence, shall be conclusively presumed to have been done or omitted in
good faith.
Corporate Governance Guidelines and Code of Business Conduct and Ethics
Our general partner has adopted Corporate Governance Guidelines and a Code of Business Conduct and Ethics applicable
to all of our employees, officers and directors with regard to Partnership-related activities. The Corporate Governance
Guidelines and the Code of Business Ethics incorporate guidelines designed to deter wrongdoing and to promote honest and
ethical conduct and compliance with applicable laws and regulations. They also incorporate expectations of our employees that
148
enable us to provide accurate and timely disclosure in our filings with the SEC and other public communications. A copy of the
Corporate Governance Guidelines and the Code of Business Conduct and Ethics are available to any person, free of charge, at
our website at www.tallgrassenergy.com.
The Chairman of the audit committee of our general partner, currently Jeffrey A. Ball, presides over any executive session
of the board of directors of our general partner in which the members of our management are not present. Interested parties
may communicate directly with the independent members of the board of directors of our general partner by submitting in an
envelope marked "Confidential" addressed to the "Independent Members of the Board" in care of the Secretary of the General
Partner at: Tallgrass Energy, LP, 4200 W. 115th Street, Suite 350, Leawood, Kansas 66211.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires members of our general partner's board of directors, executive officers of our
general partner, and persons who own more than 10% of a registered class of our equity securities, to file with the SEC, and
any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes
in ownership of our Class A shares, Class B shares and other equity securities. Officers, directors and greater than 10%
shareholders are required by the SEC's regulations to furnish to us and any exchange or other system on which such securities
are traded or quoted with copies of all Section 16(a) forms they file with the SEC.
Based solely upon a review of Forms 3, 4 and 5, and amendments thereto, we know of no director, officer, or beneficial
owner of more than 10% of any class of our equity securities registered pursuant to Section 12 of the Exchange Act that failed
to file timely any reports required to be furnished during 2017 pursuant to Section 16(a) of the Exchange Act.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Executive Summary and Background
We and our general partner were formed in Delaware in February 2015. Our general partner did not accrue any obligations
with respect to management incentive or retirement benefits for its directors and executive officers until after our initial public
offering in May 2015. Our business is managed and operated by the directors and executive officers of our general partner. All
employees, including our Named Executive Officers (as defined in "Summary Compensation Table" below), are employed by
Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018, Tallgrass Management was a wholly-owned
subsidiary of Tallgrass Energy Holdings. Effective July 1, 2018, Tallgrass Management was contributed to Tallgrass Equity in
connection with the TEP Merger. As a result, the costs of employer and director compensation and benefits are now incurred
directly by Tallgrass Equity.
Compensation of our Named Executive Officers is set and approved by the board of directors of our general partner and by
the board of managers of Tallgrass Energy Holdings, which controls our general partner. Prior to July 1, 2018, we reimbursed
Tallgrass Energy Holdings and its affiliates for all salaries, benefits and other compensation expenses for employees of
Tallgrass Management (including the Named Executive Officers) to the extent such employees provided services to us pursuant
to an allocation agreed upon between our general partner and Tallgrass Energy Holdings under the terms of the TGE Omnibus
Agreement. Other than the employment agreement with our Chief Executive Officer, David G. Dehaemers, Jr., none of our
Named Executive Officers has entered into any employment agreements with Tallgrass Management, our general partner or any
other affiliate of TGE.
Philosophy and Objectives
Since our initial public offering in May 2015, we have employed a compensation philosophy that emphasizes pay for
performance and places the majority of each Named Executive Officer's compensation at risk. We believe our pay-for-
performance approach aligns the interests of our Named Executive Officers with that of our Class A shareholders, and at the
same time enables us to maintain a lower level of recurring compensation costs in the event our operating or financial
performance is below expectations. We design our executive compensation to attract and retain individuals with the background
and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to
reach near-term and long-term goals in a way that aligns their interest with that of our Class A shareholders, and to reward
success in reaching such goals.
We use three primary elements of compensation to fulfill that design: salary, bonuses and long-term equity incentive
awards. Bonuses and long-term equity incentives (as opposed to salary) generally represent the performance driven elements.
They are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals'
bonuses is based on their relative contribution to achieving or exceeding relative near-term company goals and the
determination of specific individuals' long-term incentive equity awards is based on their actual and anticipated contribution to
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longer term performance objectives. The primary long-term measure of our performance is our ability to increase quarterly
dividends to our Class A shareholders while maintaining safe operations and long-term stable cash flow and financial health.
We do not maintain a defined benefit or pension plan for our Named Executive Officers as we believe such plans primarily
reward longevity and not performance. We provide a basic benefits package generally to all employees, which includes a
401(k) plan and health, disability and life insurance.
Elements of Compensation
Salary. We benchmark our salary amounts to comparable companies in our industry. We believe our salaries are generally
competitive with the universe of similarly situated midstream energy companies, but are moderate relative to energy industry
competitors for people with similar roles and responsibilities.
Bonuses. Our bonuses are annual discretionary bonuses in which all of our current Named Executive Officers potentially
participate. Our bonuses to Named Executive Officers generally consist of a cash bonus. In 2018, Mr. Brauchle, Mr. Moler and
Mr. Jones were granted awards under the Legacy LTIP (as defined below) as an additional component of their 2018 bonus.
These awards were granted on January 31, 2019 and vested immediately. The recipients of these awards will receive the Class
A shares as a result of the vesting on January 31, 2020.
Awards under Long-Term Incentive Plans. We have two long-term incentive plans. The Tallgrass Energy GP, LLC Long-
Term Incentive Plan (f/k/a the TEGP Management, LLC Long-Term Incentive Plan), was originally adopted by our general
partner effective as of May 1, 2015, and was amended and restated effective August 2, 2018 (as amended, the "TGE LTIP"). In
addition, the Tallgrass MLP GP, LLC Long-Term Incentive Plan was originally adopted by TEP GP effective as of May 13,
2013, and was amended and restated effective August 2, 2018 (as amended, the "Legacy LTIP" and together with the TGE
LTIP, the "Plans"). In connection with the completion of the TEP Merger effective June 30, 2018, discussed in Note 1 –
Description of Business, the Legacy LTIP was assumed by our general partner and TEP's outstanding equity participation units
were converted to equity participation shares at a ratio of 2.0 equity participation shares for each outstanding TEP equity
participation unit.
Awards under the Plans may consist of, among others, unrestricted shares, restricted shares, equity participation shares,
options and share appreciation rights which may be granted to (i) the employees of our general partner and its affiliates who
perform services for us, (ii) the non-employee directors of our general partner and (iii) the consultants who perform services for
us (such awards, the "LTIP Awards"). Historically, we have used equity participation share awards under the Plans to encourage
and reward timely achievement of certain events or dividend levels and align the long-term interests of our Named Executive
Officers with those of our Class A shareholders. An equity participation share is the right to receive, upon the satisfaction of
vesting criteria specified in the grant, a Class A share. Equity participation share awards under the Plans have been, and we
expect will continue to be, the primary long-term equity incentive provided to our Named Executive Officers and appropriately
incentivizes our Named Executive Officers to seek stable dividend growth.
Vesting Conditions. The vesting conditions applicable to the equity participation shares held by Named Executive Officers
that are outstanding under the Plans can generally be divided into the following categories:
• The first category of awards was originally granted by TEP between August 2015 and September 2015 with vesting
occurring in two parts. One-half vests on the later to occur of the first date on which TEP paid a regular quarterly
distribution of at least $0.6875 on each outstanding common unit (the "TEP Distribution Achievement Date") or May
13, 2018, and the other half vests on the later to occur of the TEP Distribution Achievement Date or May 13, 2019.
The TEP Distribution Achievement Date occurred on May 13, 2016, and the first half of the awards in this category
vested on May 13, 2018. The remaining half will vest on May 13, 2019 as long as the employee satisfies the
continuing service requirement set forth in the applicable award agreement. Mr. Jones and Mr. Watkins are the only
Named Executive Officers that were granted equity participation shares in this category. The Blackstone Acquisition
constitutes a change of control with respect to the awards in this category and as a result, any outstanding awards in
this category will vest upon consummation of the Blackstone Acquisition.
• The second category of awards was granted by TGE in 2015 to Mr. Jones and to Mr. Watkins. The terms of the awards
to Mr. Jones and Mr. Watkins each stipulate that the equity participation shares will generally vest upon the later of the
first date on which TGE pays a regular quarterly dividend of at least $0.35 on each outstanding Class A share (the
"TGE Dividend Achievement Date") or May 12, 2019. The TGE Dividend Achievement Date was met upon payment
of the $0.3550 dividend declared for the third quarter of 2017, thus these awards will vest on May 12, 2019 as long as
the employee satisfies the continuing service requirement set forth in the applicable award agreement. The Blackstone
Acquisition constitutes a change of control with respect to the awards in this category and as a result, any outstanding
awards in this category will vest upon consummation of the Blackstone Acquisition.
• The third category of awards was originally granted by TEP in November 2016 and will vest on November 1, 2019 as
long as the employee satisfies the continuing service requirement set forth in the applicable award agreement. Mr.
150
Jones and Mr. Watkins are the only Named Executive Officers that were granted equity participation shares in this
category. The Blackstone Acquisition constitutes a change of control with respect to the awards in this category and as
a result, any outstanding awards in this category will vest upon consummation of the Blackstone Acquisition.
• The fourth category of awards was originally granted by TEP in August 2017 (the "2017 Grants") and will vest on the
earliest date on or after April 1, 2021, on which the average compounded annual distribution growth rate for TGE's
regular quarterly distributions, based upon the regular quarterly distribution paid by TGE on, or immediately prior to,
such date is at least 5% over an annualized distribution rate of $1.67 per TGE Class A share, as determined by the
board of directors of our general partner. If such date has not occurred by August 2, 2024, such equity participation
shares will expire and terminate and no vesting will occur. Mr. Jones and Mr. Watkins are the only Named Executive
Officers that were granted equity participation shares in this category. The 2017 Grants do not vest solely as a result of
the consummation of the Blackstone Acquisition. See "Potential Payments upon Termination or Change-in-Control"
for a description of the conditions that would accelerate vesting of the 2017 Grants.
• The fifth category of awards was originally granted by TEP in February 2018 and will vest on January 1, 2020 as long
as the employee satisfies the continuing service requirement set for in the applicable award agreement. Mr. Brauchle,
Mr. Moler, and Mr. Jones are the only Named Executive Officers that were granted equity participation shares in this
category. The Blackstone Acquisition constitutes a change of control with respect to the awards in this category and as
a result, any outstanding awards in this category will vest upon consummation of the Blackstone Acquisition.
• The sixth category of awards was granted by TGE in October 2018 (the "2018 Grants") and will vest on the earliest
date on or after November 1, 2022, on which the average compounded annual distribution growth rate, based upon the
regular quarterly distribution paid by TGE on, or immediately prior to, such date is at least 5% over an annualized
distribution rate of $1.99 per TGE Class A share, as determined by the board of directors of our general partner. If such
date has not occurred by October 19, 2025, such equity participation shares will expire and terminate and no vesting
will occur. Mr. Jones and Mr. Watkins are the only Named Executive Officers that were granted equity participation
shares in this category. The 2018 Grants do not vest solely as a result of the consummation of the Blackstone
Acquisition. See "Potential Payments upon Termination or Change-in-Control" for a description of the conditions that
would accelerate vesting of the 2018 Grants.
Relation of Compensation Elements to Compensation Objectives
Our compensation program is designed to motivate, reward and retain our Named Executive Officers. Bonuses serve as a
near-term motivation and reward for achieving positive short-term results, such as meeting specified dividend growth and other
financial guidance targets. Longer-term retention is facilitated by the requirement for continued employment or service for
specified time periods in order for LTIP Awards to fully vest. The level of bonuses and LTIP Awards reflect the moderate salary
profile of our Named Executive Officers and the weighting towards performance based, at-risk compensation.
We strive to focus on performance-based compensation elements in an attempt to create a performance-driven environment
in which our Named Executive Officers are (i) motivated to perform over both the short-term and the long-term,
(ii) appropriately rewarded for their services and (iii) encouraged to remain with us even after meeting long-term performance
goals. We believe our compensation philosophy as implemented by application of the three primary compensation elements
(i) aligns the interests of our Named Executive Officers with our Class A shareholders, (ii) positions us to achieve our business
goals, and (iii) effectively encourages the exercise of sound judgment and risk-taking that is conducive to creating and
sustaining long-term value. We believe the processes we employ to apply the elements of compensation (as discussed in more
detail below) provide an adequate level of oversight with respect to the degree of risk being taken by management to achieve
short-term and long-term performance goals. See "Relation of Compensation Policies and Practices to Risk Management."
We believe our compensation program has been instrumental in our achievement of stated objectives. One of the primary
measures of our performance is our ability to enhance the ability of our assets to generate cash available for dividends that we
can use to increase quarterly dividends to our Class A shareholders. In the period since our initial public offering through
December 31, 2018, our compounded annual dividend growth rate is 48%. This dividend growth has, in part, supported our
decision to pay bonuses to our Named Executive Officers related to that period.
Application of Compensation Elements
Salary. We do not make systematic annual adjustments to the salaries of our Named Executive Officers. We do, however,
make salary adjustments as necessary to ensure that our salaries remain competitive in the industry marketplace.
Annual Discretionary Bonuses. Annual discretionary bonuses are determined based on our performance relative to our
annual budget, our dividend growth targets, and other quantitative and qualitative goals established each year. Such annual
objectives are discussed and reviewed with the board of directors periodically during the year and then again in conjunction
with the review and authorization of the annual budget and this annual report.
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At the end of each year, the CEO, with assistance from other members of executive management, performs a quantitative
and qualitative assessment of our performance relative to our goals. Key quantitative measures include Adjusted EBITDA, cash
available for dividend, dividend coverage, and growth in the annualized quarterly dividend level per Class A share relative to
annual growth targets. We also compare our market performance relative to our peers and major indices. Our primary
performance metric is our ability to generate increasing and sustainable cash dividends to our Class A shareholders.
Accordingly, although net income and net income per unit are monitored to highlight inconsistencies with our primary
performance metrics, we do not consider net income and net income per unit to be key performance measures. Executive
management's analysis of our performance examines our accomplishments, shortfalls and overall performance against
opportunity, taking into account controllable and non-controllable factors encountered during the year.
After the annual company-level performance analysis is completed by our CEO and other members of executive
management, that same group, along with personnel from our human resources department, considers bonuses and salary
adjustments for our employees, including our Named Executive Officers. There are no set formulas for determining salary
adjustments or annual discretionary bonuses for our Named Executive Officers. Factors considered by executive management
in determining the level of salary adjustment and bonus in general include (i) whether or not we achieved any goals established
for the year and any notable shortfalls relative to expectations; (ii) the level of difficulty associated with achieving any such
objectives based on the opportunities and challenges encountered during the year; (iii) current year operating and financial
performance relative to both public guidance and prior year's performance; (iv) significant transactions or accomplishments for
the period not included in the goals for the year; (v) our prospects at the end of the year with respect to future growth and
performance; and (vi) our positioning at the end of the year with respect to our targeted credit profile. The CEO and other
members of executive management take these factors into consideration, as well as the relative contributions of each of our
Named Executive Officers to the year's performance, in developing recommendations for Named Executive Officer bonus
amounts and salary adjustments.
These recommendations for discretionary bonus amounts and salary adjustments for our Named Executive Officers are
presented to the board of directors of our general partner and the board of managers of Tallgrass Energy Holdings, adjusted as
appropriate, and then formally approved by those boards. In several historical instances, the CEO has requested that his bonus
amount be reduced or eliminated.
Long-Term Incentive Awards. We do not make systematic annual grants of LTIP Awards to our Named Executive Officers.
We have historically attempted to time the granting of LTIP Awards such that the creation of new long-term incentives
coincides with the satisfaction of vesting criteria under existing awards. We have not formally decided on a recurring grant
cycle for future grants, but we intend for future grants to provide a balance between a meaningful retention period for us and a
visible, reasonable, growth-oriented reward for the Named Executive Officer. Under existing LTIP Awards, achievement of
performance targets does not shorten the minimum service period requirement.
Application in 2018
In connection with the announcement of the TEP Merger in March 2018, we established the following financial
performance objectives for 2018:
• Adjusted EBITDA of $755 - $835 million for the year ended December 31, 2018;
• Maintenance capital of $20 - 30 million for the year ended December 31, 2018;
• Dividend coverage of greater than 1.20x for the year ended December 31, 2018; and
• Growth of approximately 38 - 42% in our annualized dividend rate for the calendar year 2018.
We met or exceeded all these goals:
• Our Adjusted EBITDA for the year ended December 31, 2018 was approximately $860.4 million;
• Our maintenance capital for the year ended December 31, 2018 was approximately $21 million;
• Our dividend coverage for the year ended December 31, 2018 was approximately 1.26x; and
• Our dividends on Class A shares in the fourth quarter of 2018 represented a 41.5% increase from the fourth quarter of
2017.
Additionally, our internal qualitative goals included (a) advancing multi-year programs and initiatives and preparing the
organization for future growth, and (b) continuing to promote a culture of safety and environmental responsibility throughout
the organization. We achieved several accomplishments with respect to these qualitative goals, including:
• The execution of the Merger Agreement and successful completion of the TEP Merger with the expected benefits of
streamlining our corporate structure, lowering our cost of capital, and broadening our investor appeal;
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• The acquisitions from Tallgrass Development of an additional 25.01% membership interest in Rockies Express and
the remaining 2% membership interest in Pony Express in February 2018;
• Third-party acquisitions in 2018, including the acquisition of a 38% membership interest in Deeprock North in
January 2018, a 100% membership interest in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC
in January 2018, a 51% membership interest in Pawnee Terminal in April 2018, and a 100% membership interest in
NGL Water Solutions Bakken, LLC in November 2018;
• The assignment by Fitch Ratings of investment grade ratings to TEP and Rockies Express in September 2018;
• The amendment of the TEP revolving credit facility in July 2018, increasing the available amount from $1.75 billion
to $2.25 billion and permitting the repayment of the Tallgrass Equity revolving credit facility; and
• The senior note offerings of the 2023 Notes in an aggregate principal amount of $500 million in September 2018.
