ENERGY PARTNERS
2 0 1 6 A N N U A L R E P O R T
About Tallgrass Energy Par tners, LP
Tallgrass Energy Partners, LP (NYSE: TEP) is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop
midstream energy assets in North America. TEP’s operations are located in and provide services to certain key United States hydrocarbon basins,
including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford,
Bakken, Marcellus, and Utica shale formations. TEP currently provides crude oil transportation to customers in Wyoming, Colorado, and the surrounding
regions through the Pony Express System, a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma, which
includes a lateral in Northeast Colorado commencing in Weld County, Colorado, and interconnecting with the pipeline just east of Sterling, Colorado.
TEP also provides crude oil storage and terminalling services, including crude oil terminals near Sterling, Colorado and in Weld County, Colorado, and a
20 percent interest in Deeprock Development, LLC, which owns a crude oil terminal in Cushing, Oklahoma. TEP provides natural gas transportation and
storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through its 25 percent interest in the
Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio, the
Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri,
Nebraska and Wyoming, and the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming
border to Beatrice, Nebraska. TEP provides services for customers in Wyoming at the Casper and Douglas natural gas processing facilities and the West
Frenchie Draw natural gas treating facility, and NGL transportation services in Northeast Colorado and Wyoming. TEP also engages in water business
services, including freshwater transportation and produced water gathering and disposal, in Colorado and Texas through BNN Water Solutions.
TEP Distributions
per Unit
$0.8150
A G R
5 % C
3
$0.2875
Q2 '13 Q3 '13 Q4 '13 Q1 '14 Q2 '14 Q3 '14 Q4 '14 Q1 '15 Q2 '15 Q3 '15 Q4 '15 Q1 '16 Q2 '16 Q3 '16
Q4 '16
Adjusted EBITDA
(in millions)
$423.5
$252.3
$74.6
$109.9
2013
2014
2015
2016
TALLGRASS SYSTEM MAP
TEP Gross
Margin Profile
2% 1%
97%
Firm Fee
Volumetric Fee
Commodity
Tallgrass Energy Partners
Rockies Express Pipeline
Pony Express System
Tallgrass Development
Rockies Express Pipeline
Lease of Overthrust Pipeline Capacity
Oil Terminal
Lease of Overthrust Pipeline Capacity
Tallgrass Interstate Gas Transmission
NE Colorado Water & NGL Infrastructure
Pony Express System
Trailblazer Pipeline
Tallgrass Midstream
TALLGRASS ENERGY PARTNERS, LP
1
Letter to TEP
Unitholders
CHAPTER 4/YEAR 4—A TRADITIONAL MIDSTREAM MLP
Once again, we turn the page on another year at Tallgrass. And
what a year! 2016 was a year of extremes, the kind of year in the energy
space—and the MLP space in particular—that we seem to have every
five to seven years. We saw extremes in energy commodity pricing,
particularly to the downside, that eventually rippled through the entire
energy space—upstream, midstream and downstream.
Even though 2016 was a rough year for much of the industry,
Tallgrass never missed a beat and consistently executed our business
strategy. We continued to increase distributions and deliver the kind of
value our unitholders have come to expect from us. Before I dive into
our 2016 performance, I’d like to remind everyone who we are.
Tallgrass Energy Partners, LP (TEP) is a traditional midstream
operator providing long-term sustainable distribution growth to inves-
tors fueled by strong customer relationships, a significant geographic
footprint, solid growth potential and a flexible capital structure.
Again in 2016, I believe we lived up to that reputation.
It occurs to me as I write this fourth annual letter to my fellow uni-
tholders that my message may seem repetitive. There’s a reason for
that: many of our messages at Tallgrass are worth repeating. We have
a track record for doing what we say we’re going to do. I’ll leave it to
you to decide if you believe our actions of the past and our facts of the
present will translate into our vision and performance of the future
for Tallgrass.
MORE ON 2016—PERFORMANCE AND PRESENT VALUE
In February 2016, TEP units hit a 52-week low closing price of
$25.87—largely due to us being painted with the same brush as our
upstream counterparts. In January 2017, we pushed back up to about
the $50.00 per unit mark. On Feb. 12, 2016, TEP paid an annualized dis-
tribution of $2.56, which at the time meant that TEP yielded close to 10
percent. Even though our unit price has recovered significantly, I
believe TEP remains undervalued.
On Feb. 14, 2017, TEP paid an annualized distribution of $3.26 per
unit ($0.815 quarterly). At a current TEP price of ~$49.00, that equates
to a yield of nearly 7 percent. Let me lay out my case for why I believe
TEP is still undervalued.
1. From February 2016 to February 2017, we raised our distribution by
27.3 percent—a top 5 annualized growth rate in the MLP space.
2. We have told the market we believe we will have 20 percent annual-
ized distribution growth in 2017.
3. At ~7 percent, TEP’s current yield is above both the average and
median yield of all MLPs. Our view is that on a comparative basis,
TEP is significantly better than average (the mean) and deserving of a
much lower yield than the middle value (the median).
4. For 2016 we covered our distribution by greater than 1.25x, generating
almost $90 million in excess of cash distributed to our unitholders.
Since going public in May 2013, we have generated more than $130
million of excess distribution coverage that we have used to repay
debt and reinvest in our business. In 2017 we believe we will cover our
distributions by ~1.40x, generating almost $175 million in excess of
anticipated distributions, while still growing our distributions at a 20
percent annualized rate.
5. TEP has an investment grade balance sheet by almost any measure
and maintains a best-in-class Debt to EBITDA ratio of approximately
three times.
2
6. In 2016, as in prior years, we have done what we said we were going
to do. We intend to keep on doing the same.
2016—ANOTHER YEAR OF EXECUTION—A YEAR OF ~$2.0+
BILLION IN ACQUISITIONS AND EXPANSIONS
Pony Express—On Jan. 1, 2016, we bought our final interest
in the Pony Express crude oil pipeline for $743.6 million, bringing our
total ownership to 98 percent. At the time, the Seller—TDEV—took back
6.518 million TEP common units valued at $41.21 a share. In addition,
TEP retained the right to repurchase (or “call”) the shares back at a
price of $42.50. We are pleased to report that from that time, TEP was
able to raise equity at an average price of $47.25 and buy back all 6.518
million units—netting TEP a retained difference of approximately $31
million, thus reducing the transaction price by that much as well as
reducing the multiple paid down to an 8.7x multiple of cash flow. To
our knowledge, this is the first time a call strategy has been used
when issuing equity to a related party and further shows on a histori-
cal basis TEP’s creativity and TDEV’s continuing commitment to the
ongoing success of TEP.
Rockies Express Pipeline (REX)—In May 2016, we purchased a
25 percent equity interest in REX from a subsidiary of Sempra U.S.
Gas and Power for $436 million. The overall enterprise value of the
transaction exceeded $1.0 billion. This was TEP’s first acquisition of
an interest in REX. Our private affiliate, TDEV, still owns 50 percent of
REX and we expect sometime over the next two years to acquire
TDEV’s 50 percent interest in REX, continuing our growth at TEP.
At REX, we constructed our Zone 3 Capacity Enhancement proj-
ect. This project added an additional 0.8 Bcf/day of east-to-west
capacity in Zone 3 by adding additional horsepower at three new com-
pressor stations and enhancing two existing stations. This project
was placed in full service in early January 2017. We and our partners
at REX spent approximately $525 million on this project, which is fully
contracted for 15 years.
We also restructured REX’s largest legacy contract (0.5 Bcf/d)
with Encana. The contract was extended to 2024, giving Encana short-
term rate relief in exchange for a longer-term contract with REX. It
was NPV positive at a nice discount rate and was a win/win for both
REX and its customer.
REX reached an agreement to settle its $303 million breach of
contract claim against Ultra Resources, a legacy customer. REX will
receive $150 million in cash during 2017 and a new seven-year contract
for 0.2 Bcf/d commencing in 2019 for ~$27 million per year. This settle-
ment essentially keeps us whole on our original contract, takes capac-
ity out of the marketplace and allows us to have a healthy, solvent
customer for the long term at REX.
With two contracts that extend beyond 2019, we now have nearly
40 percent (0.7 Bcf/d) of the west-end volumes contracted at average
rates of $0.67 with a weighted average life of more than five years
(post-2019). Combined with the fully contracted zone 3 volumes of 2.6
Bcf/d, we have now re-contracted greater than 85 percent of REX’s
original cashflow on a long-term basis. With more than two and one
half years remaining before the rest of the west-end contracts expire,
we are confident in our ability to secure additional transportation vol-
umes on REX, whether they come from our current customers or
potential new customers.
TIGT—At TIGT, we successfully settled a rate case with agreement
from our customers and approval from the FERC on all issues includ-
ing modernizing our tariff, establishing new reservation rates, imple-
menting fuel and power cost trackers, and simplifying our zoned rate
structure from five zones to two, all resulting in a $13 million increase
in annual revenues.
Senior Notes Offering—On Sept. 1, 2016, we closed our inaugural
offering of $400 million of senior unsecured notes at one of the lowest
historical initial yields (5.50 percent) in the high yield energy space.
This offering added another arrow to our quiver and created additional
available capacity on our revolving credit facility which ultimately
gives us more flexibility for future dropdowns and potential M&A. We
expect to be an investment grade debt issuer in the near future.
2017—MUCH TO LOOK FORWARD TO
Moving into 2017, we believe things are looking up with respect
to the energy industry as a whole. From what we see and hear, our
customers, shippers, drillers and end-users are more positive and
looking optimistically toward the future.
On Jan. 3, 2017, TEP purchased Tallgrass Terminals—inclusive of
two organic development projects—and the operator of REX from
TDEV for $140 million. These two businesses bring about $17 million
of cash flow to the table for TEP.
The following are a few of the things we have to look forward to in
2017 and beyond:
• Pony Express—
o We are working to add additional refineries to create additional
demand pull on the system.
o We are working on new joint tariffs to allow our shipper customers to
ship competitively to the Gulf Coast should they choose to do so.
o We expect to have more capacity utilized (up to 100k+/bpd) on top of
our existing contracted capacity as drilling resumes and oil prices
recover to healthier levels.
o We remind everyone that we are the lowest-cost alternative to
Cushing from the Bakken, the DJ/Niobrara and the Powder River
basins.
o We expect to add a lighter stream of condensate to our mix of prod-
ucts being shipped.
• REX—
o We believe our recent Zone 3 Capacity Enhancement project may
allow for even more volumes to become available to our shippers
due to its well-engineered design. Stay tuned.
o Look for us to start modifying REX zones 1 and 2 to allow them to
ship bi-directionally post-2019, along with zone 3—this will allow for
many more revenue possibilities.
o Although still more than two and one half years away, look for our
re-contracting in zones 1 and 2 to take shape with a newly modified
system.
o Finally, if the market warrants it—and we believe it does—look for us
to optimize looping opportunities on REX in zone 3 over the next five
years. The seven interconnects we have with others in zone 3 are
well in excess of zone 3’s current capacity of 2.6 Bcf/day.
o We are seeing many natural gas electric generation plants being
co-located on our systems—TIGT, Trailblazer and REX—and we
believe we will get our fair share of these demand-pull load plants in
the future. In fact, our first large plant hook-up is underway.
• NGL and Water Businesses
o NGL pricing was destroyed along with oil prices in late 2015 and
2016. Now that oil is recovering, we’re optimistic that our processing
business will be resilient as well. We are capable of more ethane
recovery than anyone in the Powder River Basin with our cryogenic
plant capabilities.
o Organic growth in our water business will continue. We will continue
to look for opportunities to acquire systems that complement our
existing assets, and the strong relationships we have with our cus-
tomers will allow us to organically grow into the foreseeable future.
• M&A—Emphasis on Acquisitions
o As of right now, we have over $500 million of dry powder available to
us for acquisitions. We are conservatively levered at ~3.0x debt to
EBITDA at year-end 2016. We have no current need to access the
equity markets. As always, this could change for the right opportunity.
o Our management team has a rich history of successfully completing
deals that benefit Tallgrass. In fact, we have completed more than
$6.5 billion of acquisitions and growth projects over the last four and
one half years. As always, we will be prudent in the acquisitions we
pursue, and I’m confident—knowing my team—that we will con-
tinue our success in this area too.
WE HAVE ONLY JUST BEGUN
At Tallgrass, we play long ball. We’re steady in the face of short-
term movements in both the stock and commodities markets. We have
our eye on the horizon, which means we’re constantly looking to create
long-term value for our unitholders. We maintain an unwavering focus
on the things we can control, and we manage our business for long-
term success. Going forward, Tallgrass has the right assets, the right
contracts with the right counterparties, the right balance sheet and
ample liquidity to move our company forward and to meet our objec-
tives and your expectations.