For 2018, the elements of compensation were applied as described below.
Salary. In 2018, we did not implement material salary increases for Mr. Dehaemers, Mr. Brauchle, or Mr. Moler. Mr. Jones
and Mr. Watkins received salary increases of approximately 10% over 2017.
Bonuses. Based on the CEO's annual performance review and the individual performance of each of our Named Executive
Officers, the board of directors of our general partner approved the annual bonuses for our Named Executive Officers reflected
in the Summary Compensation Table and notes thereto. Such amounts take into account performance relative to our 2018
goals; the level of difficulty associated with achieving such objectives; our relative positioning at the end of the year with
respect to future growth and performance; the significant transactions or accomplishments for the period not included in the
goals for the year; and our positioning at the end of the year with respect to our targeted credit profile. The board of directors of
our general partner also considered, on a subjective basis, how well the executive officer performed his or her duties during the
year.
Long-Term Incentive Awards. Each of our Named Executive Officers, with the exception of Mr. Dehaemers, received
grants under the Plans in 2018. As noted below, we believe the substantial direct and indirect equity interests held by our
management team, including our Named Executive Officers, in TGE, Tallgrass Energy Holdings and Tallgrass Equity aligns
their interests with those of our Class A shareholders, and is taken into account when considering the level of equity incentives
granted to our Named Executive Officers under our compensation programs.
Other Compensation Related Matters
Equity Ownership. Although we encourage our Named Executive Officers to acquire and retain ownership in Class A
shares, we do not require our Named Executive Officers to maintain a specified equity ownership level. Our policies, including
our Insider Trading Policy, strongly discourage our Named Executive Officers from using puts, calls or options to hedge the
economic risk of their ownership in TGE. Based on the closing price of Class A shares on February 6, 2019, the value of the
combined equity ownership of our Named Executive Officers discussed below was significantly greater than their combined
aggregate salaries and bonuses for 2018. We believe that the substantial direct and indirect equity interests held by our
management team in TGE and Tallgrass Energy Holdings further aligns their interests with those of our Class A shareholders,
and is taken into account when considering the level of equity incentives granted to our Named Executive Officers under our
compensation programs.
Equity Ownership in TGE, Tallgrass Energy Holdings and Tallgrass Equity. Each of our Named Executive Officers
beneficially own Class A shares in TGE and some of our Named Executive Officers indirectly own equity interests in Tallgrass
Energy Holdings, Tallgrass Equity and TGE through Tallgrass KC, an entity controlled by Mr. Dehaemers. As of February 6,
2019, our Named Executive Officers beneficially owned, in the aggregate, 3,544,643 of TGE's Class A shares (excluding any
unvested LTIP Awards). As of February 6, 2019, Tallgrass KC owned 29,416,692 Class B Shares in TGE and 29,416,692 Units
in Tallgrass Equity, representing an approximate 10.50% ownership interest in TGE and Tallgrass Equity, respectively. In
addition, as of February 6, 2019, Mr. Dehaemers controlled 281,171 Class B Shares in TGE and 281,171 Units in Tallgrass
Equity through the David G. Dehaemers, Jr. Revocable Trust, dated April 26, 2006.
Recovery of Prior Awards. Except as provided by applicable laws and regulations, we do not have a policy with respect to
adjustment or recovery of awards or payments if relevant company performance measures upon which previous awards were
based are restated or otherwise adjusted in a manner that would have reduced the size of such award or payment if previously
known.
Section 162(m). With respect to the deduction limitations under Section 162(m) of the Code, we are a limited partnership
and do not fall within the definition of a "corporation" under Section 162(m).
Change-in-Control Triggers and Termination Payments. The equity participation share grants to our Named Executive
Officers other than the 2017 Grants and 2018 Grants include accelerated vesting triggered upon a change of control, as defined
153
in the respective award agreements. The Blackstone Acquisition constitutes a change of control with respect to these equity
participation shares and as a result, any outstanding equity participation shares to our Named Executive Officers other than the
2017 Grants and the 2018 Grants will vest upon consummation of the Blackstone Acquisition. Although the Blackstone
Acquisition will constitute a qualifying transaction under the 2017 Grants and the 2018 Grants, vesting under such awards will
not accelerate until one of the subsequent conditions described below occurs.
The 2017 Grants include accelerated vesting if either (i) both (A) a qualifying transaction occurs, as defined in the award
agreement, and (B) Mr. Dehaemers ceases to be the Chief Executive Officer of our general partner or certain of its affiliates, or
(ii) (A) Mr. Dehaemers ceases to be the Chief Executive Officer of our general partner or certain of its affiliates, and (B) the
Named Executive Officer is thereafter terminated without cause.
The 2018 Grants to Mr. Jones include accelerated vesting if either (i) both (A) a qualifying transaction occurs, as defined in
the award agreement, and (B) in connection with or within 12 months following such qualifying transaction, Mr. Dehaemers
ceases to be the Chief Executive Officer of our general partner or certain of its affiliates, or (ii) (A) Mr. Dehaemers ceases to be
the Chief Executive Officer of our general partner or certain of its affiliates, and (B) within 2 years after the occurrence of such
event, Mr. Jones is terminated without cause. The 2018 Grants to Mr. Watkins include accelerated vesting if either (i) both (A) a
qualifying transaction occurs, and (B) in connection with or within 12 months following such qualifying transaction, Mr.
Dehaemers, Mr. Moler, Mr. Brauchle or Mr. Jones cease to comprise at least one of the roles of Chief Executive Officer, Chief
Operating Officer, Chief Financial Officer or General Counsel of our general partner or certain of its affiliates, or (ii) (A) Mr.
Dehaemers, Mr. Moler, Mr. Brauchle or Mr. Jones cease to comprise at least one of the roles of Chief Executive Officer, Chief
Operating Officer, Chief Financial Officer or General Counsel of our general partner or certain of its affiliates, and (B) within 2
years after the occurrence of such event, Mr. Watkins is terminated without cause.
The provision of equity acceleration for defined events help to create a retention tool by assuring the executive that the
benefit of the compensation arrangement will be at least partially realized despite the occurrence of an event that could
materially alter the executive's employment arrangement. In addition, the employment agreement for Mr. Dehaemers provides
for severance in the event his employment is terminated without "cause" or in the event he resigns for "good reason." See
"Potential Payments upon Termination or Change-in-Control." Except for the accelerated vesting of the 2017 Grants to Mr.
Jones and Mr. Watkins and the 2018 Grants to Mr. Jones, if Mr. Dehaemers ceases to be the Chief Executive Officer of our
general partner or certain of its affiliates and the Named Executive Officer is thereafter terminated without cause, no other
Named Executive Officer has a contractual right to receive severance in the event of a termination of employment.
Relation of Compensation Policies and Practices to Risk Management
Our compensation policies and practices are designed to provide rewards for short-term and long-term performance, both
on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a
competitive business like ours, requires some degree of risk-taking. Accordingly, the use of compensation as an incentive for
performance could potentially cause management and others to take unnecessary or excessive risks to reach the performance
thresholds. For us, such risks would primarily attach to the execution and financing of capital expansion projects and asset
acquisitions and the realization of associated returns from both, as well as to certain commercial activities conducted in our
operational segments, in order to achieve the dividend growth performance hurdles.
From a risk management perspective, we monitor and structure our commercial activities in a manner intended to control
and minimize the potential for unwarranted risk-taking. See Note 9 – Risk Management. We also monitor and measure our
capital projects and acquisitions relative to expectations. In general, we believe our compensation arrangements serve to
minimize the incentive for unwarranted risk-taking to achieve short-term, unsustainable results. See "Compensation Discussion
and Analysis – Relation of Compensation Elements to Compensation Objectives."
In combination with our risk-management practices, we do not believe that risks arising from our compensation policies
and practices for our employees are reasonably likely to have a material adverse effect on us.
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Summary Compensation Table
The following table reflects the total compensation of the principal executive officer, the principal financial officer and the
three other most highly compensated executive officers of our general partner for 2018 (the "Named Executive Officers") for
services rendered to all Tallgrass-related entities, including TEP, TGE, Tallgrass Management and Tallgrass Development, for
the fiscal years ending December 31, 2018, 2017, and 2016.
David G. Dehaemers, Jr.
President, Chief Executive
Officer and Director
William R. Moler
Executive Vice President, Chief
Operating Officer and Director
Gary J. Brauchle
Executive Vice President and
Chief Financial Officer
Christopher R. Jones
Executive Vice President,
General Counsel and Secretary
Gary D. Watkins
Vice President and
Chief Accounting Officer
Year
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
2017
2016
Salary (1)
$ 300,000
Cash
Bonus (2)
$1,000,000
$ 300,000
$1,000,739
$ 300,000
$ 651,467
$ 300,000
$ 500,000
$ 300,000
$ 400,943
$ 300,000
$ 576,468
$ 300,000
$ 500,000
$ 299,712
$ 750,942
$ 294,904
$ 576,144
Equity
Awards (3)
$
— $
All Other
Compensation (4)
28,652
Total
$ 1,328,652
$
$
$
$
$
$
$
$
— $
— $
28,152
$ 1,328,891
27,544
$
979,011
951,328
$
28,652
$ 1,779,980
— $
— $
28,152
24,544
$
$
729,095
901,012
710,854
$
28,459
$ 1,539,313
— $
— $
27,955
$ 1,078,609
27,537
$
898,585
$ 297,116
$ 500,000
$ 3,821,254
$ 271,569
$ 750,942
$ 3,545,100
$ 240,068
$ 426,467
$
69,836
$ 247,116
$ 250,000
$ 1,209,600
$ 224,922
$ 248,435
$ 1,378,650
$ 222,975
$ 201,470
$
69,836
$
$
$
$
$
$
28,644
$ 4,647,014
27,686
$ 4,595,297
24,486
$
760,857
25,664
$ 1,732,380
23,356
$ 1,875,363
23,081
$
517,362
(1) Reflects actual salary received. Salary adjustments are typically implemented during February, which results in odd
amounts actually received by the indicated Named Executive Officer.
(2) Represents discretionary cash bonuses paid in 2019, 2018 and 2017 based on performance in 2018, 2017 and 2016,
respectively, as well as a bonus of $500 after tax that was paid to all employees in 2017, and a bonus of $1,000 after tax
that was paid to all employees in 2016.
(3) The amounts in this column include equity participation shares granted pursuant to the Plans. Each of our Named
Executive Officers, with the exception of Mr. Dehaemers, received grants under the Plans in 2018. In addition, Mr. Moler,
Mr. Brauchle, and Mr. Jones each received grants in January 2019 as a component of their 2018 bonuses. Mr. Jones and
Mr. Watkins were the only Named Executive Officers to receive grants under the Plans during 2016 and 2017. These
amounts represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity
participation units, or EPUs, granted under the Legacy LTIP prior to June 30, 2018 and equity participation shares, or EPSs
granted under the Plans. Pursuant to SEC rules, the amounts shown in the Summary Compensation Table for awards
subject to performance conditions are based on the probable outcome as of the date of grant and exclude the impact of
estimated forfeitures. The EPUs and EPSs are non-participating, therefore the grant date fair value is discounted from the
grant date fair value of TEP's common units or TGE's Class A shares, as appropriate, for the present value of the expected
(but non-participating) future dividends during the vesting period. For additional information, see Note 16 – Equity-Based
Compensation. These amounts do not correspond to the actual value that will be recognized by the executive.
(4) The amounts in the column include the following: contributions under the 401(k) savings plan (includes $27,500 for
Mr. Dehaemers, $27,500 for Mr. Moler, $27,307 for Mr. Brauchle, $27,500 for Mr. Jones, and $24,712 for Mr. Watkins for
the year ended December 31, 2018; $27,000 for Mr. Dehaemers, $27,000 for Mr. Moler, $26,804 for Mr. Brauchle,
$26,640 for Mr. Jones, and $22,492 for Mr. Watkins for the year ended December 31, 2017; and $26,500 for
Mr. Dehaemers, $26,500 for Mr. Moler, $26,500 for Mr. Brauchle, $23,629 for Mr. Jones, and $22,297 for Mr. Watkins for
the year ended December 31, 2016) and the dollar value of premiums paid for group life, accidental death and
dismemberment insurance.
155
As required by Section 953(b) of the Dodd-Frank Act and Item 402(u) of Regulation S-K, we are providing information
regarding the internal pay ratio between the annual total compensation of our Chief Executive Officer and the median of the annual
total compensation of all employees. To determine the median of the annual total compensation of all such employees, excluding
our Chief Executive Officer, we identified the "median employee" by comparing the amount of salary, wages and tips of such
employees, whether full-time, part-time, seasonal or temporary, as reflected in the payroll records of Tallgrass Management for
the period from January 1, 2018 through December 31, 2018. We determined that our Chief Executive Officer had annual total
compensation of $1,328,652, which is reflected in the Summary Compensation Table above, and the median of the annual total
compensation of all employees, excluding our Chief Executive Officer, was $96,979. Therefore, our Chief Executive Officer's
annual total compensation is 13.7 times that of the median of the annual total compensation of all employees of Tallgrass
Management.
Grants of Plan-Based Awards Table
The following table provides information concerning each grant of an award made to a Named Executive Officer during
2018 under the Plans.
Gary J. Brauchle
Grant Type
Grant Date
Number of
Shares or
Units
Grant Date
Fair Value of
Awards(1)
Executive Vice President and
Chief Financial Officer
TEP Equity Participation Units
TGE Equity Participation Shares
2/14/18
—
6,700 (2) $
$
—
William R. Moler
Executive Vice President, Chief
TEP Equity Participation Units
Operating Officer and Director
TGE Equity Participation Shares
2/14/18
—
14,500 (2) $
$
—
Christopher R. Jones
Executive Vice President, General
TEP Equity Participation Units
Counsel and Secretary
TGE Equity Participation Shares
2/14/18
10/19/18
6,700 (2) $
180,000 (3) $
30.83
—
30.83
—
30.83
17.28
Gary D. Watkins
Vice President and
TEP Equity Participation Units
—
Chief Accounting Officer
TGE Equity Participation Shares
10/19/18
—
$
70,000 (3) $
—
17.28
(1) The amounts in this column represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for
equity participation units, or EPUs, granted under the Legacy LTIP prior to June 30, 2018 and equity participation shares,
or EPSs, granted under the Plans. Pursuant to SEC rules, the amounts shown in this table for awards subject to
performance conditions, if applicable, are based on the probable outcome as of the date of grant and exclude the impact of
estimated forfeitures. The EPUs and EPSs are non-participating, therefore the grant date fair value is discounted from the
grant date fair value of TEP's common units or TGE's Class A shares, as appropriate, for the present value of the expected
(but non-participating) future dividends during the vesting period. For additional information, see Note 16 – Equity-Based
Compensation. These amounts do not correspond to the actual value that will be recognized by the executive.
(2) Vesting of the EPUs will occur on January 1, 2020 as long as the employee satisfies the continuing service requirement set
forth in the applicable award agreement. These awards were converted to EPSs effective June 30, 2018 at a ratio of 2.0
EPSs for each outstanding EPU. The Blackstone Acquisition constitutes a change of control with respect to these EPSs and
as a result, any outstanding EPSs under these awards will vest upon consummation of the Blackstone Acquisition.
(3) Vesting of the EPSs will occur on the earliest date on or after November 1, 2022, on which the average compounded
annual distribution growth rate, based upon the regular quarterly distribution paid by TGE on, or immediately prior to,
such date is at least 5% over an annualized distribution rate of $1.99 per TGE Class A share, as determined by the board of
directors of our general partner. If such date has not occurred by October 19, 2025, such EPSs will expire and terminate
and no vesting will occur. These EPSs do not vest solely as a result of the consummation of the Blackstone Acquisition.
See "Potential Payments upon Termination or Change-in-Control" for a description of the conditions that would accelerate
vesting of these EPSs.
156
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Award Table
A narrative description of all material factors necessary to an understanding of the information included in the above
Summary Compensation Table and Grants of Plan-Based Awards Table is included in "Compensation Discussion and Analysis"
and in the footnotes to such tables.
Outstanding Equity Awards at Fiscal Year-End
Effective June 30, 2018, all outstanding TEP equity participation units under the Legacy LTIP were converted to equity
participation shares at a ratio of 2.0 equity participation shares for each outstanding TEP equity participation unit. The
following table reflects all outstanding equity awards of our named executive officers as of December 31, 2018.
Equity Participation Share Awards (1)
David G. Dehaemers, Jr. .................
William R. Moler ............................
Gary J. Brauchle..............................
Christopher R. Jones .......................
Gary D. Watkins..............................
Number of Equity
Participation Share
Awards That Have
Not Vested
Market Value of
Equity Participation
Share Awards That
Have Not Vested (2)
—
705,860
326,156
10,178,988
4,512,636
$
—
29,000 (3) $
13,400 (4) $
418,200 (5) $
185,400 (6) $
Number of Unearned
Equity Participation
Shares That Have
Not Vested
Market or Payout
Value of Unearned
Equity Participation
Shares That Have
Not Vested (2)
— $
— $
— $
— $
— $
—
—
—
—
—
(1) The award agreements pursuant to which the equity participation shares set forth above were granted provide for the
settlement of the equity participation shares in Class A Shares.