Once again, in 2016 Tallgrass Energy delivered. I hope that each
owner of TEP will join me in sincerely thanking the Tallgrass employ-
ees for their continued outstanding effort. In addition to our employ-
ees, we again thank our supporters, our unitholders, our customers
and our suppliers. All of you are our partners too. You all make our
future possible, and you make our future bright.
On this date in 2017, we at TEP renew our commitment to you, our
partners, to putting forth an outstanding effort to steward our
business; to grow that business; to expand our services; and most
importantly, to translate all of that into outstanding and sustainable
investment returns.
Sincere regards,
• TIGT and Trailblazer
o We remind everyone that Trailblazer remains the least expensive
route out of the Rockies; this is a clear competitive advantage.
David G. Dehaemers, Jr.
President and Chief Executive Officer
Summary Financial Information
(in thousands, except coverage and per unit data)
Net income attributable to partners
Add:
Interest expense, net of noncontrolling interest
Depreciation and amortization expense, net of noncontrolling interest
Distributions from unconsolidated investment
Non-cash loss (gain) related to derivative instruments, net of noncontrolling interest
Non-cash compensation expense
Non-cash loss from disposal of asset
Loss on extinguishment of debt
Less:
Equity in earnings of unconsolidated investment
Non-cash loss allocated to noncontrolling interest
Gain on remeasurement of unconsolidated investment
Adjusted EBITDA
Add:
Deficiency payments received, net
Pony Express preferred distributions in excess of distributable cash flow
attributable to Pony Express
Less:
Cash interest cost
Maintenance capital expenditures, net
Distributions to noncontrolling interest in excess of earnings
Cash flow attributable to predecessor operations
Distributable cash flow (DCF)
Less:
Distributions
Amounts in excess of distributions
Distribution coverage
2016
2015
2014
2013
$ 263,529
$ 160,546
$ 70,681
$ 14,179
40,688
85,971
75,900
1,547
5,780
1,849
—
(51,780)
—
—
15,517
75,529
—
—
5,103
4,795
226
—
(9,377)
—
7,648
45,389
1,464
(184)
5,136
—
—
(717)
(10,151)
(9,388)
11,141
29,549
—
386
1,798
—
17,526
—
—
—
$ 423,484
$ 252,339
$109,878
$ 74,579
$ 33,496
$ 16,511
$
5,378
$ —
—
—
5,429
—
(37,110)
(11,323)
—
—
(13,746)
(12,123)
(22,479)
—
(6,266)
(9,913)
(5,361)
(3,086)
(5,910)(a)
(8.773)
—
—
408,547
220,502
96,059
59,896(a)
(321,953)
(192,580)
(83,329)
(49,140)(a)
$ 86,594
$ 27,922
$ 12,730
$ 10,756(a)
1.27x
1.14x
1.15x
1.22x(a)
(a) Indicated amounts presented for the twelve months ended December 31, 2013 are on a pro forma basis, which assumes that our initial public offering and related formation transactions, including bor-
rowings under our revolving credit facility, had closed on January 1, 2013. No cash distributions were paid with respect to the first quarter of 2013, and a prorated distribution of available cash was paid
for the period from the closing of the IPO (May 17, 2013) through the end of the second quarter. Pro forma distributions were calculated using the minimum quarterly distribution for the first two quarters
of 2013 and the increased distribution for the third and fourth quarters. Actual cash distributions for the twelve month period ending December 31, 2013, were $0.7547/unit. Pro forma interest expense
(inclusive of commitment fees) for the twelve months ended December 31, 2013, was calculated by multiplying the actual cash interest cost for Q3 by three and adding the actual cash interest cost for
Q4. Actual cash interest cost for the twelve month period ended December 31, 2013, was $3,555,000.
Management believes the pro forma presentation of distributable cash flow, distribution coverage and net income per limited partner unit provides investors with useful information to compare our historical
financial results to future periods. These pro forma financial measures are presented for illustrative purposes only and are not necessarily indicative of the operating results or the financial position that
would have been achieved had the initial public offering and related formation transactions been consummated on January 1, 2013 or of the results that may be obtained in the future.
TOTAL UNITHOLDER RETURN
Tallgrass Energy Partners, LP
$300
250
200
150
100
50
4
5/13/13 6/28/13 9/30/13 12/31/13 3/31/14 6/30/14 9/30/14 12/31/14 3/31/15 6/30/15 9/30/15 12/31/15 3/31/16 6/30/16 9/30/16 12/31/16
Tallgrass Energy Partners, LP (TEP)
NYSE Composite Index (NYATR)
Alerian MLP Index (AMZX)
*For the purpose of distributions, funds are assumed to be reinvested in shares of the company at the closing price on the ex-dividend date.
FORM 10-K
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, 2016
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-35917
Tallgrass Energy Partners, LP
(Exact name of registrant as specified in its charter)
Delaware
(State or other Jurisdiction of Incorporation or Organization)
46-1972941
(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
Common Units 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 and posted on its corporate Web site, if any, every Interactive Data File
required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such
shorter period that the registrant was required to submit and post such files). Yes
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, or a smaller reporting
company. See the definitions of "large accelerated filer", "accelerated filer", and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
(Check one):
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company
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 30, 2016, the last business day of the
Registrant's most recently completed second fiscal quarter (based on the closing sale price of $46.02 of the Registrant's Common Units, as reported by
the New York Stock Exchange on such date) was approximately $1,942.7 million. On February 15, 2017, the Registrant had 72,139,038 Common
Units and 834,391 General Partner Units outstanding.
TALLGRASS ENERGY PARTNERS, 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
18
56
56
57
57
58
58
60
62
84
86
87
88
89
91
93
132
132
132
133
133
138
149
151
155
156
156
176
178
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: Federal Energy Regulatory Commission.
Firm fee contracts: contracts or other arrangements, including tariff provisions, that generally obligate our customers to pay a
fixed recurring charge to reserve an agreed upon amount of capacity and/or deliverability on our assets, regardless if the
contracted capacity is actually used by the customer. Such contracts are also commonly known as "take-or-pay" contracts.
Firm services: services pursuant to which customers receive firm assurances regarding the availability of capacity and/or
deliverability of natural gas, crude oil or other hydrocarbons or water on our assets up to a contracted amount.
Fractionation: the process by which NGLs are further separated into individual, typically more valuable components including
ethane, propane, butane, isobutane and natural gasoline.
GAAP: generally accepted accounting principles in the United States of America.
GHGs: greenhouse gases.
Header system: networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large
diameter high pressure long-haul transportation pipelines.
Interruptible services: services pursuant to which customers receive limited, or no, assurances regarding the availability of
capacity and deliverability in our assets.
Keep Whole Processing Contracts: natural gas processing contracts in which we are required to replace the Btu content of the
NGLs extracted from inlet wet gas processed with purchased dry natural gas.
Line fill: the volume of oil, in barrels, in the pipeline from the origin to the destination.
Liquefied natural gas or LNG: natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by
ship. The cooling process reduces the volume of natural gas by 600 times.
Local distribution company or LDC: LDCs are involved in the delivery of natural gas to end users within a specific
geographic area.
Long-term: with respect to any contract, a contract with an initial duration greater than one year.
MMBtu: one million British Thermal Units.
Mcf: one thousand cubic feet.
MDth: one thousand dekatherms.
MMcf: one million cubic feet.
Natural gas liquids or NGLs: those hydrocarbons in natural gas that are separated from the natural gas as liquids through the
process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally, such
liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and
liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and
isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).
Natural Gas Processing: the separation of natural gas into pipeline-quality natural gas and a mixed NGL stream.
Non-contract barrels (or walk-up barrels): barrels of crude oil that our customers ship based solely on availability of capacity
and deliverability with no assurance of future capacity.
No-notice service: those services pursuant to which customers receive the right to transport or store natural gas on assets
outside of the daily nomination cycle without incurring penalties.
NYMEX: New York Mercantile Exchange.
Park and loan services: those services pursuant to which customers receive the right to store natural gas in (park), or borrow
gas from (loan), our facilities.
Percent of Proceeds Processing Contracts: natural gas processing contracts in which we process our customer's natural gas,
sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. Some percent of
proceeds contracts may also require our customers to pay a monthly reservation fee for processing capacity.
PHMSA: the United States Department of Transportation's Pipeline and Hazardous Materials Safety Administration.
Play: a proven geological formation that contains commercial amounts of hydrocarbons.
Produced water: all water removed from a well as a byproduct of the production of hydrocarbons and water removed from a
well in connection with operations being conducted on the well, including naturally occurring water in the recovery formation,
flow back water recovered during completion and fracturing operations and water entering the recovery formation through
water flooding techniques.
Receipt point: the point where a product is received by or into a gathering system, processing facility, or transportation
pipeline.
Reservoir: a porous and permeable underground formation containing an individual and separate natural accumulation of
producible hydrocarbons (such as crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is
characterized by a single natural pressure system.
Residue gas: the natural gas remaining after being processed or treated.
Shale gas: natural gas produced from organic (black) shale formations.
Tailgate: the point at which processed natural gas and NGLs leave a processing facility for transportation to end-user markets.
TBtu: one trillion British Thermal Units.
Tcf: one trillion cubic feet.
Throughput: the volume of products, such as crude oil, natural gas or water, transported or passing through a pipeline, plant,
terminal or other facility during a particular period.
Uncommitted shippers (or walk-up shippers): customers that have not signed long-term shipper contracts and have rights
under the FERC tariff as to rates and capacity allocation that are different than long-term committed shippers.
Volumetric fee contracts: contracts or other arrangements, including tariff provisions, that generally obligate a customer to pay
fees based upon the extent to which such customer utilizes our assets for midstream energy services. Unlike firm fee contracts,
under volumetric fee contracts our customers are not generally required to pay a charge to reserve an agreed upon amount of
capacity and/or deliverability.
Wellhead: the equipment at the surface of a well that is used to control the well's pressure; also, the point at which the
hydrocarbons and water exit the ground.
Working gas: the volume of gas in the storage reservoir that is in addition to the cushion or base gas. It may or may not be
completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be
used more than once during any season.
Working gas storage capacity: the maximum volume of natural gas that can be cost-effectively injected into a storage facility
and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes base gas and
non-cycling working gas.
X/d: the applicable measurement metric per day. For example, MMcf/d means one million cubic feet per day.
PART I
As used in this Annual Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEP" and
similar terms refer to Tallgrass Energy Partners, LP, together with its consolidated subsidiaries. The terms our "general
partner" or "TEP GP" refer to Tallgrass MLP 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 and Tallgrass Development's infrastructure programs, revenue projections, capital
expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks
or uncertainties. Consequently, no forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking
statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However,
when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements
in this 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 complete and integrate acquisitions from Tallgrass Development or from third parties, including our
acquisition of a 100% membership interest in Tallgrass NatGas Operator, LLC and Tallgrass Terminals, LLC that was
completed in January 2017, and our acquisition of a 25% membership interest in Rockies Express Pipeline LLC from
a unit of Sempra U.S. Gas and Power that was completed in May 2016;
the demand for our services, including crude oil transportation, storage and terminalling services, natural gas
transportation, storage and processing services and water business services;
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 third-party operators, processors and transporters;
our ability to complete internal growth projects on time and on budget;
the price and availability of debt and equity financing;
the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil,
natural gas, natural gas liquids, and other hydrocarbons;
the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the
price of alternative and competing fuels;
competition from the same and alternative energy sources;
energy efficiency and technology trends;
1
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•
•
•
•
•
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operating hazards and other risks incidental to transporting, storing and terminalling crude oil, transporting, storing
and processing natural gas, and transporting, gathering and disposing of water produced in connection with
hydrocarbon exploration and production activities;
environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
interest rates;
labor relations;
changes in tax status;
the effects of future litigation; and
certain factors discussed elsewhere in this 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
We are a publicly traded, growth-oriented limited partnership formed in 2013 to own, operate, acquire and develop
midstream energy assets in North America. Our operations are located in and provide services to certain key United States
hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and
the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations. We intend to continue to leverage
our relationship with Tallgrass Development and utilize the significant experience of our management team to execute our
growth strategy of acquiring midstream assets from Tallgrass Development and third parties, increasing utilization of our
existing assets and expanding our systems through construction of additional assets. For more information, see "Tallgrass
Development" below.
Our reportable business segments are:
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•
•
Crude Oil Transportation & Logistics—the ownership and operation of a FERC-regulated crude oil pipeline system
and crude oil storage and terminalling facilities;
Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas
pipelines and integrated natural gas storage facilities; and
Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities,
the provision of water business services primarily to the oil and gas exploration and production industry, and the
transportation of NGLs.
Additional segment and financial information is contained in our segment results included in Item 7.—Management's
Discussion and Analysis of Financial Condition and Results of Operations and the notes to our consolidated financial
statements included in Item 8.—Financial Statements and Supplementary Data of this Annual Report.
2
Our Assets
The following map shows our primary assets, which consist of crude oil transportation, storage and terminalling assets,
natural gas transportation, storage and processing assets and water business services assets, excluding our West Texas water
business services assets. Each of these assets are described in more detail below.
Crude Oil Transportation & Logistics Segment
Pony Express. We currently provide crude oil transportation to customers in Wyoming, Colorado, and the surrounding
regions through our 98% membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express"). Pony Express owns
an approximately 764-mile crude oil pipeline commencing in Guernsey, Wyoming, and terminating in Cushing, Oklahoma,
with delivery points at the Ponca City Refinery and in Cushing, Oklahoma, and a lateral in Northeast Colorado that commences
in Weld County, Colorado and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We
believe the Pony Express System is positioned as a low-cost, competitive "base load" 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 as of December 31, 2016 and for the
periods indicated:
Approximate Design
Capacity
(bbls/d) (1)
Approximate
Contractible
Capacity Under
Contract (1)(2)
Weighted Average
Remaining Firm
Contract Life (3)
Approximate Average Daily Throughput
(bbls/d)
Year Ended December 31,
2016
2015
320,000
100%
3 years
285,507
236,256 (4)
(1) Excludes additional capacity related to the Pony Express System's ability to inject drag reducing agent, which is an
additive that increases pipeline flow efficiency.
(2) We are required to make no less than 10% of design capacity available for non-contract, or "walk-up", shippers.
Approximately 100% 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.
3
(4) Approximate average daily throughput for the three months ended December 31, 2015 was 288,362 bbls/d.
Approximate average daily throughput for the year ended December 31, 2015 reflects the volumetric ramp-up during
the year due to the construction and expansion efforts of the Pony Express lateral in Northeast Colorado and third-
party pipelines with which Pony Express shares joint tariffs.
Terminals. We provide crude oil storage and terminalling services through our 100% membership interest in Tallgrass
Terminals, LLC ("Terminals"), which we acquired from Tallgrass Development effective January 1, 2017. 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") and
the crude oil terminal in Weld County, Colorado with four truck unloading skids capable of receiving up to 16,000 bbls per day
(the "Buckingham Terminal"). Terminals also owns a 20% interest in Deeprock Development, LLC ("Deeprock Development"),
which owns a crude oil terminal in Cushing, Oklahoma with approximately 2.3 million bbls of storage capacity (the "Cushing
Terminal"). In addition, Terminals owns projects currently under development to provide additional storage capacity and other
potential service opportunities, including approximately 550 acres in Cushing, Oklahoma and approximately 250 acres in
Guernsey, Wyoming.
Natural Gas Transportation & Logistics Segment
Rockies Express Pipeline. We own a 25% membership interest in Rockies Express Pipeline LLC ("Rockies Express"),
which 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:
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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, 2016, approximately 98% of Rockies Express' revenues were generated under firm fee
contracts.
The following tables provide information regarding the Rockies Express Pipeline as of December 31, 2016 and for the
years ended December 31, 2016, 2015, and 2014:
Approximate average daily deliveries (Bcf/d) (1) ..................
3.2
2.5
1.7
2016
Year Ended December 31,
2015
2014
Approximate
Capacity
Total Firm
Contracted
Capacity (2)
Approximate %
of Capacity
Subscribed
under Firm
Contracts
West-to-east..........................................
East-to-west..........................................
2.0 Bcf/d
2.6 Bcf/d (4)
1.5 Bcf/d
2.6 Bcf/d
75%
100%
Weighted
Average
Remaining Firm
Contract Life (3)
4 years
16 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, 2016. West-to-east firm
contracted capacity excludes the 0.2 Bcf/d to be contracted with Ultra as part of the settlement agreement discussed in
"Recent Developments" in Item 7.—Management's Discussion and Analysis of Financial Condition and Results of
Operations.
(3) Weighted by contracted capacity as of December 31, 2016. Weighted average remaining firm contract life of west-to-
east contracts excludes the 0.2 Bcf/d contract with Ultra beginning December 1, 2019 as discussed under "Recent
Developments" in Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations.
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 5 years.
4
(4) East-to-west capacity of 2.6 Bcf/d is inclusive of the Rockies Express Zone 3 Capacity Enhancement Project
completed in January 2017 that added an incremental 0.8 Bcf/d of east-to-west capacity within Zone 3.
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 4,655 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, 2016, approximately 88% 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 454 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, 2016, substantially all of Trailblazer Pipeline's
operationally available long-haul capacity was contracted under firm transportation contracts.
The following tables provide information regarding the TIGT System and Trailblazer Pipeline as of December 31, 2016
and for the years ended December 31, 2016, 2015, and 2014:
Approximate average daily deliveries (Bcf/d) ......................
1.1
1.1
1.0
2016
Year Ended December 31,
2015
2014
Approximate
Number of
Miles
Approximate
Capacity
Total Firm
Contracted
Capacity (1)
Approximate %
of Capacity
Subscribed
under Firm
Contracts
Transportation........
Storage...................
5,109
n/a
2.0 Bcf/d
15.974 Bcf (3)
1.6 Bcf/d
11 Bcf
79%
69%
Weighted
Average
Remaining Firm
Contract Life (2)
3 years
5 years
(1) Reflects total capacity reserved under long-term firm fee contracts, including backhaul service, as of December 31,
2016.
(2) Weighted by contracted capacity as of December 31, 2016.
(3) The FERC certificated working gas storage capacity.
NatGas. Effective January 1, 2017, we acquired 100% of the issued and outstanding membership interests in Tallgrass
NatGas Operator, LLC ("NatGas") from Tallgrass Development. NatGas is the operator of the Rockies Express Pipeline and
receives a fee from Rockies Express as compensation for its services.
Processing & Logistics Segment
Midstream Facilities. We own a 100% membership interest in Tallgrass Midstream, LLC ("TMID"), which owns and
operates natural gas processing plants in Casper and Douglas, Wyoming and a natural gas treating facility at West Frenchie
Draw, Wyoming (collectively, 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 with an approximate capacity of
19,500 barrels per day that transports NGLs from a processing plant in Northeast Colorado to an interconnect with Overland
Pass Pipeline, and TMID owns an NGL pipeline which was placed into service on January 1, 2017 that originates at our
Douglas facility and interconnects with ONEOK's Bakken NGL Pipeline. As of December 31, 2016, approximately 99% of our
reserved processing capacity was subject to firm or volumetric fee contracts, with the majority of fee revenue based on the
volumes actually processed. The remaining 1% was subject to commodity sensitive contracts. 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.
5
The table below sets forth certain information regarding the Midstream Facilities as of December 31, 2016 and for the
years ended December 31, 2016, 2015, and 2014:
Approximate
Plant Capacity
(MMcf/d) (1)
Approximate
Capacity Under
Contract
Weighted Average
Remaining
Contract Life (2)
Approximate Average Inlet Volumes (MMcf/d)
Year Ended December 31,
2015
2016
2014
190
79%
2 years
103
122
152
(1) 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.
(2) Based on the average annual reservation capacity for each such contract's remaining life.
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. Water Solutions is also the sole voting member and owns a 70%
membership interest in BNN West Texas, LLC ("West Texas"), which owns a produced water gathering and disposal system in
Reeves and Reagan County, Texas that is operated by Water Solutions. 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.
The table below sets forth certain information regarding the Water Solutions assets as of December 31, 2016 and for the
years ended December 31, 2016, 2015, and 2014:
Approximate
Capacity
Under
Contract
Approximate
Current
Design
Capacity
(bbls/d)
Remaining
Contract
Life
Approximate Average Volumes (bbls/d)
Year Ended December 31,
2015
2016
2014
Freshwater .............................
Gathering and Disposal .........
56%
63%
30,863
45,000 (1)
4 years
8 years
13,201
11,307
14,579
7,951
16,433
—
(1) Represents the combined daily disposal well injection capacity for the BNN Western, LLC ("Western") produced water
gathering and disposal system acquired in December 2015 and the West Texas produced water gathering and disposal
system which commenced operations by Water Solutions in March 2016.
Major Customers
For the year ended December 31, 2016, Continental Resources, Inc. ("Continental Resources") and Shell Trading (US)
Company ("Shell") accounted for approximately 16% and 13% of our revenues on a consolidated basis, respectively. The loss
of these customers could have a material adverse effect on our financial results.
Organizational Structure
Our general partner interest and all of our incentive distribution rights ("IDRs"), are held by our general partner, whose sole
member is Tallgrass Equity, LLC ("Tallgrass Equity"). Tallgrass Equity also directly owns 20 million TEP common units.
Tallgrass Energy GP, LP ("TEGP"), a Delaware limited partnership that completed its initial public offering in May 2015 and
has elected to be treated as a corporation for U.S. federal income tax purposes, owns a 36.94% membership interest in, and is
the managing member of, Tallgrass Equity. TEGP Management, LLC, a Delaware limited liability company ("TEGP
Management"), is TEGP's general partner. Tallgrass Energy Holdings, LLC, a Delaware limited liability company ("Tallgrass
Energy Holdings"), is the sole member of TEGP Management. Tallgrass Energy Holdings is also the general partner of
Tallgrass Development.
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, Tallgrass Energy Holdings
effectively controls our business and affairs through the exercise of its rights as the party that controls the sole member of our
general partner, including its right to appoint members to the board of directors of our general partner.
6
The chart below shows the structure of Tallgrass Energy Holdings and its subsidiaries as of February 15, 2017 in a
summary format.
7
Tallgrass Development
Tallgrass Development owns 5,619,218 of our common units, representing approximately 7.7% of our outstanding equity
at February 15, 2017. Tallgrass Development is controlled by its general partner, Tallgrass Energy Holdings, which also
indirectly controls our general partner. In connection with our initial public offering on May 17, 2013 (the "IPO"), Tallgrass
Development contributed to us 100% of the membership interests in TIGT and TMID. Since then, we have acquired the
following additional assets from Tallgrass Development: (1) in April 2014, a 100% membership interest in Trailblazer, (2) in
three separate transactions, the most recent of which was effective on January 1, 2016, a 98% membership interest in Pony
Express, and (3) in January 2017, a 100% membership interest in NatGas and Terminals. In addition, in May 2016 Tallgrass
Development 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 Tallgrass Development's wholly-
owned subsidiary and Sempra in March 2016. Tallgrass Development continues to own a 50% interest in Rockies Express and a
2% interest in Pony Express.
Pursuant to an Omnibus Agreement entered into upon the closing of our IPO, among us, TEP GP, Tallgrass Development
and Tallgrass Energy Holdings (the "TEP Omnibus Agreement"), Tallgrass Development granted us a right of first offer to
acquire certain assets held by Tallgrass Development at the time of our IPO, which we refer to as the Retained Assets, if
Tallgrass Development decides to sell such assets. The Retained Assets include Tallgrass Development's 50% interest in
Rockies Express and Tallgrass Development's remaining 2% noncontrolling interest in Pony Express. Tallgrass Development is
otherwise under no obligation to offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no
obligation to buy any assets from Tallgrass Development or pursue any such joint acquisitions. However, given the significant
economic interest in us held by Tallgrass Development and its affiliates, including Tallgrass Energy Holdings, we believe
Tallgrass Development will be incentivized to offer us the opportunity to acquire the Retained Assets.
Acquisitions
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 crude oil
transportation, storage and terminalling assets, natural gas transportation, storage and processing assets and water business
services 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 we completed in
2016 and in January 2017. See Note 4 – Acquisitions to our Consolidated Financial Statements in Item 8.—Financial
Statements and Supplementary Data for a full discussion regarding our acquisition activities.
•
•
•
•
Additional Membership Interest in Pony Express. Effective January 1, 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 Tallgrass Development, for total consideration of approximately $743.6
million. The transaction increased our aggregate membership interest in Pony Express to 98%.
Rockies Express Pipeline LLC. Effective May 6, 2016, we acquired a 25% membership interest in Rockies Express
from Sempra for cash consideration of approximately $436 million, or an enterprise value of approximately $1.08
billion when adjusted for our proportionate share of outstanding indebtedness at Rockies Express as of the acquisition
date.
Additional Membership Interest in Water Solutions. On July 1, 2016, we acquired the remaining 8% noncontrolling
equity interest in Water Solutions and additional interests in Water Solutions' subsidiaries from Regency Investments I,
LLC and BSEG Water Group LLC for total cash consideration of $6.0 million. Subsequent to the closing of the
transaction, our aggregate membership interest in Water Solutions is 100%.
Terminals and NatGas. Effective January 1, 2017, we acquired 100% of the issued and outstanding membership
interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from Tallgrass
Development for total cash consideration of $140 million.
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.
8
Additionally, pending and future construction projects, if and when brought online, may also compete with our crude oil
transportation, storage and terminalling services, natural gas transportation, storage and processing services and water
transportation, gathering 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.