(2) Reflects the closing price of $24.34 per Class A share at December 31, 2018.
(3) Mr. Moler holds 29,000 equity participation shares issued under the fifth category of awards described under
"Elements of Compensation" above.
(4) Mr. Brauchle holds 13,400 equity participation shares issued under the fifth category of awards described under
"Elements of Compensation" above.
(5) Mr. Jones holds 5,800, 35,000, 4,000, 180,000, 13,400, and 180,000 equity participation shares issued under the first,
second, third, fourth, fifth, and sixth categories, respectively, as described under "Elements of Compensation" above.
(6) Mr. Watkins holds 6,400, 35,000, 4,000, 70,000, and 70,000 equity participation shares issued under the first, second,
third, fourth, and sixth categories, respectively, as described under "Elements of Compensation" above.
157
Vested LTIP Awards
The following table sets forth certain information regarding the vesting of LTIP Awards held by the Named Executive
Officers granted under the Legacy LTIP prior to the June 30, 2018 effective date of the TEP Merger. No LTIP Awards held by
the Named Executive Officers under the TGE LTIP vested during 2018 and no LTIP Awards held by the Named Executive
Officers under the Legacy LTIP vested after June 30, 2018.
David G. Dehaemers, Jr.
President, Chief Executive Officer and Director
William R. Moler
Executive Vice President, Chief Operating Officer and Director
Gary J. Brauchle
Executive Vice President and Chief Financial Officer
Number of EPUs
Acquired on
Vesting (1)
Value Realized on
Vesting (2)
— $
— $
— $
—
—
—
Christopher R. Jones
2,900
$
123,801
Executive Vice President, General Counsel and Secretary
Gary D. Watkins
Vice President and Chief Accounting Officer
3,200
$
136,608
(1) Represents the gross number of EPUs that vested during the year ended December 31, 2018. The actual number of
TEP common units delivered to the Named Executive Officers was, in some cases, less than the number shown in the
above table due to the Named Executive Officers' option to net out TEP common units to cover a portion of applicable
tax withholding obligations.
(2) The stated value realized upon vesting is computed by multiplying the closing market price ($42.69) of TEP's common
units on the date they vested (May 13, 2018) by the number of units that vested.
Pension Benefits
We sponsor a 401(k) plan that is available to all employees, but we do not maintain a pension or defined benefit program.
Nonqualified Deferred Compensation and Other Nonqualified Deferred Compensation Plans
We do not have a nonqualified deferred compensation plan or program for our officers or employees.
Employment Agreement
On November 2, 2016, Mr. Dehaemers entered into a second amended and restated employment agreement with Tallgrass
Management, our general partner, Tallgrass Energy Holdings, Tallgrass Equity and TEP's general partner, pursuant to which he
agreed to serve as the President and Chief Executive Officer of our general partner. Under the terms of the employment
agreement, Mr. Dehaemers is entitled to receive an annual salary of $300,000. In addition, Mr. Dehaemers is entitled to receive
(i) benefits that are normally provided to senior executives of Tallgrass Management, (ii) reimbursement for all ordinary and
necessary out-of-pocket expenses incurred by Mr. Dehaemers, and (iii) a policy of director and officer liability insurance. Mr.
Dehaemers' employment is "at-will" and may be terminated at any time.
For a discussion of certain payments that Mr. Dehaemers may be entitled to upon the termination of his employment,
please read "Potential Payments Upon Termination or a Change-in-Control."
Potential Payments upon Termination or Change-in-Control
Termination
The employment agreement for Mr. Dehaemers provides that in the event his employment is terminated without "cause" or
in the event he resigns for "good reason" he will receive: (i) a severance payment equal to $900,000, payable in a lump sum
within 60 days after the termination of his employment; and (ii) directors and officers liability insurance coverage for so long as
he is subject to any claim arising from his employment by TGE and its Affiliates. In addition, upon any such termination, Mr.
Dehaemers would receive payments related to his accrued and unpaid expenses, salary and benefits. Under Mr. Dehaemers'
employment agreement:
158
•
•
"Cause" means (i) his conviction of, or plea of nolo contendere to, any crime or offense constituting a felony under
applicable law; (ii) his commission of fraud or embezzlement against Tallgrass Management or certain of its affiliates;
(iii) gross neglect by Mr. Dehaemers of, or gross or willful misconduct of Mr. Dehaemers in connection with the
performance of, his duties that, if curable, is not cured within 30 days of receiving a written notice of such gross
neglect or gross or willful misconduct; (iv) Mr. Dehaemers' willful failure or refusal to carry out the reasonable and
lawful instructions of the board of managers of Tallgrass Energy Holdings, and, in each case, such failure or refusal
has continued for a period of 30 calendar days following written notice; (v) Mr. Dehaemers' failure to perform the
duties and responsibilities of his office as his primary business activity; (vi) a judicial determination that Mr.
Dehaemers has breached his fiduciary duties with respect to Tallgrass Management or certain of its affiliates; or (vii)
Mr. Dehaemers' willful and material breach of his obligations under the limited liability company agreements of
Tallgrass Energy Holdings, our general partner, Tallgrass Equity and TEP GP, including willfully causing any
applicable Tallgrass entity to take any material action prohibited by such organizational documents, that Mr.
Dehaemers failed to cure, if curable, within 30 days following written notice thereof, specifically identifying such
willful and material breach.
"Good reason" means (i) a material diminution of Mr. Dehaemers' duties and responsibilities to Tallgrass Management
or certain of its affiliates to a level inconsistent with those of a chief executive officer; (ii) a material reduction in Mr.
Dehaemers' cash compensation or the aggregate welfare benefits provided to him (excluding any reduction that is not
limited to him specifically); (iii) a willful or intentional breach of his employment agreement by Tallgrass
Management; or (iv) a willful or intentional breach by our general partner or certain affiliates of Tallgrass
Management of a material provision of the applicable operating agreements of such entities that has a material and
adverse effect on Mr. Dehaemers.
Other than the payments to Mr. Dehaemers pursuant to his employment agreement as described above, we are not
obligated to make any cash payment or provide any benefit to our Named Executive Officers if their employment is terminated
by us or by the Named Executive Officer, other than the payment of accrued and unpaid expenses, salary and benefits. In
addition, except for the acceleration of the 2017 Grants and 2018 Grants under the circumstances further described below, any
LTIP Awards that have not vested and/or become exercisable are terminated upon the termination of such Named Executive
Officer's employment.
Change in Control
Employment Agreement. Upon a change in control, the employment agreement of Mr. Dehaemers generally does not
provide for termination or severance benefits or payments in addition to those described above.
LTIP Award Agreements. In addition to the foregoing payments to Mr. Dehaemers pursuant to his employment agreement,
the Legacy LTIP Awards and TGE LTIP Awards held by our Named Executive Officers other than the 2017 Grants and 2018
Grants typically provide for acceleration of vesting in connection with a change in control. The LTIP Awards held by our
Named Executive Officers other than the 2017 Grants and 2018 Grants vest and/or become exercisable in full upon a "change
in control" of us or our general partner. The Blackstone Acquisition constitutes a change of control with respect to these LTIP
Awards and as a result, any outstanding LTIP Awards to our Named Executive Officers other than the 2017 Grants and the 2018
Grants will vest upon consummation of the Blackstone Acquisition.
Under the Plans, "change of control" means the occurrence of one or more of the following events:
•
•
•
any Person or group, other than Tallgrass Energy Holdings or its affiliates, becomes the owner, by way of merger,
consolidation, recapitalization, reorganization or otherwise, of 50% or more of (A) the combined voting power of the
equity interests in our general partner or (B) the general partner interests in TGE;
the limited partners of TGE approve, in one or a series of transactions, a plan of complete liquidation of TGE; or
the sale or other disposition by TGE of all or substantially all of its assets in one or more transactions to any person
other than our general partner an affiliate of our general partner.
The 2017 Grants include accelerated vesting if either (i) both (A) a qualifying transaction occurs, and (B) Mr. Dehaemers
ceases to be the Chief Executive Officer of our general partner or certain of its affiliates, or (ii) (A) Mr. Dehaemers ceases to be
the Chief Executive Officer of our general partner or certain of its affiliates, and (B) the Named Executive Officer is thereafter
terminated without cause.
Under the award agreements for the 2017 Grants, a qualifying transaction means any transaction in which:
•
a person other than certain designated persons directly or indirectly acquires direct or indirect ownership or control of
50% or more of the voting interests in TEP's general partner, the ownership of 50% or more of the general partner
interests in TEP, or the ownership of such other rights or interests that grant to the owner or holder thereof the ability
159
to direct the management or policies of TEP, whether through the ownership of voting rights, by contract, or
otherwise;
• TEP's limited partners approve, in one or a series of transactions, a plan of complete liquidation of TEP; or
•
the sale or other disposition by TEP of all or substantially all of its assets in one or more transactions to any person
other than TEP's general partner and its affiliates.
The 2017 Grants do not vest solely as a result of the consummation of the Blackstone Acquisition.
The 2018 Grants to Mr. Jones include accelerated vesting if either (i) both (A) a qualifying transaction occurs, and (B) in
connection with or within 12 months following such qualifying transaction, Mr. Dehaemers ceases to be the Chief Executive
Officer of our general partner or certain of its affiliates, or (ii) (A) Mr. Dehaemers ceases to be the Chief Executive Officer of
our general partner or certain of its affiliates, and (B) within 2 years after the occurrence of such event, Mr. Jones is terminated
without cause.
The 2018 Grants to Mr. Watkins include accelerated vesting if either (i) both (A) a qualifying transaction occurs, and (B) in
connection with or within 12 months following such qualifying transaction, Mr. Dehaemers, Mr. Moler, Mr. Brauchle or Mr.
Jones cease to comprise at least one of the roles of Chief Executive Officer, Chief Operating Officer, Chief Financial Officer or
General Counsel of our general partner or certain of its affiliates, or (ii) (A) Mr. Dehaemers, Mr. Moler, Mr. Brauchle or Mr.
Jones cease to comprise at least one of the roles of Chief Executive Officer, Chief Operating Officer, Chief Financial Officer or
General Counsel of our general partner or certain of its affiliates, and (B) within 2 years after the occurrence of such event, Mr.
Watkins is terminated without cause.
Under the award agreements for the 2018 Grants, a qualifying transaction means any transaction in which:
•
a person other than certain designated persons directly or indirectly acquires direct or indirect ownership or control of
more than 50% of the voting interests in our general partner, the ownership of more than 50% of the general partner
interests in TGE, or the ownership of such other rights or interests that grant to the owner or holder thereof the ability
to direct the management or policies of TGE, whether through the ownership of voting rights, by contract, or
otherwise, or if TGE becomes a corporation or limited liability company or if the limited partners of TGE become
eligible to elect the members of the board of our general partner, the direct or indirect ability to appoint a majority of
the board of directors of the corporation or limited liability company or the board of our general partner, as the case
may be.
• TGE's limited partners approve, in one or a series of transactions, a plan of complete liquidation of TGE; or
•
the sale or other disposition by TGE of all or substantially all of its assets in one or more transactions to any person
other than our general partner and its affiliates.
The 2018 Grants do not vest solely as a result of the consummation of the Blackstone Acquisition.
The following table sets forth the value of outstanding LTIP Awards that would have vested and/or become exercisable for
each of the Named Executive Officers under the Plans if a triggering change in control event described above occurred on
December 31, 2018.
David G. Dehaemers, Jr.
William R. Moler
Gary J. Brauchle
Christopher R. Jones
Gary D. Watkins
Upon a Change in
Control (1)
$
$
$
$
$
—
705,860
326,156
10,178,988
4,512,636
(1) The stated value upon a change in control is computed by assuming that a triggering change of control event occurred
on December 31, 2018 and multiplying the closing market price ($24.34) of the Class A shares on such date by the
number of Class A shares that would have vested.
160
Confidentiality, Non-Compete and Non-Solicitation Arrangements
Under the terms of Mr. Dehaemers's employment agreement, he has agreed not to compete with Tallgrass Management or
certain of its affiliates and not to solicit Tallgrass Management's or any of its affiliates' employees or interfere with certain
business relationships during the term of his employment and for one year thereafter. In addition, under the terms of the award
agreements for the 2017 Grants and 2018 Grants, Mr. Jones and Mr. Watkins have agreed not to compete with our general
partner and its affiliates for the period commencing on the grant date and ending upon the earlier of (i) if a vesting date occurs,
18-months following termination of such person's employment, (ii) the date such LTIP Awards are forfeited without vesting,
and (iii) the date such LTIP Awards expire. Each of the Named Executive Officers has signed a confidentiality agreement in
connection with their employment by Tallgrass Management.
Compensation of TGE Directors
Officers or employees of Tallgrass Energy Holdings or its affiliates, including certain directors affiliated with EMG or
Kelso, who also serve as directors of our general partner do not receive additional compensation for such service. In 2018,
those directors of our general partner who were not excluded from receiving compensation were paid cash compensation as
follows:
• Quarterly cash payments of $10,000, resulting in an effective annual cash payment of $40,000.
•
For serving as the conflicts committee chair, a quarterly committee chair cash payment of $5,000.
In addition, Mr. Cook and Mr. Towner received compensation during the year ended December 31, 2018 for their service
on the TEP board of directors prior to the TEP Merger. Mr. Cook and Mr. Towner were appointed as directors of our general
partner on September 7, 2018.
All directors are also reimbursed for out-of-pocket expenses in connection with their service as directors, including costs
incurred to attend meetings. Each director is fully indemnified by us for actions associated with being a director to the fullest
extent permitted under Delaware law pursuant to our partnership agreement. Directors of our general partner are also eligible to
receive grants under the Plans.
The following table sets forth certain information with respect to our non-employee directors receiving cash compensation
during the year ended December 31, 2018:
Name and Principal Position
Thomas A. Gerke ................................ $
Roy N. Cook ....................................... $
Terrance D. Towner............................. $
W. Curtis Koutelas (2)........................... $
Fees Earned
60,000
105,000
65,000
30,000
Equity
Participation
Share Awards (1)
$
— $
$
$
$
130,840
130,840
$
$
— $
Non-Equity
Incentive Plan
Compensation
— $
— $
— $
— $
Total
60,000
235,840
195,840
30,000
(1) The amounts in this column include equity participation shares granted pursuant to the Plans. These amounts represent
the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity participation shares
granted under the Plans. Pursuant to SEC rules, the amounts shown in the table above for awards subject to
performance conditions are based on the probable outcome as of the date of grant and exclude the impact of estimated
forfeitures. The EPSs are non-participating, therefore the grant date fair value is discounted from the grant date fair
value of TGE's Class A shares, as appropriate, for the present value of the expected (but non-participating) future
dividends during the vesting period. For additional information, see Note 16 – Equity-Based Compensation. These
amounts do not correspond to the actual value that will be recognized by the directors.
(2) Mr. Koutelas resigned from the board of directors of our general partner effective September 7, 2018.
Compensation Committee Interlocks and Insider Participation
The listing rules of the NYSE do not require us to maintain, and we do not maintain, a compensation committee.
Mr. Dehaemers, as President and Chief Executive Officer, and Mr. Moler, as Executive Vice President and Chief Operating
Officer, participate in their capacity as a director of our general partner in the deliberations of the Board concerning executive
officer compensation. In addition, Mr. Dehaemers makes recommendations to the board of directors regarding named executive
officer compensation, but Mr. Dehaemers is not present for any discussions regarding his performance or compensation.
161
Compensation Report of the Board of Directors
The Board of Directors of our general partner has reviewed and discussed the compensation discussion and analysis
contained in this Annual Report on Form 10-K with management and, based on that review and discussion, has recommended
that the compensation discussion and analysis be included in this Annual Report for the year ended December 31, 2018 for
filing with the SEC.
David G. Dehaemers, Jr.
William R. Moler
Frank J. Loverro
Stanley de J. Osborne
Jeffrey A. Ball
John T. Raymond
Thomas A. Gerke
Roy N. Cook
Terrance D. Towner
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Tallgrass Energy, LP
The following tables set forth certain information regarding the beneficial ownership of our Class A shares and Class B
shares as of February 6, 2019 owned by:
•
•
•
•
each person who is known to us to beneficially own more than 5% of the Class A shares (calculated in accordance
with Rule 13d-3);
the named executive officers of our general partner;
each of the directors of our general partner; and
all the directors and executive officers of our general partner as a group.
All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more
shareholders, as the case may be. The amounts and percentage of Class A shares and Class B shares beneficially owned are
reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under the rules of
the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes
the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to
direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting
and investment power with respect to all Class A shares and Class B shares shown as beneficially owned by them, subject to
community property laws where applicable. Unless otherwise noted, the address of each beneficial owner named in the chart
below is 4200 W. 115th Street, Suite 350, Leawood, Kansas 66211, Attn: General Counsel.
162
Name and Address of Beneficial Owner
5% shareholders
Entities affiliated with Kelso (4)...........................................
Entities affiliated with EMG (5)...........................................
Tallgrass KC (6) ...................................................................
OppenheimerFunds, Inc. (7) .................................................
Tortoise Capital Advisors, L.L.C. (8)...................................
Kayne Anderson Capital Advisors, L.P. (9) .........................
Salient Capital Advisors LLC (10)........................................
Directors and named Executive officers:
David G. Dehaemers, Jr. (11)................................................
William R. Moler (12)...........................................................
Gary J. Brauchle (13) ............................................................
Christopher R. Jones (14)......................................................
Gary D. Watkins .................................................................
Frank J. Loverro (4) .............................................................
Stanley de J. Osborne (4)......................................................
Jeffrey A. Ball.....................................................................
John T. Raymond (15) ...........................................................
Thomas A. Gerke................................................................
Roy N. Cook .......................................................................