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 Spectra Energy, Sinclair, Plains All American, Suncor, SemGroup, Magellan Midstream Partners, Anadarko, NGL
Energy Partners, Energy Transfer Partners, and Enbridge Energy Partners. 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. In addition, Terminals encounters competition in the crude oil storage and
terminalling business from similar facilities owned by Arc Logistics Partners LP, Magellan Midstream Partners, and NGL
Energy Partners, that provide similar services near its Buckingham Terminal.
Our principal competitors in our natural gas transportation and storage business include companies that own major natural
gas pipelines, such as Spectra Energy, Wyoming Interstate Company, LLC, Colorado Interstate Gas Company, LLC, Cheyenne
Plains Gas Pipeline Company, LLC, Northern Natural Gas Company, and Southern Star Central Gas Pipeline, Inc., some of
whom also have existing storage facilities connected to their transportation systems that compete with our storage facilities. In
addition to this competition, which is primarily comprised of other pipeline companies that transport gas out of the Rocky
Mountain region, Trailblazer also delivers gas into a very competitive marketplace that receives gas from the developing shale
plays like the Bakken, Marcellus and Utica. As these supplies increase, it reduces the need for traditional Rockies gas
production that is accessible from Trailblazer.
We also experience competition in the natural gas processing business. Our principal competitors for processing business
include other facilities that service our 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., which we refer to as Kinder Morgan,
ONEOK Partners, LP, Western Gas Partners, LP, Williams Partners L.P. 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. Further, we experience competition
in the water business services. Our principal competitors in such business are other midstream companies, such as NGL Energy
Partners, 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 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 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 the 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.
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.
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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, typically with respect to storage services. 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.
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.
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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, 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. Initial comments to such notice were required to be submitted by January 19, 2017.
Inquiry Regarding the FERC's Policy for Recovery of Income Tax Costs
On December 15, 2016, the FERC issued a Notice of Inquiry regarding the FERC's policy for recovery of income tax costs
in pipeline cost of service rates. The FERC is seeking comments regarding how to address any double recovery resulting from
the FERC's current income tax allowance and rate of return policies. This Notice of Inquiry follows the U.S. Court of Appeals
for the District of Columbia Circuit holding in United Airlines, Inc., et al. v. FERC that the FERC failed to demonstrate that
there is no double recovery of taxes for a partnership pipeline as a result of the income tax allowance and return on equity
determined pursuant to the discounted cash flow methodology. The FERC has set a deadline for initial comments to be
submitted by March 8, 2017.
Certain of our Dockets at the FERC
Rockies Express Zone 3 Capacity Enhancement Project
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 compression at one existing compressor station in Muskingum County, Ohio; and (3) certain
ancillary facilities. As proposed, the facilities would increase 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 0.8 Bcf/d on January 6, 2017.
Rockies Express Seneca Lateral Facilities Conversion
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 NGPA 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.
TIGT 2015 General Rate Case Filing
On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA. The rate case
proposed a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT. In
addition, TIGT proposed certain changes to the transportation rate design of its system to replace the current rate zone structure
with a single "postage stamp" rate. TIGT also proposed new incremental charges, including (i) a charge for deliveries made to
points without certain electronic flow measurement equipment, and (ii) a Cost Recovery Mechanism ("CRM") charge to
completely or partially reimburse TIGT for certain expenses and costs it incurs to comply with anticipated new PHMSA and
EPA regulations. TIGT also proposed to replace its fixed fuel and lost and unaccounted for ("FL&U") charge with a FL&U
tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period's under/
over collection and the forecasted FL&U expense for the upcoming period. TIGT also proposed to implement a power cost
tracker to recover the actual power costs incurred by TIGT to power its compressors. Finally, TIGT proposed certain revisions
to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under the NGA and the FERC's regulations,
TIGT's shippers and other interested parties, including the FERC's Trial Staff, have a right to challenge any aspect of TIGT's
rate case filing. Accordingly, numerous TIGT customers protested aspects of TIGT's NGA Section 4 rate filing.
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On November 30, 2015, the FERC issued an order accepting and suspending the proposed rates and a majority of the
proposed tariff records to be effective upon motion May 1, 2016, subject to refund, certain modifications to TIGT's proposed
CRM charge, and the outcome of an evidentiary hearing before a FERC Administrative Law Judge (the "TIGT Suspension
Order"). In the TIGT Suspension Order, the FERC also accepted two tariff records related to force majeure events and
reservation charge crediting to be effective December 1, 2015, subject to certain modifications. On December 21, 2015, TIGT
made a compliance filing with the FERC to modify TIGT's proposed CRM charge and update the tariff records related to force
majeure events and reservation charge crediting as directed by the FERC in the TIGT Suspension Order. No comments or
protests were filed in response to the compliance filing and the FERC accepted the compliance filing on February 1, 2016. On
March 31, 2016, the FERC issued an order denying certain rehearing requests pertaining to the proposed CRM charge and
removed from hearing the non-rate issues related to proposed pro forma tariff records, placing the non-rate issues under a
separate review process, and allowing interveners further opportunity to comment on the pro forma tariff. TIGT and certain
intervenors have since filed additional information and/or comments with respect to the proposed pro forma tariff. On February
3, 2017, the FERC accepted TIGT’s pro forma tariff records, subject to conditions, and directed TIGT to file the actual tariff
records within 30 days.
On June 8, 2016, TIGT filed an Offer of Settlement ("TIGT Rate Case Settlement") with the FERC, which resolved all
issues set for hearing. On July 14, 2016, the presiding Administrative Law Judge certified the TIGT Rate Case Settlement to the
FERC, finding that settlement was uncontested, presented no issues of first impression, had no FERC policy implications, and
appeared to be just, reasonable and in the public interest. On November 2, 2016, the FERC issued an order approving the TIGT
Rate Case Settlement, finding that it appeared to be fair and reasonable and in the public interest. The FERC also directed TIGT
to file revised tariff records to implement the TIGT Rate Case Settlement, which TIGT filed, and the FERC subsequently
approved on December 23, 2016. The November 2, 2016 order also terminated all matters in the TIGT rate case, apart from the
non-rate issues related to the pro forma tariff which remain pending before the FERC. Per the terms of the TIGT Rate Case
Settlement, TIGT is required to file a new general rate case on May 1, 2019 (provided that such rate case is not pre-empted by a
pre-filing settlement), and no Supporting/Non-Contesting Participant, as defined in the TIGT Rate Case Settlement, is
permitted to, inter alia, file to change the settlement rates or any other provisions set forth in the TIGT Rate Case Settlement
prior to May 1, 2019.
For additional information, see Note 17 – Regulatory Matters to our Consolidated Financial Statements in Item 8.—
Financial Statements and Supplementary Data in this Form 10-K.
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 have one year from January 18, 2017, the effective date of the IFR, to implement
this first set of PHMSA regulations governing underground storage fields. On January 13, 2017, PHMSA finalized new hazardous
liquid pipeline safety regulations. Among other things, the final rule requires additional event-driven and periodic inspections,
requires the use of leak detection systems on all hazardous liquid pipelines, modifies repair criteria, and requires certain pipelines
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to eventually accommodate in-line inspection tools. Because the rule was finalized at the end of the Obama Administration, the
rule is subject to a regulatory freeze pending review by the Trump Administration, unless exempted due to health and safety
considerations. Assuming the rule survives the review process or is exempted from the regulatory freeze, the rule will become
effective six months after its publication in the Federal Register, although certain provisions of the Final Rule will have longer
compliance periods. 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 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. 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 significant and unanticipated capital and operating expenditures
for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our 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
Trailblazer is currently operating at less than its current MAOP, public notice of which was first provided in June 2014. As
a result of smart tool surveys in 2014, Trailblazer has identified approximately 25 - 35 miles of pipe that will likely need to be
repaired or replaced in order for the pipeline to operate at its MAOP of 1,000 pounds per square inch across all segments of the
Trailblazer Pipeline. Such repair or replacement will likely occur over a period of years, depending upon the remediation and
repair plan implemented by Trailblazer. Segments of the Trailblazer Pipeline that require full replacement could cost as much as
$2.7 million per mile and repair costs on sections of the pipeline that do not require full replacement are expected to be less on
a per mile basis. The current pressure reduction is not expected to prevent Trailblazer from fulfilling its firm service obligations
at existing subscription levels and to date it has not had a material adverse financial impact on us.
With respect to the approximately 25 - 35 miles of pipe that has been identified, Trailblazer completed 32 excavation digs
in 2015 at an aggregate cost of approximately $1.3 million. During 2016, Trailblazer completed additional excavation digs and
replaced approximately 8 miles of pipe at an aggregate cost of approximately $19.0 million. Trailblazer is currently exploring
all possible cost recovery options to recover such out of pocket costs, including recovery through a general rate increase,
negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
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In connection with our acquisition of the Trailblazer Pipeline, TD agreed to contractually 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, to the
extent that such actions are necessitated by external corrosion caused by the pipeline's disbonded Hi-Melt CTE coating. The
contractual indemnity provided by TD is capped at $20 million and is subject to an annual $1.5 million deductible. In
connection with the 2016 repairs and remediation on the Trailblazer Pipeline, TEP has received $17.9 million from TD pursuant
to the contractual indemnity.
Pony Express
In connection with certain crack tool runs on the Pony Express System completed in 2015 and 2016, Pony Express
completed approximately $9.8 million of remediation in 2016 for anomalies identified on the Pony Express System associated
with portions of the pipeline that were converted from natural gas to crude oil service, and expects to complete additional
remediation in 2017 on the Pony Express System of approximately $9 million.
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.
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 we 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 continue 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.
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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. 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. 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.
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 present 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 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.
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 government also may seek to adopt ordinances within their jurisdictions regulating the time, place and
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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.
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 us 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. The EPA and the U.S. Army Corps of Engineers recently adopted a rule to clarify the meaning of
the term "waters of the United States" with respect to federal jurisdiction; that rule is currently stayed nationwide. Many
interested parties believe that the rule expands federal jurisdiction under the CWA. 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
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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
"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. Portions of the land on which our pipelines and facilities are
located are owned by us in fee title, and we believe that we have satisfactory title to these lands. 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
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title to all of our material parcels that we own in fee and the material parcels in which our interest derives from leases,
easements, rights-of-way, permits and licenses, and we have no knowledge of any challenge that we expect will impact our title
to such assets or their underlying fee title in any material respect.
Some of the leases, easements, rights-of-way, permits and licenses we acquire, including those we acquired in the IPO,
require the consent of the grantor for the assignment/conveyance of such rights, which in certain instances is a governmental
entity. The transferor, such as Tallgrass Development or its affiliates, may continue to hold record title to portions of certain
assets until we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and
approvals that are not obtained prior to transfer. Such consents and approvals would include those required by federal and state
agencies or political subdivisions. In some cases, Tallgrass Development may, where required consents or approvals have not
been obtained, temporarily hold record title to property as nominee for our benefit and in other cases may, on the basis of
expense and difficulty associated with the conveyance of title, cause its affiliates to retain title, as nominee for our benefit, until
a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from
Tallgrass Development holding the title to any part of such assets subject to future conveyance or as our nominee.
Insurance
We generally share insurance coverage with Tallgrass Development and TEGP, for which we reimburse Tallgrass
Development and its affiliates for our share of the cost pursuant to the terms of 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.
Employees
We do not have any employees. We are managed and operated by the board of directors and executive officers of our
general partner. All of our employees are employed by an affiliate of Tallgrass Energy Holdings and devote the portion of their
time to our business and affairs that is reasonably required to manage and conduct our operations. Under the terms of the TEP
Omnibus Agreement and our partnership agreement, we reimburse Tallgrass Development and our general partner, respectively,
for the provision of various general and administrative services for our benefit and for direct expenses incurred by Tallgrass
Development 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, at the SEC's Public Reference Room at 100 F Street, N.E.,
Washington, D.C. 20549 or by calling 1-800-SEC-0330. 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 distributions on our common units at the current
distribution level, or pay any distribution at all, and the trading price of our common units 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
distribution at the current distribution level, or at all, to holders of our common units.
We may not have sufficient available cash from operating surplus each quarter to enable us to pay the quarterly distribution
at the current distribution level, at the minimum quarterly distribution level, or at all. The amount of cash we can distribute on
our units 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;
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the creditworthiness of our customers, particularly customers who are subject to firm fee contracts;
our ability to complete and integrate acquisitions from Tallgrass Development or from third parties;
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;
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 distribution 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,
including Tallgrass Development, for services provided to us;
the cost of pursuing and completing acquisitions, 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.