Terrance D. Towner ............................................................
All directors and executive officers of our general partner
as a group (11 persons) .......................................................
* Less than 1%.
Class A and Class
B shares
Beneficially
Owned (1)
Percentage of Class
A and Class B
shares Beneficially
Owned (2)
Combined
Voting Power (3)
46,727,603
46,386,232
29,416,692
26,697,437
24,224,847
8,822,918
7,847,848
31,504,182
2,903,053
2,328,812
358,978
46,830
46,727,603
46,727,603
100,000
46,833,283
54,300
116,165
53,000
23.01%
22.88%
15.83%
17.08%
15.49%
5.64%
5.02%
16.91%
1.82%
1.47%
*
*
23.01%
23.01%
*
23.1%
*
*
*
16.67%
16.55%
10.5%
9.53%
8.64%
3.15%
2.8%
11.24%
1.04%
*
*
*
16.67%
16.67%
*
16.71%
*
*
*
131,026,206
46.98%
46.75%
(1) Pursuant to Rule 13d-3 under the Exchange Act, a person has beneficial ownership of a security as to which that person,
directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares voting
power and/or investment power of such security and as to which that person has the right to acquire beneficial ownership
of such security within 60 days. In addition to Class A shares, this column includes Class B shares beneficially owned by
such persons that are, together with a corresponding number of Tallgrass Equity Units, exchangeable at any time and from
time to time for Class A shares on a one-for-one basis (subject to the terms of the Tallgrass Equity limited liability
company agreement and our partnership agreement). See "Certain Relationships and Related Party Transactions, and
Director Independence-Exchange Right."
(2) The Class A shares to be issued upon the exchange of Class B shares and Tallgrass Equity Units as described in footnote
(1) above are deemed to be outstanding and beneficially owned by the person holding the Class B shares for the purpose of
computing the percentage of beneficial ownership of Class A shares for that person and any group of which that person is a
member, but are not deemed outstanding for purpose of computing the percentage of beneficial ownership of any other
person. As such, the percentage of Class A shares shown as being beneficially owned by each person is based on an
assumption that each such person exchanged all of such person's Class B shares, together with a corresponding number of
Tallgrass Equity Units, for Class A shares and that no other person made a similar exchange.
(3) Represents the percentage of voting power of the Class A shares and Class B shares held by such person voting together as
a single class.
(4) Consists of Class B shares held of record by: (i) KIA VIII (Rubicon), L.P., a Delaware limited partnership, or KIA VIII,
and (ii) KEP VI AIV (Rubicon), LLC, a Delaware limited liability company, or KEP VI AIV. KIA VIII and KEP VI AIV,
due to their common control, could be deemed to beneficially own each of the other's shares. Each of KIA VIII and KEP
VI AIV disclaim such beneficial ownership. Frank T. Nickell, Thomas R. Wall, IV, George E. Matelich, Michael B.
Goldberg, David I. Wahrhaftig, Frank K. Bynum, Jr., Philip E. Berney, Frank J. Loverro, James J. Connors, II, Church M.
Moore, Stanley de J. Osborne, Christopher L. Collins, A. Lynn Alexander, Howard A. Matlin, John K. Kim, Henry
163
Mannix, III, Matthew S. Edgerton and Stephen C. Dutton (the "Kelso Individuals") may be deemed to share beneficial
ownership of shares held of record or beneficially owned by KIA VIII and KEP VI AIV, by virtue of their status as
managing members of KEP VI AIV and of Kelso GP VIII, LLC, a Delaware limited liability company, the principal
business of which is serving as the general partner of KIA VIII (Rubicon) GP, L.P., a Delaware limited partnership, the
principal business of which is serving as the general partner of KIA VIII. Each of Kelso GP VIII, LLC and KIA VIII
(Rubicon) GP, L.P. due to their common control, could be deemed to beneficially own each other's securities and the shares
held of record or beneficially owned by KIA VIII and KEP VI AIV. Kelso GP VIII, LLC disclaims beneficial ownership of
all the securities owned of record, or deemed beneficially owned, by KIA VIII (Rubicon) GP, L.P., KIA VIII and KEP VI
AIV, except to the extent, if any, of its pecuniary interest therein, and the inclusion of these securities in the table above
shall not be deemed an admission of beneficial ownership of all the reported securities for any purpose. KIA VIII
(Rubicon) GP, L.P. disclaims beneficial ownership of all of the securities owned of record, or deemed beneficially owned,
by Kelso GP VIII, LLC, KIA VIII and KEP VI AIV, except to the extent, if any, of its pecuniary interest therein, and the
inclusion of these securities in the table above shall not be deemed an admission of beneficial ownership of all the reported
securities for any purpose. The Kelso Individuals may be deemed to share beneficial ownership of securities owned of
record or beneficially owned by Kelso GP VIII, LLC, KIA VIII (Rubicon) GP, L.P., KIA VIII and KEP VI AIV, by virtue
of their status as managing members of Kelso GP VIII, LLC and KEP VI AIV, but disclaim beneficial ownership of such
securities, and the inclusion of these securities in the table above shall not be deemed an admission that any of the Kelso
Individuals is the beneficial owner of these securities for any purposes. Frank J. Loverro, who serves as a Managing
Director and Co-Chief Executive Officer of Kelso & Company, which manages the investments in KIA VIII, KEP VI AIV,
is one of our directors. Stanley de J. Osborne, who serves as a Managing Director of Kelso & Company, is also one of our
directors. The business address for these persons is c/o Kelso & Company, 320 Park Avenue, 24th Floor, New York, NY
10022.
(5) Consists of Class B shares held of record by Tallgrass Holdings, LLC. The manager of Tallgrass Holdings, LLC is EMG
Fund II Management, LP. EMG Fund II Management, LP's general partner is EMG Fund II Management, LLC. John T.
Raymond, who serves as one of our directors, is the sole member of EMG Fund II Management, LLC and as such, has sole
voting and dispositive power with respect to the shares held by Tallgrass Holdings, LLC; however, he disclaims beneficial
ownership of those shares except to the extent of his pecuniary interest therein. The address for Tallgrass Holdings, LLC is
The Energy & Minerals Group, 2229 San Felipe, Suite 1300, Houston, Texas 77019.
(6) Consists of Class B shares held of record by Tallgrass KC. David G. Dehaemers, Jr. has sole voting and dispositive power
with respect to the Class B shares held by Tallgrass KC; however, he disclaims beneficial ownership of those shares except
to the extent of his pecuniary interest therein.
(7) As reported on Schedule 13G filed with the SEC on January 18, 2019. The business address for this person is Two World
Financial Center, 225 Liberty Street, New York, New York 10281.
(8) As reported on Schedule 13G filed with the SEC on August 9, 2018. Tortoise Capital Advisors, L.L.C. ("TCA") acts as an
investment advisor to certain investment companies registered under the Investment Company Act of 1940. TCA, by virtue
of investment advisory agreements with these investment companies, has all investment and voting power over securities
owned of record by these investment companies. However, despite their delegation of investment and voting power to
TCA, these investment companies may be deemed to be the beneficial owner under Rule 13d-3 of the Act, of the securities
they own of record because they have the right to acquire investment and voting power through termination of their
investment advisory agreement with TCA. Thus, TCA has reported on the Schedule 13G that it shares voting power and
dispositive power over the securities owned of record by these investment companies. TCA also acts as an investment
adviser to certain managed accounts. Under contractual agreements with these managed account clients, TCA, with respect
to the securities held in these client accounts, has investment and voting power with respect to certain of these client
accounts, and has investment power but no voting power with respect to certain other of these client accounts. TCA has
reported on the Schedule 13G that it shares voting and/or investment power over the securities held by these client
managed accounts despite a delegation of voting and/or investment power to TCA because the clients have the right to
acquire investment and voting power through termination of their agreements with TCA. TCA may be deemed the
beneficial owner of the securities covered by the Schedule 13G under Rule 13d-3 of the Act that are held by its clients. The
business address for this person is 11550 Ash Street, Suite 300, Leawood, Kansas 66211.
(9) As reported on Schedule 13G filed with the SEC on February 1, 2019. Kayne Anderson Capital Advisors, L.P. is the
general partner (or general partner of the general partner) of the limited partnerships and investment adviser to the other
accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment
Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of
each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital
Advisors, L.P. disclaims beneficial ownership of the shares reported, except those shares attributable to it by virtue of its
general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the shares reported,
164
except those shares held by him or attributable to him by virtue of his limited partnership interests in the limited
partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnerships, and
his ownership of common stock of the registered investment company. The business address for these persons is 1800
Avenue of the Stars, Second Floor, Los Angeles California 90067.
(10) As reported on Schedule 13G filed with the SEC on April 10, 2017. The business address for this person is 4265 San
Felipe, 8th Floor, Houston, TX 77027.
(11) Consists of (i) 29,416,692 Class B shares held of record by Tallgrass KC, (ii) 281,171 Class B shares held indirectly
through the David G. Dehaemers, Jr. Revocable Trust, dated April 26, 2006 (the "Dehaemers Trust"), for which Mr.
Dehaemers serves as Trustee and (iii) 1,806,319 Class A shares held indirectly through the Dehaemers Trust. Mr.
Dehaemers has sole voting and dispositive power with respect to the shares held by Tallgrass KC; however, he disclaims
beneficial ownership of those shares except to the extent of his pecuniary interest therein.
(12) Consists of (i) 1,403,765 Class B shares held of record by Tallgrass KC and (ii) 1,499,288 Class A shares held indirectly
through the William R. Moler Revocable Trust U.T.A. dated August 27, 2013 ("Moler Trust"), for which Mr. Moler serves
as Trustee. Mr. Moler indirectly holds a membership interest in Tallgrass KC through the Moler Trust, that includes
1,403,765 TEGP Tracking Units. Pursuant to Tallgrass KC's limited liability company agreement, Mr. Moler is permitted to
exchange his TEGP Tracking Units in Tallgrass KC for an equivalent number of Class A shares of TGE.
(13) Consists of (i) 2,183,636 Class B shares held of record by Tallgrass KC and (ii) 145,176 Class A shares held indirectly
through the Brauchle Revocable Trust, under a trust agreement dated April 10, 2014, for which Mr. Brauchle serves as a
Trustee (the "Brauchle Trust"). Mr. Brauchle indirectly holds a membership interest in Tallgrass KC through the Brauchle
Trust, that includes 2,183,636 TEGP Tracking Units. Pursuant to Tallgrass KC's limited liability company agreement, Mr.
Brauchle is permitted to exchange his TEGP Tracking Units in Tallgrass KC for an equivalent number of Class A shares of
TGE.
(14) Consists of (i) 311,948 Class B shares held of record by Tallgrass KC and (ii) 47,030 Class A shares held directly by Mr.
Jones. Mr. Jones holds a membership interest in Tallgrass KC that includes 311,948 TEGP Tracking Units. Pursuant to
Tallgrass KC's limited liability company agreement, Mr. Jones is permitted to exchange his TEGP Tracking Units in
Tallgrass KC for an equivalent number of Class A shares of TGE.
(15) Consists of (i) 46,386,232 Class B shares held of record by Tallgrass Holdings, LLC and (ii) 447,051 Class A shares held
directly by John T. Raymond. The manager of Tallgrass Holdings, LLC is EMG Fund II Management, LP. EMG Fund II
Management, LP's general partner is EMG Fund II Management, LLC. John T. Raymond, who serves as one of our
directors, is the sole member of EMG Fund II Management, LLC and as such, has sole voting and dispositive power with
respect to the shares held by Tallgrass Holdings, LLC; however, he disclaims beneficial ownership of those shares except
to the extent of his indirect pecuniary interest therein.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information about our Class A shares that may be issued under equity compensation plans as
of December 31, 2018:
Plan Category
Equity compensation plans approved by
security holders
Equity compensation plans not approved by
security holders (2)
Total
(a)
Number of securities
to be issued
upon exercise of
outstanding options,
warrants and rights
(b)
Weighted average
grant date fair value of
outstanding options,
warrants and rights
(c)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a))
3,049,644 (1) $
—
3,049,644
$
$
18.25
—
18.25
17,735,121
—
17,735,121
(1) Amounts shown represent equity participation share awards outstanding under the Plans as of December 31, 2018. The
outstanding awards will be settled in Class A shares pursuant to the terms of the award agreements and are not subject
to an exercise price.
(2) There are no equity compensation plans in place pursuant to which Class A shares may be issued except for the Plans.
For additional information regarding the Plans, see Note 16 – Equity-Based Compensation to our Consolidated Financial
Statements in Item 8.—Financial Statements and Supplementary Data of this Annual Report.
165
Item 13. Certain Relationships and Related Transactions, and Director Independence
We are a Delaware limited partnership formed in February 2015. Although we were formed as a limited partnership, we
have elected to be taxed as a corporation for U.S. federal income tax purposes.
Limited Liability Company Agreement of Tallgrass Equity
As of February 8, 2019, we own Tallgrass Equity units representing 55.79% of the membership interests in Tallgrass
Equity. In accordance with the Tallgrass Equity limited liability company agreement, the net profits and net losses of Tallgrass
Equity will generally be allocated to the holders of Tallgrass Equity units on a pro rata basis in accordance with their relative
number of Tallgrass Equity units held. Accordingly, net profits and losses of Tallgrass Equity are currently allocated 55.79% to
us and 44.21% to the Exchange Right Holders with respect to their Tallgrass Equity units. If we cause a distribution to be made,
such distribution will be made to the holders of Tallgrass Equity units on a pro rata basis in accordance with their relative
number of Tallgrass Equity units held.
For purposes of any transfer or exchange of Tallgrass Equity units initially owned by the Exchange Right Holders and our
Class B shares, the Tallgrass Equity limited liability company agreement and our partnership agreement contain provisions
linking each such Tallgrass Equity unit with one of our Class B shares. Our Class B shares cannot be transferred without
transferring an equal number of Tallgrass Equity units and vice versa.
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 into Class A shares at an exchange ratio of one Class A share for each Tallgrass
Equity unit exchanged. The above 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.
The above mechanisms are subject to customary conversion rate adjustments for equity splits, equity dividends and
reclassifications.
In addition, pursuant to our partnership agreement and the Tallgrass Equity limited liability company agreement, our
capital structure and the capital structure of Tallgrass Equity generally replicate one another and provide for customary
antidilution mechanisms 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.
TGE Omnibus Agreement
In connection with the closing of the TGE IPO, we, our general partner, Tallgrass Equity and Tallgrass Energy Holdings
entered into the TGE Omnibus Agreement, that addresses the following matters:
• Tallgrass Equity's obligation to reimburse Tallgrass Energy Holdings and its affiliates for expenses incurred (i) on our
behalf, (ii) on behalf of our general partner and (iii) for any other purposes related to our business and activities or
those of our general partner, including our public company expenses and general and administrative expenses; and
• Our use of the name "Tallgrass" and any associated or related marks.
Pursuant to the TGE Omnibus Agreement, Tallgrass Energy Holdings may perform, or cause its affiliates to perform,
centralized general and administrative services for TGE, such as accounting, audit, business development, corporate record
keeping, treasury services (including cash management), real property/land, legal, operations/engineering, investor relations,
risk management, commercial/marketing, information technology, insurance, government relations/compliance, tax, payroll,
human resources and environmental, health and safety. In exchange, Tallgrass Equity reimburses Tallgrass Energy Holdings
and its affiliates for their expenses to the extent incurred on our behalf in providing these services. All reimbursements to our
general partner, Tallgrass Energy Holdings and their respective affiliates by Tallgrass Equity will proportionally reduce cash
distributions by Tallgrass Equity to its members, which in turn will reduce the amount of cash we distribute to our Class A
shareholders.
Effective January 1, 2018, these costs are incurred by Tallgrass Equity directly. For the years ended December 31, 2017
and 2016, Tallgrass Equity reimbursed Tallgrass Management and its affiliates $2.0 million pursuant to the TGE Omnibus
Agreement.
TEP Omnibus Agreement
In May 2013, TEP entered into an Omnibus Agreement with Tallgrass Equity (as successor to Tallgrass Development),
Tallgrass Energy Holdings, and TEP GP, which we refer to as the TEP Omnibus Agreement, that governs TEP's relationship
with them regarding the following matters:
•
the provision by Tallgrass Energy Holdings to TEP of certain administrative services and TEP's agreement to
reimburse it for such services;
166
•
the provision by Tallgrass Energy Holdings of such employees as may be necessary to operate and manage TEP's
business, and TEP's agreement to reimburse it for the expenses associated with such employees;
•
certain indemnification obligations; and
• TEP's use of the name "Tallgrass" and related marks.
Pursuant to the TEP Omnibus Agreement, Tallgrass Energy Holdings may perform, or causes its affiliates to perform,
centralized corporate, general and administrative services for TEP, such as legal, corporate record keeping, planning, budgeting,
regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk
management, health, safety and environmental, information technology, human resources, investor relations, cash management
and banking, payroll, internal audit, taxes and engineering. In exchange, TEP reimburses Tallgrass Energy Holdings and its
affiliates for their expenses to the extent incurred on TEP's behalf in providing these services.
Exchange Right
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 into 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.
For purposes of any transfer or exchange of Tallgrass Equity units initially owned by the Exchange Right Holders and our
Class B shares, the Tallgrass Equity limited liability company agreement and our partnership agreement contain provisions
effectively linking one Tallgrass Equity unit with one of our Class B shares. Class B shares cannot be transferred without
transferring an equal number of Tallgrass Equity units and vice versa. In connection with the Secondary Offering completed in
November 2016, the participating Exchange Right Holders exercised their Exchange Right with respect to a total of 10,350,000
Tallgrass Equity units and an equal number of Class B shares. In addition, during the year ended December 31, 2018, 2,821,332
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.
The above mechanisms are subject to customary conversion rate adjustments for equity splits, equity dividends and
reclassifications.
Registration Rights Agreement
In connection with the closing of the TGE IPO, we entered into a shareholder and registration rights agreement, which we
refer to as the registration rights agreement, with certain of the Exchange Right Holders. Pursuant to the registration rights
agreement, we agreed to register the resale of 109,504,440 Class A shares issuable upon exercise of the Exchange Right held by
the Exchange Right Holders or any of their permitted transferees to the registration rights agreement under certain
circumstances. In addition, we agreed to register the 27,554,785 Class A shares issuable upon the exercise of the Exchange
Right with respect to 27,554,785 Tallgrass Equity units and Class B shares, respectively, issued in connection with the
acquisition of the 25.01% membership interest in Rockies Express and the 5,619,218 additional TEP common units acquired by
Tallgrass Equity in February 2018. We refer to such Class A shares issuable upon exercise of the Exchange Right as the
Registrable Securities.
In accordance with our obligations under the registration rights agreement, we have registered the resale of 125,291,659
Class A shares issuable upon exercise of the Exchange Right pursuant to our Form S-3 (File No. 333-225382) filed with the
SEC on June 1, 2018, which became effective June 13, 2018. We are required to maintain the effectiveness of such registration
statement until the date on which all Registrable Securities covered by the shelf registration statement have been sold
thereunder in accordance with the plan and method of distribution disclosed in the annual report included in the shelf
registration statement, or otherwise cease to be Registrable Securities under the registration rights agreement.
Demand and Piggyback Rights
The Exchange Right Holders have the right to require that we register their Registrable Securities and/or facilitate an
underwritten offering of their Registrable Securities. There is no aggregate limit on the number of such demand requests;
however, the demand rights of these holders are subject to a number of size, frequency and other limitations. In November
2016, EMG and Kelso exercised this "demand" registration right under the registration rights agreement and together with the
other participating Exchange Right Holders, sold 10,350,000 Class A Shares in the Secondary Offering that closed on
November 22, 2016. For a period of 120 days following the closing of the Secondary Offering, the participating Exchange
Right Holders were not permitted to exchange any of their Tallgrass Equity units pursuant to the terms of the underwriting
agreement.
167
In the event we propose to conduct an underwritten offering of Registrable Securities, then the holders of Registrable
Securities will generally have customary rights to participate in such offering, subject to customary offering size limitations and
related allocation provisions and other limitations. Similarly, in the event that eligible holders demand that we conduct an
underwritten offering of their Registrable Securities, then we will generally have customary rights to participate in such
offering, subject to customary offering size limitations and related allocation provisions and other limitations.
Delay Rights
We will not be required to comply with any demand request, and may suspend the holders' ability to use any shelf
registration statement, following our delivery of written notice to the holders of customary blackout periods and deferral events.
Expenses
The holders of Registrable Securities will pay certain selling expenses, including any underwriters' discounts and
commissions. We will generally cause Tallgrass Equity to pay all other registration expenses in connection with our obligations
under the registration rights agreement.
Pursuant to the terms of the registration rights agreement discussed above, the Company was obligated to cause Tallgrass
Equity to pay all fees and expenses related to the Secondary Offering, excluding certain selling expenses, including any
underwriters' discounts and commissions. The Company did not receive any proceeds from the sale of Class A shares in the
Secondary Offering. The total expenses paid by Tallgrass Equity in connection with the Secondary Offering, and associated
filings, were approximately $1.0 million.
Other Transactions
In January 2018, we entered into an agreement to acquire a 51% membership interest in the Pawnee, Colorado crude oil
terminal ("Pawnee Terminal") from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $30.6
million. The transaction closed on April 1, 2018. Kelso owns an indirect equity interest in Zenith Energy Terminals Holdings,
LLC.
Effective February 1, 2018, TEP acquired the remaining 2% membership interest in Pony Express, along with
administrative assets consisting primarily of information technology assets, from Tallgrass Development for cash consideration
of approximately $60 million, bringing its aggregate membership interest in Pony Express to 100%.
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, a wholly-owned subsidiary of
Tallgrass Equity, and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and
an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Equity issued 27,554,785
TGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February
6, 2018, to the limited partners of Tallgrass Development.
In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the
contribution by us and Silver Creek of cash and additional Powder River Basin assets. These additional contributions closed in
January 2019. The expanded joint venture operates under the name Powder River Gateway, LLC, and owns the Iron Horse
Pipeline, the PRE Pipeline, a 70-mile crude oil pipeline that transports crude oil from the Powder River Basin to Guernsey,
Wyoming, and crude oil terminal facilities in Guernsey, Wyoming. Effective January 1, 2019, 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. EMG owns an indirect equity interest in Silver Creek.
Procedures for Review, Approval or Ratification of Transactions with Related Persons
The board of directors of our general partner has adopted a related party transactions policy (the "Policy"), which
supplements the conflict of interest provisions in our code of business conduct and ethics. According to the Policy, a "Related
Party Transaction" is an actual or proposed transaction, arrangement or relationship (or any series of similar transactions,
arrangements or relationships) in which (a) the Partnership, our general partner or Tallgrass Equity (collectively, the
"Partnership Group") was, is or will be a participant, (b) the amount involved exceeds $120,000, and (c) in which any Related
Party had, has or will have a direct or indirect material interest. The Policy's definition of a "Related Party" is in line with the
definition set forth in the instructions to Item 404(a) of Regulation S-K promulgated by the SEC. Transactions resolved under
the conflicts provisions of our partnership agreement are not required to be reviewed or approved under the policy.
Under the Policy, the General Counsel and Chief Financial Officer or Chief Accounting Officer are responsible for
determining whether a Related Party Transaction requires the approval of the Audit Committee. The Audit Committee is
responsible for evaluating and assessing a proposed transaction based on the relevant facts and circumstances, including
comparing the terms of the proposed transaction to the terms available to unrelated third parties. The Audit Committee shall
approve only those Related Party Transactions that are either (i) on terms no less favorable to the Partnership Group than those
168
generally being provided to or available from unrelated third parties or (ii) are fair and reasonable to the Partnership Group,
taking into account the totality of the relationships between the parties involved.
If the General Counsel determines it is impractical or undesirable to wait until an Audit Committee meeting to consummate
a Related Party Transaction, the chairman of the Audit Committee may review and approve the Related Party Transaction in
accordance with the procedures set forth in the Policy. However, any such approval (and its rationale) must be reported to the
Audit Committee at the next regularly scheduled meeting. A Related Party Transaction entered into without pre-approval of the
Audit Committee shall not be deemed to violate the Policy, or be invalid or unenforceable, so long as the transaction is brought
to the Audit Committee as promptly as reasonably practical after it is entered into and is subsequently ratified by the Audit
Committee. If the Audit Committee determines not to ratify a Related Party Transaction that has been commenced without
approval, the Audit Committee may direct the immediate discontinuation or rescission of the transaction, or modify the
transaction to make it acceptable for ratification.
Director Independence
The information required by Item 407(a) of Regulation S-K is included in Item 10.—Directors, Executive Officers and
Corporate Governance.
Item 14. Principal Accounting Fees and Services
We have engaged PricewaterhouseCoopers LLP as our independent registered public accounting firm. The following table
summarizes fees we were billed by PricewaterhouseCoopers LLP (or included in TD's general and administrative expense
allocation to us) for independent auditing, tax and related services for each of the last two fiscal years:
Audit fees (1) ..................................................................................................
Audit related fees (2).......................................................................................
Tax fees (3)......................................................................................................
Total...............................................................................................................
$
$
Year Ended December 31,
2018
2017
(in thousands)
1,935
$
—
520
2,455
$
1,843
—
611
2,454
(1) Audit fees represent amounts billed for each of the years presented for professional services rendered in connection
with (i) the integrated audit of our annual financial statements and internal control over financial reporting, (ii) the
review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and
regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This
information is presented as of the latest practicable date for this Annual Report.
(2) Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services
that are reasonably related to the performance of the annual audit or quarterly reviews of our financial statements and
are not reported under audit fees.
(3) Tax fees represent amounts we were billed in each of the years presented for professional services rendered in
connection with tax compliance, tax advice and tax planning.
All services provided by our independent registered public accountant are subject to pre-approval by the audit committee
of our general partner. The audit committee of our general partner is informed of each engagement of the independent
registered public accountant to provide services under the policy. The audit committee of our general partner has approved the
use of PricewaterhouseCoopers LLP as our independent registered public accounting firm, including all services rendered for
the year ended December 31, 2018.
169
PART IV
Item 15. Exhibits, Financial Statement Schedules
(1)
Financial Statements
Consolidated Financial Statements included in this Item 15:
Financial Statements of Rockies Express Pipeline LLC
170
FINANCIAL STATEMENTS
ROCKIES EXPRESS
PIPELINE LLC
For the years ended December 31, 2018, 2017 and 2016
171
Report of Independent Registered Public Accounting Firm
To the Board of Directors of Rockies Express Pipeline LLC
We have audited the accompanying financial statements of Rockies Express Pipeline LLC, which comprise the balance sheets as
of December 31, 2018 and 2017, and the related statements of income, members' equity, and cash flows for each of the three years
in the period ended December 31, 2018.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting
principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal
control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether
due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance
with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements.
The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial
statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's
preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly,
we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the
reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the
financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our
audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rockies
Express Pipeline LLC as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2018, in accordance with accounting principles generally accepted in the United States
of America.
Emphasis of Matters
As described in Note 6 to the financial statements, the Company has significant transactions with related parties.
As discussed in Notes 2 and 7 to the financial statements, the Company changed the manner in which it accounts for revenue in
2018.
Our opinion is not modified with respect to these matters.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 8, 2019
172
ROCKIES EXPRESS PIPELINE LLC
BALANCE SHEETS
December 31,
2018
2017
(in millions)
Current Assets:
ASSETS
Cash and cash equivalents ..................................................................................... $
Accounts receivable, net........................................................................................
Gas imbalances......................................................................................................
Current portion of contract asset ...........................................................................
Other current assets ...............................................................................................
Total Current Assets..........................................................................................
Property, plant and equipment, net.............................................................................
Contract asset .............................................................................................................
Deferred charges and other assets ..............................................................................
Total Noncurrent Assets....................................................................................
1.1
$
76.8
7.4
31.8
3.6
120.7
5,759.0
157.0
15.2
5,931.2
Total Assets................................................................................................................. $
6,051.9
$
Current Liabilities:
LIABILITIES AND EQUITY
Accounts payable................................................................................................... $
Accrued interest.....................................................................................................
Accrued taxes ........................................................................................................
Current portion of long-term debt .........................................................................
Accrued other current liabilities ............................................................................
Total Current Liabilities....................................................................................
Long-term Liabilities and Deferred Credits:
Long-term debt, net ...............................................................................................
Other long-term liabilities and deferred credits.....................................................
Total Long-term Liabilities and Deferred Credits ............................................
Commitments and Contingencies
Members' Equity:
$
21.0
39.0
81.8
525.0
23.6
690.4
1,492.7
10.2
1,502.9
Members' equity ....................................................................................................
Total Liabilities and Members' Equity ....................................................................... $
3,858.6
6,051.9
$
25.7
75.8
6.3
—
14.6
122.4
5,939.2
—
11.8
5,951.0
6,073.4
20.3
56.3
60.0
550.0
27.4
714.0
2,014.8
34.5
2,049.3
3,310.1
6,073.4
The accompanying notes are an integral part of these financial statements.
173
ROCKIES EXPRESS PIPELINE LLC
STATEMENTS OF INCOME
Years Ended December 31,
2018
2017
(in millions)
2016
Revenues:
Transportation services........................................................................ $
Natural gas sales ..................................................................................
Total Revenues................................................................................
Operating Costs and Expenses:
Cost of transportation services ............................................................
Cost of natural gas sales ......................................................................
Operations and maintenance................................................................
Depreciation and amortization ............................................................
General and administrative..................................................................
Taxes, other than income taxes............................................................
Total Operating Costs and Expenses ..............................................
Operating Income .....................................................................................
907.7
$
839.6
$
6.9
914.6
32.3
5.0
27.0
219.6
28.2
85.3
397.4
517.2
9.6
849.2
29.8
7.3
25.3
218.4
30.5
65.3
376.6
472.6
Other (Expense) Income:
Interest expense, net ............................................................................
Gain on litigation settlement ...............................................................
Other income, net ................................................................................
Total Other Expense, net.................................................................
Net Income to Members ........................................................................... $
(150.0)
—
2.3
(147.7)
369.5
$
(168.0)
150.0
3.4
(14.6)
458.0
$
715.1
—
715.1
26.5
—
24.8
204.3
39.9
71.9
367.4
347.7
(158.6)
61.7
27.7
(69.2)
278.5
The accompanying notes are an integral part of these financial statements.
174
ROCKIES EXPRESS PIPELINE LLC
STATEMENTS OF MEMBERS' EQUITY
Rockies
Express
Holdings,
LLC
Total
TEP REX
Holdings,
LLC
(in millions)
Sempra REX
Holdings,
LLC
P66 REX
LLC
Members' Equity:
Balance at January 1, 2016 ........................ $
Net Income to Members ..........................
Contributions from Members ..................
Distributions to Members ........................
Transfer of equity interest........................
Balance at December 31, 2016 .................. $
Net Income to Members ..........................
Contributions from Members ..................
Distributions to Members ........................
Transfer of equity interest (see Note 1) ...
Balance at December 31, 2017 .................. $
Cumulative effect of ASC 606
implementation ........................................
Net Income to Members ..........................
Contributions from Members ..................
Distributions to Members ........................
Transfer of equity interest (see Note 1) ...
Balance at December 31, 2018 .................. $
3,318.2
$
1,659.0
$
— $
829.6
$
278.5
304.9
(471.6)
—
139.3
152.5
(235.8)
—
42.6
50.0
(75.9)
840.8
27.0
26.2
(42.0)
(840.8)
3,430.0
$
1,715.0
$
857.5
$
— $
458.0
92.0
(669.9)
—
3,310.1
$
125.2
369.5
576.5
(522.7)
—
131.1
29.7
(197.6)
(850.3)
827.9
51.0
44.9
1.6
(63.7)
(861.7)
212.4
39.3
(304.8)
850.3
—
—
—
—
$
1,654.7
$
— $
42.9
232.2
430.7
(328.4)
861.7
—
—
—
—
—
3,858.6
$
— $
2,893.8
$
— $
829.6
69.6
76.2
(117.9)
—
857.5
114.5
23.0
(167.5)
—
827.5
31.3
92.4
144.2
(130.6)
—
964.8
The accompanying notes are an integral part of these financial statements.
175
ROCKIES EXPRESS PIPELINE LLC
STATEMENTS OF CASH FLOWS
Cash Flows from Operating Activities:
Net income to Members ...................................................................... $
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation and amortization........................................................
Change in contract asset .................................................................
Changes in components of working capital:
Accounts receivable........................................................................
Current regulatory assets and liabilities, net...................................
Accounts payable and accrued other current liabilities ..................
Accrued taxes..................................................................................
Other current assets and liabilities..................................................
Return of customer deposits ................................................................
Receipt of customer deposits...............................................................
Other operating, net .............................................................................
Net Cash Provided by Operating Activities .............................................
Cash Flows from Investing Activities:
Capital expenditures ............................................................................
Other investing, net .............................................................................
Net Cash Used in Investing Activities......................................................
Cash Flows from Financing Activities:
Contributions from Members ..............................................................
Distributions to Members ....................................................................
Repayment of senior notes ..................................................................
Other financing, net .............................................................................
Net Cash Used in Financing Activities ....................................................
Net Change in Cash and Cash Equivalents ..............................................
Cash and Cash Equivalents, beginning of period.....................................
Cash and Cash Equivalents, end of period ............................................... $
Supplemental Disclosures:
Years Ended December 31,
2018
2017
(in millions)
2016
369.5
$
458.0
$
278.5
224.7
(62.3)
(1.7)
10.0
(19.6)
11.4
(2.8)
(29.9)
8.4
3.9
511.6
(36.5)
(3.3)
(39.8)
576.5
(522.7)
(550.0)
(0.2)
(496.4)
(24.6)
25.7
1.1
$
223.7
—
(25.4)
3.4
(7.0)
(7.6)
—
(55.7)
5.8
1.1
596.3
(108.9)
(2.2)
(111.1)
92.0
(669.9)
—
—
(577.9)
(92.7)
118.4
25.7
$
209.6
—
28.2
(12.5)
12.2
(0.6)
(0.7)
—
52.9
(22.5)
545.1
(305.7)
(2.3)
(308.0)
304.9
(471.6)
—
—
(166.7)
70.4
48.0
118.4
Cash payments for interest, net ........................................................... $
(164.9) $
(164.9) $
(155.6)
Schedule of Noncash Investing and Financing Activities:
Increase in accrual for payment of property, plant and equipment ..... $
2.8
$
— $
—
The accompanying notes are an integral part of these financial statements.
176
ROCKIES EXPRESS PIPELINE LLC
NOTES TO FINANCIAL STATEMENTS
1. Description of Business
Rockies Express Pipeline LLC ("Rockies Express") is a Federal Energy Regulatory Commission ("FERC") regulated
natural gas transportation system with approximately 1,712 miles of natural gas pipeline, including laterals, extending from
Opal, Wyoming and Meeker, Colorado to Clarington, Ohio and consisting of three zones:
• Zone 1 - a 328-mile pipeline from the Meeker Hub in Northwest Colorado, across Southern Wyoming to the Cheyenne
Hub in Weld County, Colorado capable of transporting 2.0 Bcf/d of natural gas from west to east;
• Zone 2 - a 714-mile pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri capable of
transporting 1.8 Bcf/d of natural gas from west to east; and
• Zone 3 - a 643-mile pipeline from Audrain County, Missouri to Clarington, Ohio, which is bi-directional and capable
of transporting 1.8 Bcf/d of natural gas from west to east and 2.6 Bcf/d of natural gas from east to west.