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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 cash distributions to our unitholders 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, 2016, approximately 89% of our
crude oil transportation revenues were generated under firm fee transportation contracts and approximately 92% of our natural
gas transportation and storage revenues were generated under firm fee transportation and storage contracts. As of December 31,
2016, the weighted average remaining life of our oil transportation contracts was approximately three years, the weighted
average remaining life of our long-term natural gas transportation contracts and natural gas storage contracts at TIGT and
Trailblazer was approximately three years and five years, respectively, and the weighted average remaining life of our natural
gas processing contracts 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
2016 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, most of the long-term contracts for the Pony Express Pipeline
expire in 2019 and those customers may unilaterally decide whether to renew such contract. If those customers do not renew
their contract, 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;
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 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.
In the current commodity environment, which included significant price reduction and volatility in crude oil, natural gas
and other hydrocarbons from the second half of 2014 through the first half of 2016, we expect customers will generally
continue to be less likely to enter into long-term firm fee contracts until prices recover and stability returns to the commodity
markets. Customers who do enter into long-term 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 distributions to our unitholders 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 cash distributions to our unitholders. 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. The decline and volatility in natural gas and crude oil prices during the second half of 2014 through
the first half of 2016 negatively impacted the financial condition of our customers and future declines, lower prices, or volatility
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
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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 cash distributions to our
unitholders.
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. On January 12, 2017, Rockies Express and Ultra
agreed to settle Rockies Express’s claim against Ultra's bankruptcy estate. The settlement includes Ultra's agreement to pay
Rockies Express $150 million in cash no later than October 30, 2017 and enter 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. The settlement is part of Ultra's Chapter 11 reorganization plan,
and therefore subject to the approval of the U.S. Bankruptcy Court. There is no assurance that Ultra's Chapter 11 reorganization
plan will be approved or that Ultra will meet the terms and conditions for such plan to become effective.
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 TEP and Rockies Express view as favorable, the
settlements will not deliver the same benefits as the underlying contract at issue in each circumstance.
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. With the decline and volatility
in natural gas and crude oil prices over the last two years and the corresponding deterioration of the financial condition of some
of our customers, the percent of our revenue from customers with investment grade credit ratings fell to slightly under 45%
during the year ended December 31, 2016. Although we ask for credit support from customers without investment grade credit
ratings, 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.
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, 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 and may also increase the
magnitude of these obligations.
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, 2016, Continental
Resources and Shell accounted for approximately 16% and 13% of our revenues on a consolidated basis, respectively. In addition,
for the year ended December 31, 2016, approximately 60% of our consolidated revenues were represented by the top ten customers
on our Pony Express System. We own a 25% membership interest in Rockies Express, which is not consolidated for financial
reporting purposes. Approximately 23%, 12%, 10%, and 10%, respectively, of Rockies Express' total revenues as of December
31, 2016 were represented by Rockies Express' four largest non-affiliated shippers.
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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 cash distributions to our unitholders 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 distributions to
our unitholders, the price of our units, our results of operations and ability to conduct our business.
If we are unable to make acquisitions on economically acceptable terms from Tallgrass Development or third parties,
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 unit basis.
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations
on a per unit basis.
The acquisition component of our strategy is based, in part, on our expectation of ongoing divestitures of midstream energy
assets by industry participants, including Tallgrass Development. Many factors could impair our access to future midstream
assets, including a change in control of Tallgrass Development. A material decrease in divestitures of midstream energy assets
from Tallgrass Development or otherwise 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 distributions to our
unitholders.
Our future growth and ability to increase distributions will be limited if we are unable to make accretive acquisitions from
Tallgrass Development or third parties because, among other reasons, (i) Tallgrass Development elects not to sell or contribute
additional assets to us or to offer acquisition opportunities to us, (ii) we are unable to identify attractive third-party acquisition
opportunities, (iii) we are unable to negotiate acceptable purchase contracts with Tallgrass Development or third parties, (iv) we
are unable to obtain financing for these acquisitions on economically acceptable terms, (v) we are outbid by competitors or (vi)
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
unit basis. For example, we acquired a 25% membership interest in Rockies Express in May 2016, and if certain risks or
unanticipated liabilities were to arise, the desired benefits of the 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 our 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.
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If any acquisition eventually proves not to be accretive to our distributable cash flow per unit, it could have a material
adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our
unitholders.
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 distributions 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 distributions. We could be required to
use cash from our operations or incur borrowings or sell additional common units or other limited partner interests in order to
fund our expansion capital expenditures. Using cash from operations will reduce cash available for distribution to our common
unitholders. 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 distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest
expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder
dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could
materially decrease our ability to pay distributions at the then-current distribution rate. We do not currently have any
commitment with our general partner or other affiliates, including Tallgrass Development, 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, 2016, Pony Express had a cumulative net deficiency balance of $60.6 million and a cumulative
shipper incremental balance of $24.4 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.
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.
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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 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 Development 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 pay or increase distributions to our
unitholders. 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
distributions to our unitholders.
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.
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.
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, on June 17,
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. On February 2,
2017, Rockies Express and Michels entered into a binding settlement agreement to resolve the claims brought by Michels in
exchange for a $10 million cash payment by Rockies Express.
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, with respect to the Rockies Express Zone 3 Capacity Enhancement Project,
substantially all of the construction expenditures have been incurred during 2015 and 2016, yet Rockies Express will only
receive increases in cash flow from the project now that it is completed and was placed in-service in January 2017.
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.
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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, 2016, approximately 40% 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
distributions to our unitholders.
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 distributions to our unitholders.
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 a significant amount of
Rockies Express' revenue, are from contracts that contain most favored nations rights, limiting flexibility to offer certain
capacity to new shippers.
Approximately 90% of the Pony Express System's current available 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 distributions to our unitholders.
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 our ability to make distributions to our unitholders.
If third-party pipelines or other facilities interconnected to our systems become partially or fully unavailable, or if the
volumes we transport do not meet the quality requirements of such pipelines or facilities, our revenues and our ability to
make distributions to our unitholders could be adversely affected.
Our assets typically connect to other pipelines or facilities owned, leased and/or operated by unaffiliated third parties, such
as the ONEOK Bakken Pipeline, L.L.C., Deeprock Development, Whiting, 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.
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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, 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.
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, or if the volumes we transport or process do not meet the quality requirements of such pipelines or facilities, our
revenues and our ability to make quarterly cash distributions to our unitholders could be adversely affected.
The lack of diversification of our assets and geographic locations could adversely affect our ability to make
distributions to our common unitholders.
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 distribution to our common unitholders than if we maintained more
diverse assets and locations. For example, our water business services are concentrated in a limited number of assets and
primarily consists of our water business operations 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.
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 is 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.
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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 our 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.
The amount of cash we have available for distribution to unitholders depends primarily on our cash flow rather than on
our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution 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 distributions during periods when we record losses for
financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial
accounting purposes.
The revenue in our Processing & Logistics segment largely depends on the amount of natural gas that our customers
actually deliver to our natural gas processing plants.
As of December 31, 2016, approximately 99% of our reserved capacity at our Casper and Douglas natural gas processing
plants was subject to firm or volumetric fee contracts, with the majority of the fee revenue being based on the volumes actually
processed (the remaining 1% was subject to commodity sensitive contracts such as percent of proceeds or keep whole
processing contracts). 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
Processing & Logistics segment will decline. As natural gas, crude oil or NGL prices decline, which was the case from the
second half of 2014 through the first half of 2016, 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 and anticipated volumes from several producers from which TMID receives natural gas for processing. If a gradual
recovery of commodity prices and a corresponding increase in volumes over time to TMID does not occur, we could have an
impairment of the goodwill at the TMID reporting unit, which is a component of our Processing & Logistics 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 our exposure to
direct commodity price risk may increase in the future.
Our Processing & Logistics 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. As of
December 31, 2016, approximately 1% of the reserved capacity in our Processing & Logistics segment was contracted under
percent of proceeds or 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. From the second half of 2014 through the first half of
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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.
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 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. 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 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;
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;
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, and from the second half of 2014 through the
first half of 2016 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. If recent lower commodity
prices are prolonged beyond our contract lives, we will likely experience 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 recent declines in crude oil
prices, a number of producers in our areas of operation significantly reduced their capital budgets and drilling plans in 2015 and
2016. Even if those producers increase their capital budgets in areas we serve in 2017, it may take months before the increased
capital spending 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 recent
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 distributions
to our unitholders.
Our natural gas and crude oil 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 are subject to regulation by the FERC under the ICA, and the Energy
Policy Act of 1992. We provide interstate transportation service on the Pony Express System 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 the 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.
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 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 is 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.
For example, TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA in October 2015, which
resulted in the TIGT Rate Case Settlement that was approved by an order issued by the FERC on November 2, 2016. The TIGT
Rate Case 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 FL&U) 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.
Under the ICA, which applies to the Pony Express System, parties having standing and not restricted by contract may
protest newly filed rates and terms and conditions of service within a prescribed notice period. 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 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.
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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.
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.
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.
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.
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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, the FERC may 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. 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 distributions to our unitholders.
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. FERC generally
does not regulate crude oil transportation contracts, but contract rates must be filed with FERC and tariff rules and regulations
generally apply to contract shippers.
On our interstate crude oil pipeline system, the Pony Express System, shippers may generally challenge new or existing
rates at any time unless they have contractually agreed not to. As a result of settlement or by order of the FERC following
hearing, our 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.
Further, the FERC's actions are subject to court challenge, which may have broader implications for other regulated
pipelines. For example, in July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion
in United Airlines, Inc., et al. v. FERC, finding that the FERC had acted arbitrarily and capriciously when it failed to
demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income
tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result
in the pipeline partnership owners double-recovering their income taxes. The court vacated the FERC's order and remanded to
the FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance.
On December 15, 2016, the FERC issued a Notice of Inquiry regarding the FERC's policy for recovery of income tax costs
in pipeline cost of service rates. The FERC is seeking comments regarding how to address any double recovery resulting from
the FERC's current income tax allowance and rate of return policies following the holding in United Airlines, Inc., et al. v.
FERC. The FERC has set a deadline for initial comments to be submitted by March 8, 2017.
There is not likely to be a definitive resolution of these issues for some time, and the ultimate outcome of this proceeding is
not certain and could result in changes going forward to the FERC's treatment of income tax allowances in the cost of service or
to the discounted cash flow return on equity. Depending upon the resolution of these issues, the cost of service rates of our
interstate natural gas pipelines and interstate crude oil pipeline could be affected to the extent we propose new rates or changes
to our existing rates or if our rates are subject to complaint or challenge by the FERC.
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 distributions to our unitholders.
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;
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;
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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 distributions to
unitholders. For example, approximately 10,000 bbls of crude oil were released at the Sterling Terminal in January 2017. Our
initial review indicates that the release was restricted to the containment area located at the Sterling Terminal and was the result
of a defective roof drain system on a storage tank. While approximately 9,000 bbls have been recovered and we do not
anticipate that our total costs to remediate such release will exceed $500,000, our ultimate remediation costs may exceed our
estimates.
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 distributions to our unitholders. 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 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 18 – Legal and Environmental Matters to the consolidated financial statements 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.
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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;
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. PHMSA recently published an IFR that will increase the per-day violation penalty to $205,638
and the maximum penalty for a related series of violations to $2,056,380, effective August 1, 2016. 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 requires additional event-driven and periodic inspections,
requires the use of leak detection systems on all hazardous liquid pipelines, modifies repair criteria, and requires certain
pipelines to eventually accommodate in-line inspection tools. Because the rule was finalized at the end of the Obama
Administration, the rule is subject to a regulatory freeze pending review by the Trump Administration, unless exempted due to a
determination by PHMSA and OMB to allow its effect due to health and safety considerations. Assuming the rule survives the
review process or is exempted from the regulatory freeze, the rule will become effective six months after its publication in the
Federal Register, although certain provisions of the Final Rule will have longer compliance periods. 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.
On June 22, 2016, President Obama signed the PIPES Act, that reauthorizes PHMSA's oil and gas pipeline programs
through 2019 and provides for the following new mandates, among others:
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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 will have one year from January 18, 2017,
the effective date of the IFR, to implement this first set of PHMSA regulations governing underground storage fields.
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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.
For example, Trailblazer is currently operating at less than its current MAOP, public notice of which was first provided in
June 2014. As a result of smart tool surveys in 2014, Trailblazer has identified approximately 25 - 35 miles of pipe that will
likely need to be repaired or replaced in order for the pipeline to operate at its MAOP of 1,000 pounds per square inch across all
segments of the Trailblazer Pipeline. Such repair or replacement will likely occur over a period of years, depending upon the
remediation and repair plan implemented by Trailblazer. Segments of the Trailblazer Pipeline that require full replacement
could cost as much as $2.7 million per mile and repair costs on sections of the pipeline that do not require full replacement are
expected to be less on a per mile basis.
With respect to the approximately 25 - 35 miles of pipe that has been identified, Trailblazer completed 32 excavation digs
in 2015 at an aggregate cost of approximately $1.3 million. During 2016, Trailblazer completed additional excavation digs and
replaced approximately 8 miles of pipe at an aggregate cost of approximately $19.0 million. Trailblazer may not recover all
such out of pocket costs through the available cost recovery options, such as 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 and 2016, Pony
Express completed approximately $9.8 million of remediation in 2016 for anomalies identified on the Pony Express System
associated with portions of the pipeline converted from natural gas to crude oil service, and expects to complete additional
remediation in 2017 on the Pony Express System of approximately $9 million.
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 our 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 and terminalling, natural gas transportation, storage 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:
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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;
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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;
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,
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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 $497,000 in 2015 and
approximately $990,000 in 2016, and we have budgeted approximately $718,000 for 2017.
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 2013, the EPA extended its National Enforcement Initiatives, enforcement priorities list, including an initiative
related to Energy Extraction Activities, for 2014 through 2016, and the EPA plans to retain the Energy Extraction Activities
initiative for an additional three years, effective October 2016. 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, 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. As another 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. Most recently, the parties held a settlement meeting in August 2015. Following
the settlement meeting, negotiations are continuing and the parties have entered into tolling agreements that have tolled the
statute of limitations until January 31, 2017. 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.
37
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.
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. The rule is currently stayed nationwide.
Although it is unclear how the Corps and the EPA will implement this rule if the stay is lifted, the rule may require additional
Corps or EPA authorizations or involvement in our future operations, for instance, if we extend our pipelines into or across
areas (such as certain ditches) newly considered "waters of the United States" under the final rule.
The 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. 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. 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. On November 10, 2016, the EPA issued a final information collection request that
requires oil and gas companies to provide EPA with extensive information that EPA could use in crafting regulations of existing
methane sources under CAA Section 111(d). 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. 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. 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,
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.
38
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.
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. 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. 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, but a Wyoming federal judge struck down the rules in June 2016, finding that the BLM lacked congressional
authority to promulgate them. The BLM is appealing this decision to the U.S. Court of Appeals for the Tenth Circuit. 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.
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.
39
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. 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 has also 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. 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.
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 distributions to our unitholders.
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 distributions to our unitholders.
40
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 cash distributions to our unitholders.
Our revolving credit facility and the indenture governing our 5.50% senior notes due 2024 contain certain restrictions
which could adversely affect our business, financial condition, results of operations and ability to make quarterly cash
distributions to our unitholders.
We are dependent upon certain earnings and cash flow generated by our operations in order to meet our debt service
obligations. Our revolving credit facility and the indenture governing our 5.50% senior notes due 2024 (the "2024 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 cash distributions to our unitholders.
For example, our revolving credit facility limits our ability to, among other things:
•
•
incur or guarantee additional indebtedness;
redeem or repurchase units or make 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;
• merge or consolidate with another company; and
•
transfer, sell or otherwise dispose of assets.
Our revolving credit facility also contains covenants requiring us 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 we will meet those
ratios and tests. Further, our obligations under the revolving credit facility are (i) guaranteed by us and each of our existing and
subsequently acquired or organized direct or indirect wholly owned domestic subsidiaries, subject to our 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 us and each guarantor (other than real property interests related to our pipelines).
Similarly, the indenture governing the 2024 Notes contains covenants that, among other things, limit our ability and the
ability of our 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 of our properties to, another person; (vii) sell or otherwise
dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates.
The provisions of our revolving credit facility and indenture governing the 2024 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 our revolving credit facility or the indenture
governing the 2024 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 our lenders or the holders of the 2024 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 revolving
credit facility, would prohibit our ability to make quarterly distributions. If the payment of our indebtedness is accelerated and
we are unable to repay the indebtedness in full, our lenders could foreclose on the assets pledged by us and the guarantors under
the revolving credit facility. In that case, our assets may be insufficient to repay such indebtedness in full, and our unitholders
could experience a partial or total loss of their investment.
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Tallgrass Equity's ownership in our IDRs, our common units and our general partner interest, are pledged under
Tallgrass Equity's revolving credit facility.
Tallgrass Equity's direct ownership of 20,000,000 of our common units and its direct ownership of our general partner
(which owns our IDRs and general partner interest), are pledged as security under Tallgrass Equity's revolving credit facility.
Tallgrass Equity's revolving credit facility contains customary and other events of default. Upon an event of default, the lenders
under Tallgrass Equity's revolving credit facility could foreclose on Tallgrass Equity's ownership interest in TEP GP and the
20,000,000 of our common units owned by Tallgrass Equity. This could ultimately result in a change in control of TEP GP,
which would constitute an immediate event of default under our credit facility. This would have a material adverse effect on our
business, financial condition and results of operations.
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 distributions to unitholders 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 distributions, 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 your
investment. 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 unit price, our ability to issue equity or incur indebtedness for
acquisitions or other purposes and our ability to make cash distributions at our intended levels.
The interest rate on borrowings under our 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 our revolving credit facility.
As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied
distribution yield. The distribution 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 units, and a rising interest rate environment could have an adverse impact on our unit price, our
ability to issue equity or incur indebtedness for acquisitions or other purposes and our ability to make cash distributions at our
intended levels.
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 December 31, 2016 Rockies Express had approximately $2.575 billion of total indebtedness outstanding. In addition,
Rockies Express has a revolving credit facility, which will mature on January 31, 2020, with approximately $150 million of
additional borrowing capacity available as of December 31, 2016.
The scheduled maturities of Rockies Express' outstanding indebtedness balances as of December 31, 2016 are summarized
as follows (in millions):
Year
2018 .........................................................................................................................................
2019 .........................................................................................................................................
2020 .........................................................................................................................................
Thereafter ................................................................................................................................
Scheduled Maturities
$
550.0
525.0
750.0
750.0
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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 agreement governing its credit facility permits 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 2016 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 distributions to our unitholders.
Rockies Express' revolving credit facility contains certain restrictions which could limit its financial flexibility and
increase its financing costs.
Rockies Express' revolving credit facility contains 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 revolving credit facility
generally requires Rockies Express to comply with various affirmative and negative covenants, including a limit on the
leverage ratio (as defined in the 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.
The instruments governing any future indebtedness 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
43
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 distributions to our unitholders. 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. Whether we have the power of eminent
domain for the Pony Express crude oil pipeline varies from state to state, depending upon the laws of the particular state.
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 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 report our financial
results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
Upon the completion of our initial public offering, we became subject to the public reporting requirements of the Securities
Exchange Act of 1934, as amended. Effective internal controls are necessary for us to provide reliable financial reports, prevent
fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may
not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future
or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For
example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public
accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Any failure to develop,
implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause
us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over
financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm's, conclusions
about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404.
Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information,
which could have an adverse effect on our business and would likely have a negative effect on the trading price of our units.
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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 our water business services, may
have a material adverse effect on our business, financial condition and results of operations.
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. 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.
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 eliminate or reduce these risks by using redundant
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.
Our investment in Rockies Express is a minority interest and could be adversely affected by our lack of sole decision-
making authority.
As a minority-interest partner in Rockies Express, we do not control Rockies Express. 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
other members of Rockies Express might become bankrupt, fail to fund their 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.
The other members of Rockies Express 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, including Tallgrass Development, to make decisions with respect to their ownership interest without taking into
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account the interests of Rockies Express or any other member of Rockies Express, and we do not have a voting trust or other
arrangement in place requiring us or Tallgrass Development to vote jointly. 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 of the decisions of the
Rockies Express members effectively require unanimous approval of all three members of Rockies Express, including Tallgrass
Development and Phillips 66.
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 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 general partner and its affiliates, including Tallgrass Equity, TEGP and Tallgrass Energy Holdings, have conflicts
of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us
and our other common unitholders.
Tallgrass Equity owns our general partner and appoints all of the officers and directors of our general partner. TEGP owns
a 36.94% membership interest in, and is the managing member of, Tallgrass Equity. TEGP Management is TEGP's general
partner. Tallgrass Energy Holdings is the sole member of TEGP Management and is also the general partner of Tallgrass
Development.
All of our current officers and a majority of the current directors of our general partner are also officers and/or directors of
Tallgrass Equity, TEGP Management and Tallgrass Energy Holdings. Certain of our directors are also officers or principals of
Kelso or EMG, whose affiliated entities, along with certain members of our management, own and control Tallgrass Energy
Holdings. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the
officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner that is in the best
interests of its owner, Tallgrass Equity. Conflicts of interest will arise between our general partner and its direct and indirect
owners, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general
partner may favor its own interests and the interests of its direct and indirect owners over our interests and the interests of our
unitholders. These conflicts include the following situations, among others:
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Neither our partnership agreement nor any other agreement requires Tallgrass Equity, TEGP Management, Tallgrass
Energy Holdings or their respective direct and indirect owners to pursue a business strategy that favors us, and the
officers and directors of Tallgrass Energy Holdings, TEGP Management and Tallgrass Equity may have a fiduciary
duty to make these decisions in the best interests of Tallgrass Energy Holdings, TEGP Management and Tallgrass
Equity and their respective direct and indirect owners, respectively, which may be contrary to our interests. Tallgrass
Energy Holdings, TEGP Management or Tallgrass Equity may choose to shift the focus of their investment and growth
to areas not served by our assets.
Tallgrass Energy Holdings, TEGP Management and Tallgrass Equity their respective direct and indirect owners, and
their respective affiliates are not limited in their ability to compete with us and, other than Tallgrass Development's
obligation to offer us certain assets (if Tallgrass Development decides to sell such assets) pursuant to the right of first
offer under the TEP Omnibus Agreement, may offer business opportunities or sell midstream assets to third parties
without first offering us the right to bid for them.
Our general partner is allowed to take into account the interests of parties other than us, such as Tallgrass Energy
Holdings, its direct and indirect owners, and their respective affiliates in resolving conflicts of interest and exercising
certain rights under our partnership agreement, which has the effect of limiting its duty to our unitholders.
All of the current officers and a majority of the current directors of our general partner are also officers and/or
directors of Tallgrass Energy Holdings and may owe fiduciary duties to Tallgrass Energy Holdings and Tallgrass
Development. Accordingly, these officers will devote significant time to the business of Tallgrass Development.
Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with
contractual standards governing its duties, limits our general partner's liabilities and restricts the remedies available to
our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.
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Except in limited circumstances, our general partner has the power and authority to conduct our business without
unitholder approval.
Disputes may arise under our commercial agreements with Tallgrass Development and its affiliates.
Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional
partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash
available for distribution to our unitholders.
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is
classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital
expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is
distributed to our unitholders.
Our general partner determines which costs incurred by it are reimbursable by us.
Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the
purpose or effect of the borrowing is to make incentive distributions.
Our partnership agreement permits us to classify up to $40 million as operating surplus, even if it is generated from
asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash
may be used to fund distributions on our general partner units or to our general partner in respect of the IDRs.
Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any
services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
Our general partner may limit its liability regarding our contractual and other obligations.
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its
affiliates if they own more than 80% of the common units.
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including Tallgrass
Development's and its affiliates' obligations under the TEP Omnibus Agreement and their commercial agreements with
us.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our general partner may transfer its IDRs without unitholder approval.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target
distribution levels related to our general partner's IDRs without the approval of the conflicts committee of the board of
directors of our general partner or our unitholders. This election may result in lower distributions to our common
unitholders in certain situations.
Affiliates of our general partner are not limited in their ability to compete with us and have limited obligations to offer
us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect
our results of operations and cash available for distribution to our unitholders.
Affiliates of our general partner, including Kelso, EMG, Tallgrass Equity and its affiliates and Tallgrass Energy Holdings
and its affiliates, including Tallgrass Development, are not prohibited from owning assets or engaging in businesses that
compete directly or indirectly with us. In addition, in the future, affiliates of our general partner and the entities owned or
controlled by affiliates of our general partner, including Tallgrass Development, may acquire, construct or dispose of additional
midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the
opportunity to purchase or construct such assets or to engage in such business opportunities, other than Tallgrass Development's
obligation to offer us certain assets (if Tallgrass Development decides to sell such assets) pursuant to the right of first offer
under the TEP Omnibus Agreement. While affiliates of our general partner may offer us the opportunity to buy these or other
additional assets, these affiliates of our general partner, including Tallgrass Development, are not contractually obligated to do
so, other than as described above, and we are unable to predict whether or when such opportunities may arise.
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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does
not apply to our general partner, its executive officers and directors or any of its affiliates, including Tallgrass Development.
Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an
opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be
liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or
entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not
communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and
affiliates of our general partner, including Tallgrass Development, and result in less than favorable treatment of us and our
common unitholders.
Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce
cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be
determined by our general partner.
Under our partnership agreement and the TEP Omnibus Agreement, we will reimburse our general partner and Tallgrass
Energy Holdings and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as
compensation expense for those persons who provide services necessary to run our business, and insurance expenses. Our
partnership agreement and the TEP Omnibus Agreement each provide that our general partner will determine in good faith the
expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and
Tallgrass Energy Holdings and its affiliates will reduce the amount of available cash to pay cash distributions to our common
unitholders.