The member interests and voting rights in Rockies Express as of December 31, 2018 are as follows:
•
•
75% - TEP REX Holdings, LLC ("TEP REX"), an indirect wholly owned subsidiary of Tallgrass Energy Partners, LP
("TEP"); and
25% - P66REX LLC, a wholly owned subsidiary of Phillips 66.
On March 31, 2017, TEP, Tallgrass Development LP ("TD"), and Rockies Express Holdings, LLC ("REX Holdings"), an
indirect wholly owned subsidiary of TD, entered into a definitive Purchase and Sale Agreement, pursuant to which TEP
acquired an additional 24.99% membership interest in Rockies Express from TD in exchange for cash consideration of $400
million. This transaction increased TEP REX's aggregate membership interest in Rockies Express to 49.99%.
On February 7, 2018, Tallgrass Development Holdings, LLC ("Tallgrass Development Holdings"), a wholly owned
subsidiary of Tallgrass Equity, acquired REX Holdings and its 25.01% membership interest in Rockies Express as a result of
the merger of TD into Tallgrass Development Holdings. Tallgrass Equity is the sole member of TEP's general partner. Effective
July 1, 2018, REX Holdings was merged into TEP REX, resulting in TEP REX owning a 75% membership interest in Rockies
Express.
2. Summary of Significant Accounting Policies
Basis of Presentation
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of
America ("GAAP") requires management to make estimates and assumptions. These estimates and assumptions affect the
reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of
revenues and expenses. Actual results could differ from these estimates. Certain prior year amounts have been reclassified to
conform to the current presentation.
Use of Estimates
Certain amounts included in or affecting these 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.
Cash and Cash Equivalents
Rockies Express considers all highly liquid investments purchased with an original maturity of three months or less to be
cash equivalents.
177
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are carried at their estimated collectible amounts. Rockies Express periodically reviews and evaluates
the appropriateness of the allowance for doubtful accounts based on a statistical analysis of historical defaults, and adjustments
are recorded as necessary for changes in circumstances and customer-specific information. When specific receivables are
determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $1.0
million and $2.0 million at December 31, 2018 and 2017, respectively.
Fuel Recovery Mechanism
Rockies Express obtains natural gas quantities from its shippers as reimbursement for fuel consumed at compressor
stations and other locations on its system as well as for natural gas quantities lost and otherwise unaccounted for, in accordance
with its tariff and applicable contract terms. Rockies Express tracks the volume and value of associated over- or under-
collections of fuel and lost and unaccounted for quantities through a tracking mechanism referred to as "fuel tracker." Those
amounts are recorded as an addition or reduction to a regulatory asset or liability balance representing the amounts to be
recovered from or refunded to customers through the fuel tracker mechanisms. Fuel tracker volumes are valued using a
weighted-average monthly index price.
Accounting for Regulatory Activities
Rockies Express' regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the
Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("Codification"). This Topic prescribes the
circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and
liabilities represent probable future revenues or expenses to Rockies Express associated with certain charges and credits that
will be recovered from or refunded to customers through the ratemaking process. Rockies Express recorded regulatory assets of
approximately $0.7 million and $10.9 million at December 31, 2018 and 2017, respectively, and regulatory liabilities of
approximately $1.8 million and $2.0 million at December 31, 2018 and 2017, respectively. Regulatory assets and liabilities at
December 31, 2018 and 2017 were primarily attributable to the fuel tracker discussed in "Fuel Recovery Mechanism" above.
For additional details see Note 10 – Regulatory Matters.
Gas Imbalances
Gas imbalances receivable and payable reflect gas volumes owed between Rockies Express and its customers. Gas
imbalances represent the difference between customer nominated versus actual gas receipts from and gas deliveries to
interconnecting pipelines under various operational balancing agreements. Gas imbalances are settled in cash or made up in-
kind subject to the terms of the various agreements and are valued at the average monthly index price.
Property, Plant and Equipment
Property, plant and equipment is stated at historical cost, which for constructed assets includes indirect costs such as
payroll taxes, other employee benefits, allowance for funds used during construction and other costs directly related to the
projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over
the remaining useful life of the asset or major asset component. Rockies Express also capitalizes certain costs directly related to
the construction of assets, including internal labor costs, interest and engineering costs.
Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of depreciable
utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in
accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of property,
plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or
salvage are expensed when incurred.
Rockies Express maintains natural gas in its pipeline, known as "line pack," which serves to maintain the necessary
pressure to allow efficient transmission of natural gas. Line pack is capitalized within "Property, plant and equipment, net" on
the balance sheets and depreciated over the estimated useful life of the pipeline.
Impairment of Long-Lived Assets
Rockies Express reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that
the carrying amount of an asset may not be recoverable. An impairment loss results when the estimated undiscounted future net
cash flows expected to result from the asset's use and its eventual disposition are less than its carrying amount. Rockies Express
assesses its long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset is tested
for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value.
Examples of long-lived asset impairment indicators include:
•
a significant decrease in the market value of a long-lived asset or group;
178
•
•
•
•
•
a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its
physical condition;
a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or
asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the
rate-making process;
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction
of the long-lived asset or asset group;
a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or
forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and
a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of
significantly before the end of its previously estimated useful life.
When an impairment indicator is present, Rockies Express first assesses the recoverability of the long-lived assets by
comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset
to the carrying amount of the asset. If the carrying amount is higher than the undiscounted future cash flows, the fair value of
the asset is assessed using a discounted cash flow analysis to determine the amount of impairment, if any, to be recognized.
Depreciation and Amortization
Rockies Express has elected to compute depreciation using a composite method employed by applying a single
depreciation rate to a group of assets with similar economic characteristics. The annual composite rate of depreciation for the
years ended December 31, 2018, 2017, and 2016 was 2.86%.
Allowance for Funds Used During Construction
Included in the cost of "Property, plant and equipment, net" on the accompanying balance sheets is an allowance for funds
used during construction ("AFUDC"). AFUDC represents the estimated cost of debt, from borrowed funds, or the estimated
cost of capital, from equity funds, during the construction period. During the years ended December 31, 2018, 2017 and 2016
Rockies Express recognized AFUDC associated with the estimated cost of debt of approximately $0.3 million, $0.2 million,
and $9.3 million, respectively, recorded as "Interest expense, net" on the accompanying statements of income. During the years
ended December 31, 2018, 2017, and 2016, Rockies Express recognized AFUDC associated with the estimated cost of capital
from equity funds of approximately $0.6 million, $0.5 million, and $24.8 million, respectively, recorded as "Other income, net"
on the accompanying statements of income.
Revenue Recognition
In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with
Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition
guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is
that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that
reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core
principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance
obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations
in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also
mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing
and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include
qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and
assets recognized from the costs to obtain or fulfill a contract.
Management completed its evaluation and implemented the revised guidance using the modified retrospective method as
of January 1, 2018. This approach allows Rockies Express to apply the new standard to (i) all new contracts entered into after
January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under
legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Revenues presented in the
comparative financial statements for periods prior to January 1, 2018 have not been revised.
On January 1, 2018, Rockies Express recorded a cumulative effect adjustment to equity of $125.2 million. The cumulative
effect adjustment arose as a result of the allocation of the transaction price to a series of individual performance obligations in
certain long-term transportation contracts with rates that vary throughout the term of the contract. Rockies Express established
a contract asset on January 1, 2018 that reflects the amount by which the revenue that would have been recognized pursuant to
ASC 606 exceeds the actual cash collected from the customer for periods prior to implementation and will be reversed over the
remaining term of the contract.
179
See Note 7 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and the
additional requirements prescribed by the standard. These new disclosures include information regarding the significant
judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities.
Deferred Financing Costs
Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing
period using the effective interest method. Deferred financing costs associated with long-term debt are presented as a reduction
to the corresponding debt on the accompanying balance sheets. Deferred financing costs associated with revolving credit
facilities or lines of credit are classified as noncurrent assets on the accompanying balance sheets.
Deferred Charges and Deferred Credits
Rockies Express has $0.5 million remaining of an initial $20.0 million deferred charge and deferred credit relating to a
customer contract. The deferred charge is being amortized using a straight-line-method over the life of the related contract.
Amortization of the deferred charge for each of the years ended December 31, 2018, 2017, and 2016 was $2.0 million and is
included within transportation services revenues in the accompanying statements of income. The deferred credit is payable over
a period of 10 years.
Environmental Matters
Rockies Express expenses or capitalizes, as appropriate, environmental expenditures that relate to current operations.
Rockies Express expenses amounts that relate to an existing condition caused by past operations that do not contribute to
current or future revenue generation. Rockies Express does not discount environmental liabilities to a net present value, and
records environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be
reasonably estimated. Generally, recording of these accruals coincides with the completion of a feasibility study or a
commitment to a formal plan of action.
Fair Value
Fair value, as defined in the fair value measurement accounting guidance, is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price.
The fair value measurement accounting guidance requires that Rockies Express make assumptions that market participants
would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk
(the risk that an obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty
(for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage
factors in determining the instruments' fair value. The principal or most advantageous market should be considered from the
perspective of the reporting entity. The fair value of current financial assets and liabilities approximate their reported carrying
amounts as of December 31, 2018 and 2017.
Income Taxes
Rockies Express is a limited liability company that has elected to be treated as a partnership for income tax purposes.
Accordingly, no provision for federal or state income taxes has been recorded in the financial statements of Rockies Express
and the tax effects of Rockies Express' activities accrue to its Members.
Accounting Pronouncements Not Yet Adopted
ASU No. 2016-02, "Leases (Topic 842)"
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update
to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by
recognizing 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.
Subsequent to issuing ASU 2016-02, the FASB has issued a series of subsequent updates to the lease guidance in Topic
842, including ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, ASU
No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Leases (Topic 842): Targeted Improvements,
and ASU 2018-20, Leases (Topic 842): Narrow-Scope Improvements for Lessors. The amendments in ASU 2016-02, ASU
2018-01, ASU 2018-10, ASU 2018-11, and ASU 2018-20 are effective for public entities for annual reporting periods
beginning after December 15, 2018, and for interim periods within that reporting period.
180
Management has completed its evaluation and implemented the revised guidance using the modified retrospective method
as of January 1, 2019. The approach allows Rockies Express 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.
Rockies Express will not recast comparative periods in the accompanying financial statements. Management elected the
package of practical expedients permitted under the transition guidance within the new standard, which among other things,
allowed Rockies Express to carry forward the historical lease classification. Management also elected the practical expedient
related to land easements, allowing Rockies Express to carry forward the accounting treatment for land easements on existing
agreements.
Adoption of the new standard resulted in the recognition of ROU assets and lease liabilities for operating leases of
approximately $40.0 million.
3. Property, Plant and Equipment
Rockies Express' property, plant and equipment, net consisted of the following:
Natural gas pipelines ........................................................................................... $
General and other ................................................................................................
Construction work in progress ............................................................................
Accumulated depreciation and amortization.......................................................
Total property, plant and equipment, net............................................................. $
December 31,
2018
2017
(in millions)
7,677.0
$
15.8
27.8
(1,961.6)
5,759.0
$
7,661.2
15.4
11.9
(1,749.3)
5,939.2
Depreciation expense was approximately $219.6 million, $218.4 million and $204.3 million for the years ended
December 31, 2018, 2017 and 2016, respectively.
4. Financing
Debt
Total outstanding debt as of December 31, 2018 and 2017 consisted of the following:
6.85% senior notes due July 15, 2018 (1)............................................................. $
6.00% senior notes due January 15, 2019 (2) .......................................................
5.625% senior notes due April 15, 2020 .............................................................
7.50% senior notes due July 15, 2038.................................................................
6.875% senior notes due April 15, 2040 .............................................................
Less: Unamortized debt discount and deferred financing costs .....................
Total debt, net......................................................................................................
Less: Current portion......................................................................................
Total long-term debt, net ..................................................................................... $
December 31,
2018
2017
(in millions)
— $
525.0
750.0
250.0
500.0
(7.3)
2,017.7
(525.0)
1,492.7
$
550.0
525.0
750.0
250.0
500.0
(10.2)
2,564.8
(550.0)
2,014.8
(1) The 6.85% senior notes were repaid on July 15, 2018. The repayment was funded by contributions from the Rockies
Express Members, as discussed further below.
(2) The 6.00% senior notes were repaid on January 15, 2019. The repayment was funded by the issuance of a 364-Day
Term Loan Agreement effective January 8, 2019, as discussed further below.
Rockies Express Senior Notes
The senior notes issued by Rockies Express are redeemable in whole or in part, at Rockies Express' option at any time, at
redemption prices defined in the associated indenture agreements.
181
All payments of principal and interest with respect to the fixed rate senior notes are the sole obligation of Rockies Express.
Note holders have no recourse against Rockies Express' Members or their respective officers, directors, employees,
shareholders, members, managers, unit holders or affiliates for any failure by Rockies Express to perform or comply with its
obligations pursuant to the notes or the indenture. As of December 31, 2018, Rockies Express was in compliance with the
covenants required under the senior notes.
Maturities of Debt
The scheduled maturities of Rockies Express' outstanding debt balances as of December 31, 2018 are summarized as
follows (in millions):
Year
2019.................................................................................................................................................
2020.................................................................................................................................................
2021.................................................................................................................................................
2022.................................................................................................................................................
2023.................................................................................................................................................
Thereafter ........................................................................................................................................
Total scheduled maturities...............................................................................................................
Unamortized debt discount and deferred financing costs ...............................................................
Total debt.........................................................................................................................................
Scheduled Maturities
$
$
525.0
750.0
—
—
—
750.0
2,025.0
(7.3)
2,017.7
The 6.00% senior notes were repaid on January 15, 2019. The repayment was funded by the issuance of a 364-Day Term
Loan Agreement effective January 8, 2019 (the "Term Loan") which matures on January 7, 2020. As a result, Rockies Express
has $525 million of debt scheduled to mature within one year of the issuance of these financial statements. Management has
obtained a letter of support from the Members of Rockies Express confirming the Members' intent and ability to provide
Rockies Express with financial support through at least one year and a day beyond February 8, 2019 to the extent that other
sources of funding are not otherwise available to Rockies Express. This support from the Members effectively alleviates the
risk surrounding the ability of Rockies Express to continue as a going concern.
Rockies Express Revolving Credit Facility
On October 1, 2015, Rockies Express entered into a $150 million senior unsecured revolving credit facility ("the revolving
credit facility") with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders, which will mature on January
31, 2020. The revolving credit facility includes a $75 million sublimit for letters of credit and a $20 million sublimit for swing
line loans and may be used for working capital and general company purposes. The revolving credit facility also contains an
accordion feature whereby Rockies Express can increase the size of the credit facility to an aggregate of $200 million, subject
to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. As of
December 31, 2018, there were no outstanding borrowings or letters of credit issued under the revolving credit facility.
Borrowings under the credit facility bear interest, at Rockies Express' option, at either (a) a base rate, which will be a rate
equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted
Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For borrowings
bearing interest based on the base rate, the applicable margin was initially 1.00%, and for loans bearing interest based on the
reserve adjusted Eurodollar rate, the applicable margin was initially 2.00%. After the first full fiscal quarter, the applicable
margin ranges from 0.50% to 1.25% for base rate borrowings and 1.50% to 2.25% for reserve adjusted Eurodollar rate
borrowings, based upon Rockies Express' total leverage ratio. The unused portion of the credit facility is subject to a
commitment fee, which ranges from 0.20% to 0.45% based upon Rockies Express' total leverage ratio.
Rockies Express has the option to have the applicable margin determined based on Rockies Express' credit ratings. If
Rockies Express were to make an election to exercise this option, the applicable margin would range from 0.125% to 1.00% for
base rate borrowings and 1.125% to 2.00% for reserve adjusted Eurodollar borrowings, based on Rockies Express' credit
ratings. Under such an election, the commitment fee would range from 0.125% to 0.40%, also based on Rockies Express' credit
ratings.
182
Covenants Under the Term Loan and Revolving Credit Facility
The Term Loan and the revolving credit facility generally require Rockies Express to comply with various affirmative and
negative covenants, including a limit on the leverage ratio (as defined in each credit agreement) of Rockies Express and
restrictions on:
•
•
•
•
incurring secured indebtedness;
entering into mergers, consolidations and sales of assets;
granting liens;
entering into transactions with affiliates; and
• making restricted payments.
As of December 31, 2018, Rockies Express was in compliance with the covenants required under the revolving credit
facility.
Fair Value
The following table sets forth the carrying amount and fair value of Rockies Express' debt, which is not measured at fair
value in the accompanying balance sheets as of December 31, 2018 and 2017, but for which fair value is disclosed:
Fair Value
Quoted prices
in active markets
for identical assets
(Level 1)
Significant
other observable
inputs
(Level 2)
Significant
unobservable
inputs
(Level 3)
Total
Carrying
Amount
December 31, 2018 ................. $
December 31, 2017 ................. $
— $
— $
(in millions)
2,086.9
2,752.1
$
$
— $
— $
2,086.9
2,752.1
$
$
2,017.7
2,564.8
The debt is carried at amortized cost, net of deferred financing costs. The estimated fair value of Rockies Express'
outstanding private placement debt is based upon quoted market prices adjusted for illiquid markets. Rockies Express is not
aware of any factors that would significantly affect the estimated fair value subsequent to December 31, 2018.