Our partnership agreement requires that we distribute our available cash, which could limit our ability to grow and
make acquisitions.
Our partnership agreement requires us to distribute our available cash to our unitholders. 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.
In addition, because we intend to distribute 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 units in connection with any
acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that
we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement
on our ability to issue additional units, including units ranking senior to the common units. 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 available cash that we have to distribute to our unitholders.
While our partnership agreement requires us to distribute our available cash, our partnership agreement, including
provisions requiring us to make cash distributions contained therein, may be amended.
While our partnership agreement requires us to distribute our available cash, our partnership agreement, including
provisions requiring us to make cash distributions therein, may be amended. Our partnership agreement can be amended with
the consent of our general partner and the approval of a majority of the outstanding common units (including common units
held by our general partner and its affiliates, including Tallgrass Development and Tallgrass Equity). Tallgrass Development
and Tallgrass Equity currently own approximately 7.8% and 27.7% of our outstanding common units, respectively.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance
requirements.
Our common units are listed on the New York Stock Exchange, or NYSE. Unlike most corporations, we are not required
by NYSE rules to have, and we do not intend to have, a majority of independent directors on our general partner's board of
directors or a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance
of additional common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval
rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the
NYSE corporate governance requirements.
If you are not an eligible taxable holder, you will not be entitled to allocations of income or loss or distributions or
voting rights on your common units and your common units will be subject to redemption.
In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our
subsidiaries on assets that are subject to rate regulation by the FERC or an analogous regulatory body, we have adopted certain
requirements regarding those investors who may own our common units. Eligible holders are individuals or entities subject to
United States federal income taxation on the income generated by us or entities not subject to United States federal income
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taxation on the income generated by us, so long as all of the entity's owners are subject to such taxation. If a holder of our
common units (other than affiliates of our general partner) is not a person who fits the requirements to be an eligible taxable
holder, such holder will not be entitled to receive allocations of income or loss or distributions or voting rights on its units and
will run the risk of having its units redeemed by us at the market price calculated in accordance with our partnership agreement
as of the date of redemption. The redemption price will be paid in cash or by delivery of a promissory note, as determined by
our general partner.
Our partnership agreement replaces our general partner's fiduciary duties to holders of our common units 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 unitholders other than the implied contractual
covenant of good faith and fair dealing (which provides that a court will enforce the reasonable expectations of the partners
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 limited partners. Examples of decisions that our
general partner may make in its individual capacity include:
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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;
whether to elect to reset target distribution levels;
whether to transfer the IDRs or any units it owns to a third party; 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 unitholders.
Our partnership agreement restricts the remedies available to holders of our common units 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 unitholders 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:
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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 unitholders for decisions made in its capacity as a general
partner so long as such decisions are made in good faith;
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
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our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us
or our unitholders) 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 common units, excluding any common units 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 common unitholders 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.
Holders of our common units have limited voting rights and are not entitled to select our general partner or elect
members of its board of directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders have no right
on an annual or ongoing basis to select our general partner or elect its board of directors. Rather, the board of directors of our
general partner, including the independent directors, is appointed by Tallgrass Equity, as a result of it owning our general
partner, and not by our unitholders. Tallgrass Energy Holdings effectively controls our business and affairs through the exercise
of its rights as the party that controls Tallgrass Equity. Furthermore, if the unitholders are dissatisfied with the performance of
our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the
common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our
partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information
about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of
management.
Even if holders of our common units are dissatisfied, they cannot currently remove our general partner without its
consent.
Unitholders are currently unable to remove our general partner without its consent because our general partner and its
affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding
common units is required to remove our general partner. Tallgrass Development and Tallgrass Equity currently own
approximately 7.8% and 27.7% of our outstanding common units, respectively. This gives our affiliates the ability to prevent
the involuntary removal of our general partner. Cause is narrowly defined to mean that a court of competent jurisdiction has
entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity
as our general partner and does not include most cases of charges of poor management of the business.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders' voting rights are further restricted by a provision of our partnership agreement providing that any units held by
a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their
transferees, persons who acquired such units with the prior approval of the board of directors of our general partner and
transferees of any of the foregoing, provided such transferee is an affiliate of the transferor, cannot vote on any matter.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder
consent.
Our general partner may transfer its general partner interest to a third party without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the ability of Tallgrass Energy Holdings to cause the transfer of all or a
portion of Tallgrass Equity's ownership interest in our general partner to a third party. For example, on May 12, 2015, Tallgrass
Energy Holdings completed the initial public offering of TEGP that indirectly owns all of our incentive distribution rights, our
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general partner interest, and a certain number of our common units. Under this new structure, Tallgrass Energy Holdings
continues to indirectly control our general partner, but, if, in the future, Tallgrass Energy Holdings no longer controls, directly
or indirectly, our general partner, then a third party with a controlling interest in our general partner would be in a position to
replace the board of directors and officers of our general partner with its own designees and thereby exert significant control
over the decisions made by the board of directors and officers. This effectively permits a "change of control" without the vote
or consent of the unitholders.
The IDRs of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its IDRs to a third party at any time without the consent of our unitholders. If our general
partner transfers its IDRs to a third party but retains its general partner interest, our general partner may not have the same
incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained
ownership of its IDRs. For example, a transfer of IDRs by our general partner could reduce the likelihood of Tallgrass
Development selling or contributing additional midstream assets to us, because Tallgrass Energy Holdings, Tallgrass
Development's general partner, would have less of an economic incentive to grow our business, which in turn would impact our
ability to grow our asset base.
We may issue additional units without unitholder approval, which could negatively impact unitholders' existing
ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests, including limited partner
interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The
issuance by us of additional common units or other equity securities of equal or senior rank could have the following effects:
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our existing unitholders' proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
because the amount payable to holders of IDRs is based on a percentage of the total cash available for distribution, the
distributions to holders of IDRs will increase even if the per unit distribution on common units remains the same;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
Further, at times during recent years, the capital markets have limited the availability of capital through traditional issuances
of common units. As these periods occur in the future, it may be necessary for us to issue preferred units, convertible units, or
other securities that rank senior to the common units in order to raise capital, which could further magnify the dilutive and other
negative effects on unitholders' existing ownership interests.
Affiliates of our general partner, including Tallgrass Development, may sell units in the public or private markets, and
such sales could have an adverse impact on the trading price of the common units.
Tallgrass Development currently holds 5,619,218 common units and Tallgrass Equity, which owns our general partner,
currently holds 20,000,000 common units. In addition, we have agreed to provide our general partner and its affiliates with
certain registration rights. For example, the 5,619,218 common units owned by Tallgrass Development have been 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.
The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on
any trading market that may develop. For additional information, see Note 12 – Partnership Equity and Distributions to our
Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data in this Form 10-K.
Our general partner may limit its liability regarding our obligations.
Our general partner may limit its liability under contractual arrangements so that the counterparties to such arrangements
have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause
us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our
general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In
addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf.
Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to
our unitholders.
51
Our general partner has a limited call right that may require unitholders to sell units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have
the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the
common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant
to the terms of our partnership agreement. As a result, unitholders may be required to sell common units at an undesirable time
or price and may not receive any return on investment.
Unitholders may also incur a tax liability upon a sale of your units. Tallgrass Development and Tallgrass Equity, each an
affiliate of our general partner, currently own approximately 7.8% and 27.7% of our outstanding common units, respectively.
Our general partner, or any transferee holding a majority of the IDRs, may elect to cause us to issue common units to it
in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the IDRs,
without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower
distributions to our common unitholders in certain situations.
The holder or holders of a majority of the IDRs, which is currently our general partner, have the right, at any time when
there are no subordinated units outstanding and the holders have received incentive distributions at the highest level to which
they are entitled (48%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not
exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target
distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a
reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for
the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly
distribution"), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases
above the reset minimum quarterly distribution. We have been paying quarterly cash distributions at the highest distribution
level (48%) since our distribution with respect to the fourth quarter of 2014. Our general partner has the right to transfer the
IDRs at any time, in whole or in part, and any transferee holding a majority of the IDRs would have the same rights as our
general partner with respect to resetting target distributions.
In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the IDRs will
be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have
entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the
distributions on the IDRs in the prior two quarters. Our general partner will also be issued the number of general partner units
necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our
general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not
otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a
transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash
distributions it receives related to its IDRs and may therefore desire to be issued common units rather than retain the right to
receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current
business environment. This risk could be elevated if our IDRs have been transferred to a third party. As a result, a reset election
may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise
received had we not issued common units to our general partner in connection with resetting the target distribution levels.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those
contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is
organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders
of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other
states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court
or government agency were to determine that:
•
•
we were conducting business in a state but had not complied with that particular state's partnership statute; or
your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our
partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under
Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution
would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the
date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the
distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of
52
common units are liable both for the obligations of the transferor to make contributions to the partnership that were known to
the transferee at the time of transfer and for those obligations that were unknown if the liabilities could have been determined
from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-
recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being
subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service treats us as a
corporation for U.S. federal income tax purposes or we become subject to material additional amounts of entity-level
taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends in part on our being treated as a
partnership for U.S. federal income tax purposes. We have not requested, and except as described below, do not plan to request,
a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a publicly
traded partnership such as ours to be treated as a corporation rather than a partnership for U.S. federal income tax purposes.
Although we do not believe based upon our current operations that we are so treated, a change in our business or a change in
current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to
taxation as an entity.
For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the U.S.
federal income tax laws that affect publicly traded partnerships. We are unable to predict whether any such changes, or
proposals, will be considered or will ultimately be enacted or whether judicial or administrative interpretations of applicable
law will change. Any such changes could negatively impact the value of an investment in our common units. Any modification
to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the
exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
On January 24, 2017, final regulations by the IRS and the U.S. Department of the Treasury were published in the Federal
Register that provide industry-specific guidance regarding whether income earned from certain activities will constitute qualifying
income. We believe that we will continue to be able to meet the exception for us to be treated as a partnership for U.S. federal
income tax purposes under the new rules.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our
taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax
at varying rates. Our distributions would generally be taxed again as corporate dividends (to the extent of our current and
accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a
tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced.
Therefore, if we were treated as a corporation for U.S. federal income tax purposes there would be a material reduction in our
anticipated cash flow and after tax return to our unitholders, likely causing a substantial reduction in the value of our common
units.
At the state level, 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 us by any state will reduce the cash available
for distributions to our unitholders.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax
purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact
of that law on us.
Our unitholders' share of our income will be taxable to them for U.S. federal income tax purposes even if they do not
receive any cash distributions from us.
A unitholder will be treated as a partner who is subject to allocation of taxable income which could be different in amount
than the cash we distribute. A unitholder's allocable share of our taxable income will be taxable to the unitholder, which may
require the payment of U.S. federal income taxes and, in some cases, state and local income taxes even if no cash distributions
are received from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or
even equal to the actual tax liability that results from that income.
53
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely
impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax
purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS's
positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all
of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the
outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which
they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner
because the costs will reduce our cash available for distribution.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss for U.S. federal income tax purposes equal to the
difference between the amount realized and your tax basis in those common units. Because distributions in excess of your
allocable share of our net taxable income decrease your tax basis in your common units, some, or all of any of such prior excess
distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common
units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost.
Furthermore, a substantial portion of the amount realized on any sale or other disposition of your common units, whether or not
representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In
addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your common units,
you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in
adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts
(known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to
organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated
business taxable income and will be taxable to them. Distributions to non-U.S. persons will generally be reduced by
withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income
tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should
consult a tax advisor before investing in our common units.
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common
units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt
depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS
challenge to those positions could adversely affect the amount of tax benefits available to you. A successful IRS challenge also
could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative
impact on the value of our common units or result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and
transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the
basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation
of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and
transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis
of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury
Regulations, and although the U.S. Treasury Department adopted final Treasury Regulations allowing a similar monthly
simplifying convention for taxable years beginning on or after August 3, 2015, such regulations do not specifically authorize
the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were
issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
54
A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be
considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal
income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain
or loss from the disposition.
Because a unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be
considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax
purposes as a partner with respect to those common units during the period of the loan to the short seller and may recognize
gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or
deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by
the unitholder as to those common units could be fully taxable as ordinary income. Our unitholders desiring to assure their
status as partners and avoid the risk of gain recognition from a loan to a short seller should consult a tax advisor to discuss
whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their
common units.
We have adopted certain valuation methodologies in determining a unitholder's allocations of income, gain, loss and
deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely
affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the
fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation
matters, we make many fair market value estimates using a methodology based on the market value of our common units as a
means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting
allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income
or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of common units
and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns
without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in
the termination of our partnership for U.S. federal income tax purposes.