5. Members' Equity
During the years ended December 31, 2018, 2017, and 2016, Rockies Express made distributions to Members of $522.7
million, $669.9 million, and $471.6 million, respectively. The distributions paid by Rockies Express during the year ended
December 31, 2017 included a distribution of the proceeds from the Ultra settlement discussed in Note 11 – Legal and
Environmental Matters.
During the years ended December 31, 2018, 2017, and 2016, Rockies Express received contributions from Members of
$576.5 million, $92.0 million, and $304.9 million, respectively. Contributions from Members during the year ended December
31, 2018 included a special contribution of approximately $550 million to fund the repayment of senior notes as discussed in
Note 4 – Financing. Contributions from Members during the years ended December 31, 2017 and 2016 were primarily used to
fund the construction and other costs of the Zone 3 Capacity Enhancement project, as discussed in Note 10 – Regulatory
Matters.
Additional contributions and distributions were made subsequent to December 31, 2018. For details see Note 12 –
Subsequent Events.
6. Related Party Transactions
Rockies Express has an operating agreement with Tallgrass NatGas Operator, LLC ("NatGas"), a subsidiary of TEP, under
which NatGas provides and bills Rockies Express for various services at cost including employee labor costs, information
technology services, employee health and retirement benefits, and insurance for property and casualty risks. In addition,
NatGas receives a management oversight fee in the amount of 1% of Rockies Express' earnings before interest, taxes,
depreciation, and amortization. Rockies Express' practice is to settle receivable and payable balances that exist with affiliates in
the following month.
183
Totals of significant transactions with affiliated companies are as follows:
Revenues: Transportation services (1).............................. $
Charges to Rockies Express:
Compensation, benefits and other charges............... $
General and administrative charges from affiliate... $
Management Fees:
Tallgrass NatGas Operator, LLC.............................. $
Years Ended December 31,
2018
2017
(in millions)
2016
— $
— $
18.1
10.3
7.5
$
$
$
18.6
8.9
8.5
$
$
$
14.4
20.6
9.4
6.2
(1) Transportation services revenue for the year ended December 31, 2016 is primarily from Sempra Energy prior to the
May 6, 2016 sale of Sempra Energy's ownership to TEP REX.
Balances with affiliated companies included in the accompanying balance sheets are as follows:
December 31,
2018
2017
(in millions)
Payables to affiliated companies:
TEP................................................................................................................. $
TD...................................................................................................................
Total payables to affiliated companies ...................................................... $
3.4
—
3.4
$
$
Gas imbalances with affiliated shippers are as follows:
Affiliate gas imbalance receivables .................................................................... $
7. Revenue from Contracts with Customers
December 31,
2018
2017
(in millions)
0.8
$
1.3
2.3
3.6
0.4
As discussed in Note 2 – Summary of Significant Accounting Policies, Rockies Express adopted the guidance in ASC Topic
606 effective January 1, 2018 using the modified retrospective method of adoption. As a result, revenue reported for the years
ended December 31, 2017 and 2016 have not been revised. The following tables provide the impact of the guidance on the
Rockies Express balance sheet as of December 31, 2018 and statement of income for the year ended December 31, 2018:
December 31, 2018
As currently
reported
Under previous
guidance
Impact of ASC
Topic 606
(in millions)
Current portion of contract asset ................................................. $
Contract asset............................................................................... $
31.8
157.0
$
$
— $
— $
31.8 (1)
157.0 (1)
184
Transportation services................................................................ $
General and administrative.......................................................... $
Net Income to Members .............................................................. $
Year Ended December 31, 2018
As currently
reported
Under previous
guidance
Impact of ASC
Topic 606
(in millions)
907.7
28.2
369.5
$
$
$
845.4
27.6
307.8
$
$
$
62.3 (1)
0.6 (2)
61.7
(1) Reflects the impact of the allocation of the transaction price to a series of individual performance obligations in certain
long-term transportation contracts with rates that vary throughout the term of the contract and related contract asset.
(2) Reflects the additional management fee associated with the effect of the change in gas transportation revenue.
Disaggregated Revenue
A summary of our revenue by line of business is as follows:
Year Ended December
31, 2018
(in millions)
Firm Transportation - West to East .................................................................................................
Firm Transportation - East to West .................................................................................................
All other ..........................................................................................................................................
Total firm transportation.............................................................................................................
Natural gas sales..............................................................................................................................
Total revenue ..............................................................................................................................
$
$
467.7
425.0
15.0
907.7
6.9
914.6
Performance Obligations
A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of
account in ASC Topic 606. A contract's transaction price is allocated to each distinct performance obligation and recognized as
revenue when, or as, the performance obligation is satisfied. The majority of Rockies Express' contracts have a single
performance obligation and are billed and collected monthly. These performance obligations typically include an obligation to
stand ready to provide natural gas transportation service over the life of the contract, which is a series. These performance
obligations are satisfied over time using each day of service to measure progress toward satisfaction of the performance
obligation.
Rockies Express also engages in commodity sales, in which the performance obligations include an obligation to deliver
the specified volume of a commodity to the designated receipt point. Revenue from commodity sales is recognized at a point in
time when the customer obtains control of the commodity, typically upon delivery to the designated delivery point when the
customer accepts and takes possession of the commodity.
On December 31, 2018, we had $7.5 billion of remaining performance obligations, which we refer to as total backlog.
Total backlog includes performance obligations under firm transportation contracts, and excludes variable consideration that is
not estimated at contract inception, as discussed further below. We expect to recognize the total backlog during future periods
as follows (in millions):
Year
2019.................................................................................................................................................
2020.................................................................................................................................................
2021.................................................................................................................................................
2022.................................................................................................................................................
2023.................................................................................................................................................
Thereafter ........................................................................................................................................
Total............................................................................................................................................
$
$
Estimated Revenue
853.9
617.3
606.3
576.2
572.0
4,278.5
7,504.2
185
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.
The nature of our contracts gives rise to several types of variable consideration, including 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 performance obligation, we do not estimate the total variable consideration for the overall
performance obligation because the uncertainty related to the consideration is resolved each month as the distinct service is
provided. 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.
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 balance sheets. Revenue is generally billed and
collected monthly based on services provided or volumes sold. As of December 31, 2018, we had recognized a contract asset of
$188.8 million reflecting the amount by which the revenue recognized exceeds the actual cash collected from certain contracts
with rates that vary throughout the term of the contract.
8. Commitments and Contingent Liabilities
Leases
Total rental expense under operating leases was $29.2 million for the years ended December 31, 2018, 2017, and 2016.
Future minimum commitments related to these leases as of December 31, 2018 are as follows (in millions):
Year
2019.................................................................................................................................................
2020.................................................................................................................................................
2021.................................................................................................................................................
2022.................................................................................................................................................
2023.................................................................................................................................................
Thereafter ........................................................................................................................................
Total.................................................................................................................................................
$
$
Future Minimum
Lease Payments
29.1
29.1
29.1
29.1
29.1
116.4
261.9
The future minimum rental commitments are primarily attributable to a 20-year capacity lease agreement with Overthrust
Pipeline Company ("Overthrust") which commenced on January 1, 2008. The capacity lease provides the right to transport on a
firm basis 625 MMcf/d of natural gas through Overthrust's system from either the Williams Field Services Opal Processing
Plant or the TEPPCO Pioneer Processing Plant to the Wamsutter interconnect.
Capital Expenditures
Approximately $60.8 million of Rockies Express' capital expenditure budget for 2019 had been committed for purchases
of property, plant and equipment at December 31, 2018.
9. Major Customers
During 2018, three non-affiliated shippers accounted for $168.5 million (18%), $118.7 million (13%), and $112.2 million
(12%), respectively of Rockies Express' total revenues. During 2017, three non-affiliated shippers accounted for $169.4 million
(20%), $111.9 million (13%), and $101.3 million (12%), respectively of Rockies Express' total revenues. During 2016, four
non-affiliated shippers accounted for $164.8 million (23%), $82.9 million (12%), $71.4 million (10%), and $70.4 million
(10%), respectively of Rockies Express' total revenues. Rockies Express attempts to mitigate credit risk by seeking collateral or
financial guarantees and letters of credit from customers.
186
10. Regulatory Matters
There are no regulatory proceedings challenging the transportation rates of Rockies Express. Rockies Express has made
certain regulatory filings with the FERC, including the following:
Petition for Declaratory Order – FERC Docket No. RP13-969-000
In June 2013, in Docket No. RP13-969-000, Rockies Express filed with the FERC a Petition for Declaratory Order which
sought a ruling that the "most favored nations" or "MFN" provisions contained in Rockies Express' negotiated rate agreements
("NRAs") with its Foundation and Anchor Shippers would not prevent Rockies Express from providing firm transportation
service at rates lower than Foundation and Anchor Shippers' rates that (1) have an east-to-west primary path; (2) are for a term
of one year or longer; and (3) are limited to service in one rate zone and therefore do not utilize all of the same facilities or rate
zones as the service provided pursuant to the Foundation and Anchor Shipper NRAs. In November 2013, the FERC issued a
declaratory order finding that the potential transactions would not trigger the MFN rights of Rockies Express' Foundation and
Anchor Shippers. Various parties filed requests for rehearing of the FERC's declaratory order.
In September 2014 and December 2015, the FERC accepted amended contracts with the shippers holding MFN rights on
Rockies Express, which reflect the terms of settlements between these shippers and Rockies Express. The settlements provide
additional clarity with respect to the applicability of the settling shippers' MFN rights, sharing by Rockies Express of certain
transportation revenues, and the withdrawal of the settling shippers from the Petition for Declaratory Order proceeding. On
September 27, 2017, FERC issued an order denying the requests for rehearing of the declaratory order issued in November
2013, and no party sought judicial appeal of the FERC order denying rehearing within the statutory deadline.
Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000
On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the FERC an application for (1) authorization
to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio
(Seneca Lateral Facilities described in Docket Nos. CP13-539-000 and CP14-194-000) from Natural Gas Policy Act of 1978
Section 311 authority to Natural Gas Act ("NGA") Section 7 jurisdiction, and (2) issuance of a certificate of public convenience
and necessity authorizing Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC
issued a Certificate to Rockies Express granting its requested authorizations and on June 1, 2016 Rockies Express commenced
NGA service on the Seneca Lateral.
Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000
On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to
construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur
County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain
ancillary facilities. The facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 0.8 Bcf/d. Pursuant to
the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the
project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity
authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the
project facilities. The project was placed in-service for the full 0.8 Bcf/d on January 6, 2017.
2016 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP16-702 and RP17-240
On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in
Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016. On December 1, 2016, Rockies
Express made an interim fuel tracker filing with a proposed effective date of January 1, 2017 in Docket No. RP17-240. The
FERC issued an order accepting the filing on December 29, 2016.
Electric Power Charge Clarification - FERC Docket No. RP17-285
On December 21, 2016, in Docket No. RP17-285, Rockies Express proposed certain revisions to the General Terms and
Conditions of its tariff to clarify that the electric power costs associated with the operation of gas coolers installed in
association with the Zone 3 Capacity Enhancement Project at both electric and gas powered stations, will be included in the
Power Cost Tracker. Several shippers submitted comments on the proposal. The FERC issued an order on January 19, 2017
accepting the proposed revisions permitting the recovery of electric power costs from the operation of both gas and electric
powered compressor stations, subject to certain clarifications.
2017 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP17-401 and RP17-1064
On February 13, 2017, in Docket No. RP17-401, Rockies Express made its annual fuel and power cost tracker filing with a
proposed effective date of April 1, 2017. The FERC issued an order accepting the filing, including certain requested waivers, on
March 21, 2017. On September 20, 2017, Rockies Express made its interim fuel tracker filing in Docket No. RP17-1064 with a
proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on October 18, 2017.
187
Increased Frequency of FL&U and PCT Adjustments - FERC Docket No. RP18-228
On December 1, 2017, in Docket No. RP18-228, Rockies Express made a filing with the FERC to increase the frequency
in which it may adjust fixed fuel and lost and unaccounted for retainages and power cost tracker charges during the year so that
its recovery of fixed fuel and lost and unaccounted for charges and power costs more closely track usage. Rockies Express
proposed an effective date of April 1, 2018. The comment period ended on December 13, 2017, and no parties opposed Rockies
Express' filing. On April 4, 2018, the FERC issued a letter order accepting Rockies Express' proposal, subject to certain
modifications. Rockies Express submitted a compliance filing reflecting the approved tariff provisions and requested
modifications on April 10, 2018. No comments on the compliance filing were submitted by the comment deadline of April 16,
2018. On April 18, 2018, the FERC issued an order accepting Rockies Express' compliance filing effective April 19, 2018.
2018 Annual FERC Fuel Tracking Filing - FERC Docket No. RP18-453
On February 20, 2018, in Docket No. RP18-453, Rockies Express made its annual fuel and power cost tracker filing with a
proposed effective date of April 1, 2018. The FERC issued an order accepting the filing on March 19, 2018.
Cheyenne Hub Enhancement Project - FERC Docket CP18-103
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. 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 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.
Rockies Express Form No. 501-G Filing - FERC Docket No. RP19-412
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 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. The filing remains pending
before the FERC.
11. Legal and Environmental Matters
Legal
In addition to the matters discussed below, Rockies Express is a defendant in various lawsuits arising from the day-to-day
operations of its business. Although no assurance can be given, Rockies Express believes, based on its experiences to date, that
the ultimate resolution of such routine items will not have a material adverse impact on its business, financial position, results
of operations or cash flows.
Rockies Express has evaluated claims in accordance with the accounting guidance for contingencies that it deems both
probable and reasonably estimable and, accordingly, has recorded no reserve for legal claims as of December 31, 2018 or 2017.
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
December 31, 2018, Rockies Express has paid public utility excise taxes to the state of Ohio totaling $7.1 million and has
accrued an additional $3.3 million for amounts expected to be assessed through the year ended December 31, 2018. 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 $10.4 million asset representing the anticipated refund of the public utility excise taxes
paid.
188
Mineral Management Service Lawsuit
On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S.
Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements
for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA")
conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay.
On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was
liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for
the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in
this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on
June 23, 2016.
Ultra Resources
In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2
Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14,
2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, seeking
approximately $303 million in damages and other relief. On April 29, 2016, Ultra and certain of its debtor affiliates filed for
protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District
of Texas, which operated as a stay of the Harris County state court proceeding.
On January 12, 2017, Rockies Express and Ultra entered into an agreement to settle Rockies Express' approximately $303
million claim against Ultra. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of
$150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express
commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37 per dth/d, or
approximately $26.8 million annually.
Michels Corporation
On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the
Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral
Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract,
negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe
and Noble Counties, asserting $24.2 million as the amount due.
On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $10 million cash payment by
Rockies Express. The cash payment was inclusive of approximately $5.9 million that Rockies Express had been withholding
from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement
and Rockies Express made the $10 million cash payment to Michels on February 16, 2017.
Environmental, Health and Safety
Rockies Express is 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. Rockies Express believes that compliance with these laws will
not have a material adverse impact on its 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 Rockies Express to incur significant costs.
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. Total cost of remediation was approximately $6.1 million prior
to any insurance recoveries. Permanent repairs were completed in September 2018. As of February 8, 2019, Rockies Express
has recovered a significant majority of these costs from insurance.
12. Subsequent Events
Subsequent events, which are events or transactions that occurred after December 31, 2018 through the issuance of the
accompanying financial statements, have been evaluated through February 8, 2019.
Members' Equity
Rockies Express paid distributions of $46.3 million to its Members and received contributions from its Members of $7.9
million in January 2019.
189
(2)
Financial Statement Schedules
All schedules are omitted because they are either not applicable or the required information is shown in the
Consolidated Financial Statements or notes thereto included in Item 8 of this Form 10-K.
(3)
Exhibits
Exhibit No. Description
2.1
Agreement and Plan of Merger, dated as of March 26, 2018, by and among Tallgrass Energy GP, LP, Tallgrass
Equity, LLC, Razor Merger Sub, LLC, Tallgrass Energy Partners, LP and Tallgrass MLP GP, LLC
(incorporated by reference to Exhibit 2.1 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on
March 27, 2018).
2.2
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
4.1
4.2
4.3
4.4
4.5
Agreement and Plan of Merger, dated as of February 7, 2018, by and among Tallgrass Energy GP, LP,
Tallgrass Development, LP, Tallgrass Equity, LLC, Tallgrass Development Holdings, LLC and Tallgrass
Energy Holdings, LLC (incorporated by reference to Exhibit 2.2 to Tallgrass Energy, LP’s Quarterly Report
on Form 10-Q filed on May 3, 2018).
Certificate of Limited Partnership of Tallgrass Energy GP, LP, dated February 10, 2015 (incorporated by
reference to Exhibit 3.1 to Tallgrass Energy GP, LP's Registration Statement on Form S-1 filed February 24,
2015).
Certificate of Formation of TEGP Management, LLC, dated February 10, 2015 (incorporated by reference to
Exhibit 3.3 to Tallgrass Energy GP, LP's Registration Statement on Form S-1 filed February 24, 2015).
Certificate of Formation of Tallgrass GP Holdings, LLC, dated March 28, 2013 (now known as Tallgrass
Equity, LLC) (incorporated by reference to Exhibit 3.5 to Tallgrass Energy GP, LP's Registration Statement on
Form S-1 filed February 24, 2015).
Certificate of Amendment to Certificate of Formation of Tallgrass GP Holdings, LLC, dated February 20,
2015 (now known as Tallgrass Equity, LLC) (incorporated by reference to Exhibit 3.6 to Tallgrass Energy GP,
LP's Registration Statement on Form S-1 filed February 24, 2015).
Second Amended and Restated Limited Liability Company Agreement of Tallgrass Equity, LLC, dated May
12, 2015 (incorporated by reference to Exhibit 3.7 to Tallgrass Energy GP, LP's Quarterly Report on Form 10-
Q filed on June 18, 2015).
Certificate of Amendment to Limited Liability Company Certificate of Formation of TEGP Management,
LLC, dated June 29, 2018 (incorporated by reference to Exhibit 3.1 to Tallgrass Energy, LP's Current Report
on Form 8-K filed on July 2, 2018).
Certificate of Amendment to Certificate of Limited Partnership of Tallgrass Energy GP, LP, dated June 29,
2018 (incorporated by reference to Exhibit 3.2 to Tallgrass Energy, LP's Current Report on Form 8-K filed on
July 2, 2018).
Second Amended and Restated Agreement of Limited Partnership of Tallgrass Energy, LP, dated July 1, 2018
(incorporated by reference to Exhibit 3.3 to Tallgrass Energy, LP's Current Report on Form 8-K filed on July
2, 2018).
Second Amended and Restated Limited Liability Company Agreement of Tallgrass Energy GP, LLC, dated
July 1, 2018 (incorporated by reference to Exhibit 3.4 to Tallgrass Energy, LP's Current Report on Form 8-K
filed on July 2, 2018).
Specimen certificate representing Class A Shares (incorporated by reference to Exhibit 4.1 to Tallgrass Energy
GP, LP's Registration Statement on Form S-1/A filed April 20, 2015).
Registration Rights Agreement, dated May 12, 2015, by and among Tallgrass Energy GP, LP and each of the
Initial Holders listed on an annex thereto (incorporated by reference to Exhibit 4.2 to Tallgrass Energy GP,
LP's Quarterly Report on Form 10-Q filed on June 18, 2015).
Indenture, dated September 1, 2016, among Tallgrass Energy Partners, LP, Tallgrass Energy Finance Corp.,
the Guarantors named therein and U.S. Bank National Association, as trustee. (incorporated by reference to
Exhibit 4.1 to Tallgrass Energy Partners, LP's Current Report on Form 8-K filed on September 1, 2016).
Form of 5.50% Senior Note (included as Exhibit A in Exhibit 4.1 which is incorporated by reference to
Exhibit 4.1 to Tallgrass Energy Partners, LP's Current Report on Form 8-K filed on September 1, 2016).
Indenture, dated September 15, 2017, among Tallgrass Energy Partners, LP, Tallgrass Energy Finance Corp.,
the Guarantors named therein and U.S. Bank National Association, as trustee. (incorporated by reference to
Exhibit 4.1 to Tallgrass Energy Partners, LP's Current Report on Form 8-K filed on September 15, 2017).
190
4.6
4.7
4.8
10.1
10.2†
10.3†
10.4†
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
Form of 5.50% Senior Note (included as Exhibit A in Exhibit 4.1 which is incorporated by reference to
Exhibit 4.1 to Tallgrass Energy Partners, LP's Current Report on Form 8-K filed on September 15, 2017).
Indenture, dated as of September 26, 2018, among Tallgrass Energy Partners, LP, Tallgrass Energy Finance
Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by
reference to Exhibit 4.1 to Tallgrass Energy, LP's Current Report on Form 8-K filed on September 26, 2018).
Form of 4.75% Senior Note (included as Exhibit A in Exhibit 4.1 which is incorporated by reference to
Exhibit 4.1 to Tallgrass Energy, LP's Current Report on Form 8-K filed on September 26, 2018).
Omnibus Agreement, dated May 12, 2015, by and among Tallgrass Energy Holdings, LLC, Tallgrass Energy
GP, LP, TEGP Management, LLC and Tallgrass Equity, LLC (incorporated by reference to Exhibit 10.1 to
Tallgrass Energy GP, LP's Current Report on Form 8-K filed May 12, 2015).
Form of Employee Equity Participation Share Agreement (incorporated by reference to Exhibit 4.5 to the
Partnership's Registration Statement on Form S-8 filed on July 17, 2015).
Second Amended and Restated Employment Agreement, dated November 2, 2016, by and among Tallgrass
Management, LLC, Tallgrass Energy Holdings, LLC, Tallgrass Equity, LLC, Tallgrass MLP GP, LLC, TEGP
Management, LLC and David G. Dehaemers, Jr. (incorporated by reference to Exhibit 10.4 to Tallgrass
Energy Partners, LP's Annual Report on Form 10-K filed February 15, 2017).
Form of Employee Equity Participation Unit Agreement (incorporated by reference to Exhibit 4.5 to Tallgrass
Energy Partners, LP's Registration Statement on Form S-8 filed on June 18, 2013).
Second Amended and Restated Limited Liability Company Agreement of Rockies Express Pipeline LLC,
dated effective as of January 1, 2010, among Rockies Express Holdings, LLC (as successor by assignment to
Kinder Morgan W2E Pipeline LLC), TEP REX Holdings, LLC (as successor by assignment to Sempra REX
Holdings, LLC and P&S Project I, LLC), and P66REX LLC (f/k/a COPREX LLC) (incorporated by reference
to Exhibit 10.4 to the Partnership's Quarterly Report on Form 10-Q filed on August 3, 2016).
Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Rockies
Express Pipeline LLC, dated effective as of November 13, 2012, among Kinder Morgan W2E Pipeline LLC,
TEP REX Holdings, LLC (as successor by assignment to Sempra REX Holdings, LLC and P&S Project I,
LLC), Rockies Express Holdings, LLC and P66REX LLC (f/k/a COPREX LLC) (incorporated by reference
to Exhibit 10.5 to the Partnership's Quarterly Report on Form 10-Q filed on August 3, 2016).
Amendment No. 2 to Second Amended and Restated Limited Liability Company Agreement, dated effective
as of May 5, 2016, among Sempra REX Holdings, LLC and P&S Project I, LLC, Rockies Express Holdings,
LLC and P66REX LLC (incorporated by reference to Exhibit 10.6 to the Partnership's Quarterly Report on
Form 10-Q filed on August 3, 2016).
Purchase and Sale Agreement, dated as of January 1, 2017, by and among Tallgrass Energy Partners, LP,
Tallgrass Development, LP and Tallgrass Operations, LLC (incorporated by reference to Exhibit 10.1 to the
Partnership's Current Report on Form 8-K filed on January 3, 2017).
Form of Employee Equity Participation Unit Agreement (incorporated by reference to Exhibit 10.1 to
Tallgrass Energy Partners, LP's Current Report on Form 10-Q filed on November 2, 2017).
Support Agreement, dated as of March 26, 2018, by and among Tallgrass Energy GP, LP, Tallgrass Equity,
LLC and Tallgrass Energy Partners, LP (incorporated by reference to Exhibit 10.1 to Tallgrass Energy, LP’s
Current Report on Form 8-K filed on March 27, 2018).
Omnibus Agreement, dated May 17, 2013, by and among Tallgrass Development, LP, Tallgrass Energy
Partners, LP, Tallgrass MLP GP, LLC and Tallgrass Development GP, LLC (incorporated by reference to
Exhibit 10.2 to Tallgrass Energy Partners, LP's Current Report on Form 8-K filed May 17, 2013).
Second Amended and Restated Credit Agreement, dated June 2, 2017, by and among Tallgrass Energy
Partners, LP, Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders
named therein (incorporated by reference to Exhibit 10.1 to Tallgrass Energy Partners, LP’s Quarterly Report
on Form 10-Q filed on August 2, 2017).
Tallgrass Energy GP, LLC Long-Term Incentive Plan (as amended and restated effective August 2, 2018)
(incorporated by reference to Exhibit 10.1 to Tallgrass Energy, LP’s Quarterly Report on Form 10-Q filed on
August 2, 2018).
Tallgrass MLP GP, LLC Long-Term Incentive Plan (as amended and restated effective August 2, 2018)
(incorporated by reference to Exhibit 10.2 to Tallgrass Energy, LP’s Quarterly Report on Form 10-Q filed on
August 2, 2018).
191
10.15
10.16
21.1*
23.1*
23.2*
31.1*
31.2*
32.1*
32.2*
Form of Equity Participation Share Agreement (incorporated by reference to Exhibit 10.3 to Tallgrass Energy,
LP’s Quarterly Report on Form 10-Q filed on August 2, 2018).
Amendment No. 1 to Second Amended and Restated Credit Agreement, dated July 26, 2018, (incorporated by
reference to Exhibit 10.1 to Tallgrass Energy, LP's Current Report on Form 8-K filed on July 27, 2018).
List of Subsidiaries of Tallgrass Energy, LP.
Consent of PricewaterhouseCoopers LLP on Consolidated Financial Statements of Tallgrass Energy, LP and
the effectiveness of Tallgrass Energy, LP's internal control over financial reporting.
Consent of PricewaterhouseCoopers LLP on Financial Statements of Rockies Express Pipeline LLC.
Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr.
Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle.
Section 1350 Certification of David G. Dehaemers, Jr.
Section 1350 Certification of Gary J. Brauchle.
101.INS*
XBRL Instance Document.
101.SCH*
XBRL Taxonomy Extension Schema Document.
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase Document.
* - filed herewith
† - Management contract of compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to
Item 15(b).
192
Item 16. Form 10-K Summary
Not applicable.
193
Pursuant to the requirements of Section 13 or 15(d) 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.
SIGNATURES
Tallgrass Energy, LP
By: Tallgrass Energy GP, LLC, its general partner
By:
/s/ David G. Dehaemers, Jr.
David G. Dehaemers, Jr.
President and Chief Executive Officer of Tallgrass
Energy GP, LLC (the general partner of Tallgrass
Energy, LP)
Date: February 8, 2019
194
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the dates indicated.
Name
Title
Date
/s/ David G. Dehaemers, Jr.
David G. Dehaemers, Jr.
Director, President and Chief Executive Officer
February 8, 2019
(Principal Executive Officer)
/s/ Gary J. Brauchle
Gary J. Brauchle
/s/ Gary D. Watkins
Gary D. Watkins
/s/ Frank J. Loverro
Frank J. Loverro
/s/ Stanley de J. Osborne
Stanley de J. Osborne
/s/ Jeffrey A. Ball
Jeffrey A. Ball
/s/ John T. Raymond
John T. Raymond
/s/ William R. Moler
William R. Moler
/s/ Thomas A. Gerke
Thomas A. Gerke
/s/ Roy N. Cook
Roy N. Cook
/s/ Terrance D. Towner
Terrance D. Towner
Executive Vice President and Chief Financial Officer
February 8, 2019
(Principal Financial Officer)
Vice President and Chief Accounting Officer
February 8, 2019
(Principal Accounting Officer)
February 8, 2019
February 8, 2019
February 8, 2019
February 8, 2019
February 8, 2019
February 8, 2019
February 8, 2019
February 8, 2019
Director
Director
Director
Director
Director
Director
Director
Director
195
Tallgrass Energy, LP
Subsidiaries
Exhibit 21.1
Jurisdiction of Organization
Company
Alpha Reclaim Technology, LLC.......................................................................................... Texas
BNN Colorado Water, Inc. .................................................................................................... Colorado
BNN Colorado Water, LLC................................................................................................... Delaware
BNN Great Plains, LLC ........................................................................................................ Delaware
BNN North Dakota, LLC...................................................................................................... Delaware
BNN Recycle, LLC............................................................................................................... Delaware
BNN Redtail, LLC ................................................................................................................ Delaware
BNN South Texas, LLC ........................................................................................................ Delaware
BNN Water Solutions, LLC .................................................................................................. Delaware
BNN West Texas, LLC.......................................................................................................... Delaware
BNN Western, LLC............................................................................................................... Delaware
Cheyenne Connector Pipeline, Inc........................................................................................ Colorado
Cheyenne Connector, LLC.................................................................................................... Delaware
Deeprock Development, LLC ............................................................................................... Delaware
Pawnee Terminal, LLC ......................................................................................................... Delaware
Plaquemines Liquids Terminal, LLC .................................................................................... Delaware
Seahorse Pipeline, LLC......................................................................................................... Delaware
Stanchion Energy, LLC......................................................................................................... Delaware
Tallgrass Cheyenne Connector Holdings, LLC .................................................................... Delaware
Tallgrass Colorado Pipeline, Inc. .......................................................................................... Colorado
Tallgrass Energy Finance Corp. ............................................................................................ Delaware
Tallgrass Energy Investments, LLC ...................................................................................... Delaware
Tallgrass Energy Partners, LP ............................................................................................... Delaware
Tallgrass Equity Investments, LLC....................................................................................... Delaware
Tallgrass Equity, LLC ........................................................................................................... Delaware
Tallgrass Interstate Gas Transmission, LLC ......................................................................... Colorado
Tallgrass PRG Holdings, LLC .............................................................................................. Delaware
Tallgrass PRG Operator, LLC............................................................................................... Delaware
Tallgrass Management, LLC................................................................................................. Delaware
Tallgrass Midstream Gathering, LLC ................................................................................... Colorado
Tallgrass Midstream, LLC .................................................................................................... Delaware
Tallgrass MLP GP, LLC........................................................................................................ Delaware
Tallgrass MLP Operations, LLC ........................................................................................... Delaware
Tallgrass NatGas Operator, LLC........................................................................................... Delaware
Tallgrass PLT Operator, LLC ................................................................................................ Delaware
Tallgrass Pony Express Pipeline, LLC.................................................................................. Delaware
Tallgrass Sterling Terminal, LLC.......................................................................................... Delaware
Tallgrass Terminals, LLC...................................................................................................... Delaware
TEP REX Holdings, LLC...................................................................................................... Delaware
Trailblazer Pipeline Company LLC ...................................................................................... Delaware
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (No. 333-225382), S-3/ASR
(No. 333-226086), S-8 (Nos. 333-226537 and 333-205717) of Tallgrass Energy, LP, of our report dated February 8, 2019,
relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form
10 K.
Exhibit 23.1
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 8, 2019
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (No. 333-225382), S-3/ASR
(No. 333-226086), S-8 (Nos. 333-226537 and 333-205717) of Tallgrass Energy, LP, of our report dated February 8, 2019,
relating to the financial statements of Rockies Express Pipeline LLC, which appears in this Form 10 K of Tallgrass Energy, LP.
Exhibit 23.2
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 8, 2019
Certification by Chief Executive Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,
as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
I, David G. Dehaemers, Jr., certify that:
Exhibit 31.1
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K of Tallgrass Energy, LP;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
By:
/s/ David G. Dehaemers, Jr.
David G. Dehaemers, Jr.
President and Chief Executive Officer of Tallgrass
Energy GP, LLC (the general partner of Tallgrass
Energy, LP)
Date: February 8, 2019
Certification by Chief Financial Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,
as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
I, Gary J. Brauchle, certify that:
Exhibit 31.2
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K of Tallgrass Energy, LP;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
By:
/s/ Gary J. Brauchle
Gary J. Brauchle
Executive Vice President and Chief Financial Officer of
Tallgrass Energy GP, LLC (the general partner of
Tallgrass Energy, LP)
Date: February 8, 2019
Certification Pursuant to
18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 32.1
In connection with the annual report of Tallgrass Energy, LP (the “Partnership”) on Form 10-K for the year ended
December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David G.
Dehaemers, Jr., President and Chief Executive Officer of Tallgrass Energy GP, LLC, the general partner of the Partnership,
certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section
906”), that, to my knowledge:
1.
2.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results
of operations of the Partnership.
By:
/s/ David G. Dehaemers, Jr.
David G. Dehaemers, Jr.
President and Chief Executive Officer of Tallgrass Energy
GP, LLC (the general partner of Tallgrass Energy, LP)
Date: February 8, 2019
A signed original of this written statement required by Section 906 has been provided to the Partnership and will be
retained and furnished to the Securities and Exchange Commission or its staff upon request.
Certification Pursuant to
18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 32.2
In connection with the annual report of Tallgrass Energy, LP (the “Partnership”) on Form 10-K for the year ended
December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gary J.
Brauchle, Executive Vice President and Chief Financial Officer of Tallgrass Energy GP, LLC, the general partner of the
Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(“Section 906”), that, to my knowledge:
1.
2.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results
of operations of the Partnership.
By:
/s/ Gary J. Brauchle
Gary J. Brauchle
Executive Vice President and Chief Financial Officer
and of Tallgrass Energy GP, LLC (the general partner of
Tallgrass Energy, LP)
Date: February 8, 2019
A signed original of this written statement required by Section 906 has been provided to the Partnership and will be
retained and furnished to the Securities and Exchange Commission or its staff upon request.
L AST PAGE OF 10 -K
CORPOR ATE INFORMATION
BOARD OF DIRECTORS
PUBLIC HEADQUARTERS
David G. Dehaemers Jr.
William R. Moler
Jeffrey A. Ball
Roy N. Cook
Thomas A. Gerke
Frank J. Loverro
Stanley de J. Osborne
John T. Raymond
Terrance D. Towner
EXECUTIVE MANAGEMENT
David G. Dehaemers Jr.
President and Chief Executive Officer
William R. Moler
Executive Vice President &
Chief Operating Officer
Gary J. Brauchle
Executive Vice President &
Chief Financial Officer
Christopher R. Jones
Executive Vice President,
General Counsel & Secretary
4200 W. 115th Street
Suite 350
Leawood, KS 66211
(913) 928-6060
TALLGRASS ENERGY
4200 W. 115th Street
Suite 350
Leawood, KS 66211
(913) 928-6060
370 Van Gordon Street
Lakewood, CO 80228
(303) 763-2950
INVESTOR RELATIONS
(913) 928-6012
investor.relations@tallgrassenergy.com
MEDIA RELATIONS
(913) 928-6014
media.relations@tallgrassenergylp.com
TRANSFER AGENT
American Stock Transfer and Trust
TICKER SYMBOL
NYSE: TGE
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4200 W. 115th Street, Suite 350, Leawood, KS 66211 • (913) 928-6060 • www.tallgrassenergy.com