We will be considered to have technically terminated our partnership for U.S. federal income tax purposes if there is a sale
or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Tallgrass
Development and its direct and indirect owners own a substantial interest in our capital and profits. Therefore, a transfer by
them of all or a portion of their interests in us could result in a termination of our partnership for U.S. federal income tax
purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be
counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all
unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was
not available, as described below) for one fiscal year if the termination occurs on a day other than December 31 and could
result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting
on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than
twelve months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination. Our
termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead we
would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and
could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly
traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated
requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the
partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
As a result of investing in our common units you will likely become subject to state and local taxes and return filing
requirements in jurisdictions where we operate or own or acquire properties.
In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local
taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in
which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our
unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all
of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those
requirements. We currently own property or conduct business in a number of states, most of which currently impose a personal
income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make
acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal
income tax. It is your responsibility to file all federal, state and local tax returns.
55
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 distribution to our unitholders.
We have subsidiaries that are treated as corporations for U.S. federal income tax purposes and subject to corporate level
income taxes and may conduct additional activities in taxable corporate subsidiaries in the future.
Even though we (as a partnership for U.S. federal income tax purposes) are not subject to U.S. federal income tax, we have
subsidiaries that are organized as corporations for U.S. federal income tax purposes. Although these subsidiaries have not previously
generated any material taxable income, we may elect to conduct additional activities in one or more subsidiaries treated as
corporations for U.S. federal income tax purposes in the future that could generate material taxable income. For example, it is
unclear whether and to what extent our share of water business services income from Water Solutions will be treated as qualifying
income. On January 24, 2017, final regulations by the IRS and the U.S. Department of the Treasury were published in the Federal
Register providing that income from water delivery services is not qualifying income unless the partnership providing those services
also collects, cleans, recycles or otherwise disposes of the water after use in accordance with applicable law. While we have not
requested a ruling from the IRS that income from Water Solutions, or a portion of such income, is qualifying income, we may
request such a ruling in the future, although the IRS may be unwilling or unable to provide a favorable ruling in a timely manner
or at all. If it becomes necessary in order to preserve our status as a partnership, we may elect to conduct all or portions of our
Water Solutions business in a taxable corporate subsidiary (see "—Our tax treatment depends on our status as a partnership for
U.S. federal income tax purposes. If the IRS were to treat us as a corporation for U.S. federal income tax purposes, which would
subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.").
The taxable income, if any, of any subsidiary that is treated as a corporation for U.S. federal income tax purposes, is
subject to corporate-level U.S. federal income taxes, which may reduce the cash available for distribution to us and, in turn, to
our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that this corporation has more tax
liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution
could be further reduced. The income tax return filing positions taken by corporate subsidiaries could require significant
judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment could also be
required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return
positions taken by our corporate subsidiaries would be fully supportable, certain positions may be successfully challenged by
the IRS, state or local jurisdictions.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any
resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for
distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years
beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We
will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their
interests in us during the year under audit, but there can be no assurance that we will be able to (or will choose to) do so under
all circumstances. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our
cash available for distribution to our unitholders might be substantially reduced.
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.
56
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 2020. In addition, we lease our principal executive offices in Leawood, Kansas. Tallgrass Development
pays a proportionate share of the costs to occupy the building to us pursuant to the TEP Omnibus Agreement.
Item 3. Legal Proceedings
See Note 18 – Legal and Environmental Matters to the consolidated financial statements included in Part II—Item 8.—
Financial Statements and Supplementary Data of this Annual Report, which is incorporated by reference into this Part I—Item
3 of this Annual Report.
Item 4. Mine Safety Disclosures
Not applicable.
(cid:24)(cid:26)
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Market Information
Our common units have been listed on the New York Stock Exchange ("NYSE") under the symbol "TEP" since the
completion of our IPO on May 17, 2013. The following table sets forth the high and low sales prices of the common units, as
reported by the NYSE, as well as the amount of cash distributions per unit declared for the periods indicated:
Quarter Ended
December 31, 2016.............................
$
September 30, 2016 ............................
June 30, 2016 ......................................
March 31, 2016...................................
December 31, 2015.............................
September 30, 2015 ............................
June 30, 2015 ......................................
March 31, 2015...................................
Holders
High
Low
Distribution per
Common Unit
$
48.86
49.79
50.78
42.35
47.63
49.09
52.13
53.70
$
42.59
43.19
35.62
25.82
33.40
35.02
47.21
40.00
0.8150
0.7950
0.7550
0.7050
0.6400
0.6000
0.5800
0.5200
As of February 15, 2017, there were 64 unitholders of record of our common units. This number does not include
unitholders whose units are held in trust by other entities. The actual number of beneficial unitholders is greater than the
number of holders of record. In addition, as of February 15, 2017, our general partner owned all 834,391 of our general partner
units.
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 45 days after the end of each quarter, we distribute our available
cash to unitholders of record on the applicable record date, as determined by our general partner.
Definition of Available Cash. The term "available cash" generally means, for any quarter, all cash and cash equivalents on
hand at the end of that quarter:
•
less the amount of cash reserves established by our general partner to:
provide for proper conduct of business;
comply with applicable law or regulation, any of our debt instruments or other agreements; or
provide funds for distributions to unitholders and to our general partner for any one or more of the next four
quarters;
•
plus, if our general partner so determines, all or any portion of the cash on hand on the date of distribution of available
cash for the quarter, including cash on hand resulting from working capital borrowings made subsequent to the end of
such quarter.
58
Minimum Quarterly Distribution. We intend to make cash distributions to the holders of common units on a quarterly basis
in an amount equal to at least the minimum quarterly distribution, or MQD, of $0.2875 per unit or $1.15 per unit on an
annualized basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of
fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay
the MQD on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of
distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into
consideration the terms of our partnership agreement. Our general partner has broad discretion to establish cash reserves that it
determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and
maintenance expenditures, reserves to stabilize distributions of cash to our unitholders, reserves to reduce debt or, as necessary,
reserves to comply with the terms of any of our agreements or obligations. We will be prohibited from making any distributions
to unitholders if it would cause an event of default or if an event of default exists under our credit agreement.
General Partner Interest. Our general partner is currently entitled to approximately 1.14% of all quarterly distributions that
we make prior to our liquidation based on its ownership of the general partner interest. As of February 15, 2017, our general
partner interest is represented by 834,391 general partner units. Our general partner has the right, but not the obligation, to
contribute a proportional amount of capital to us to maintain its general partner interest, up to 2%. The general partner's
proportionate interest in our quarterly distributions will be reduced if we issue additional units in the future and our general
partner does not contribute a proportional amount of capital to us to maintain its general partner interest.
Incentive Distribution Rights. As quarterly distributions exceed the MQD and other higher target distribution levels, our
general partner, as the holder of the IDRs, becomes entitled to increasing percentages (13%, 23% and 48%) of the distributions
after the MQD. Such higher target distribution levels have been achieved and we have been distributing 48% on the IDRs since
our distribution with respect to the fourth quarter of 2014. For additional information, see Note 12 – Partnership Equity and
Distributions to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data in this Form
10-K.
Conversion of Subordinated Units. Under the terms of our partnership agreement and upon the payment of our quarterly
cash distribution to unitholders on February 13, 2015, our subordination period ended. As a result, our 16,200,000 subordinated
units held by TD converted into common units on a one for one basis on February 17, 2015. The conversion of the subordinated
units did not impact the aggregate amount of cash distributions paid.
59
Performance Graph
The following performance graph compares the performance of our common units with the NYSE Composite Index Total
Return and the Alerian Total Return MLP Index during the period beginning on May 14, 2013, and ending on December 31,
2016. The graph assumes a $100 investment in our common units 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 Partners, LP or Affiliated Purchasers
None.
Item 6. Selected Financial Data
The historical financial statements included in this Annual Report reflect the combined results of operations of TIGT and
TMID, which we refer to collectively as "our Predecessor." As discussed further in Note 2 – Summary of Significant Accounting
Policies to the accompanying consolidated financial statements, the financial statements of our Predecessor for historical
periods beginning after November 13, 2012 have been recast to reflect the operations of Trailblazer, which was acquired on
April 1, 2014, and Pony Express, of which TEP acquired a controlling 33.3% membership interest effective September 1, 2014.
In connection with our initial public offering on May 17, 2013, TD contributed to us its equity interests in our Predecessor.
The term "TEP Pre-Predecessor" refers to the Tallgrass Energy Partners Pre-Predecessor, which represents the combined
results of operations of TIGT and TMID that were owned by Kinder Morgan Energy Partners, LP ("TEP Pre-Predecessor
Parent") prior to November 13, 2012, at which date TEP Pre-Predecessor Parent sold those assets, among others, to TD.
Financial information for the TEP Pre-Predecessor has not been recast to reflect the operations of Trailblazer and Pony
Express. The following discussion analyzes the financial condition and results of operations of our Predecessor. In certain
circumstances and for ease of reading we discuss the financial results of the Predecessor as being "our" financial results
during historic periods, although TIGT and TMID were owned by TD from November 13, 2012 until May 17, 2013, Trailblazer
was owned by TD from November 13, 2012 to March 31, 2014, and Pony Express was wholly-owned by TD from November 13,
2012 to August 31, 2014. As used in this Annual Report, unless the context otherwise requires, "we," "us," our," the
"Partnership," "TEP" and similar terms refer to Tallgrass Energy Partners, LP, together with its consolidated subsidiaries.
60
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 TEP for the periods and as of the dates
indicated. 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.
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.
TEP
Year Ended December 31,
2016
2015
2014
2013
Period from
Nov. 13 to
Dec. 31, 2012
Statement of operations data:
Revenue ...................................... $ 605,122
Operating income ....................... $ 256,370
Equity in earnings of
unconsolidated investment (2) ..... $
51,780
Net income (loss) ....................... $ 267,894
Net income (loss) attributable to
partners ....................................... $ 263,529
Net income allocable to limited
partners ....................................... $ 161,064
Net income per limited partner
unit - basic .................................. $
Net income per limited partner
unit - diluted ............................... $
2.23
2.26
Balance sheet data (at end of
period):
Property, plant and equipment,
net ............................................... $2,012,263
Unconsolidated investments (2) ... $ 461,915
Total assets ................................. $3,018,971
Long-term debt, net .................... $1,407,981
Long-term debt allocated from
TD............................................... $
(in thousands, except per unit amounts)
$ 536,197
$ 371,556
$ 290,526
$ 197,915
$
53,413
$
— $
717
$ 184,814
$ 160,546
$ 114,068
$
$
1.95
1.91
$
$
$
$
$
59,329
70,681
61,774
1.39
1.36
$
$
$
$
$
$
$
33,999
—
7,624
9,747
6,991
0.17
0.17
(1)
(1)
(1)
$2,025,018
$1,853,081
$1,116,806
$
— $
— $
1,255
$2,562,074
$2,457,197
$1,631,413
$ 753,000
$ 559,000
$ 135,000
TEP Pre-
Predecessor
Period from
January 1 to
November
12, 2012
(in thousands,
except per unit
amounts)
$
$
$
$
$
$
$
$
$
$
38,572
69
$
$
220,292
50,113
— $
(2,618)
(2,366)
$
$
—
51,496
51,496
N/A
N/A
N/A
N/A
N/A
N/A
726,754
$
717,486
— $
—
1,238,598
$
767,681
— $
390,491
$
—
—
— $
— $
— $
—
Other:
Distributions declared per
common unit............................... $
3.0700
$
2.3400
$
1.6000
$
0.7547
N/A
N/A
(1) The net income allocated to the limited partners was based upon the number of days between the closing of the IPO on
May 17, 2013 to December 31, 2013.
(2) Represents equity in earnings of our 25% membership interest in Rockies Express beginning in 2016, and our 50% equity
interest in Grasslands Water Services I, LLC ("GWSI") in periods prior to May 2014. For more information see Note 9 –
Investments in Unconsolidated Affiliates to our Consolidated Financial Statements in Item 8.—Financial Statements and
Supplementary Data in this Form 10-K.
61
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Historical periods have been recast to reflect the operations of Trailblazer, which was acquired on April 1, 2014, and Pony
Express, of which TEP acquired a controlling 33.3% membership interest effective September 1, 2014. TEP's subsequent
acquisitions of an additional 33.3% and 31.3% membership interest in Pony Express on March 1, 2015 and January 1, 2016,
respectively, represent acquisitions of noncontrolling interests. As a result, financial information for periods prior to those
transactions have not been recast to reflect the additional 33.3% and 31.3% membership interests. 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,
and Pony Express was wholly-owned by TD from November 13, 2012 to August 31, 2014.
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
We are a publicly traded, growth-oriented limited partnership formed in 2013 to own, operate, acquire and develop
midstream energy assets in North America. Our operations are located in and provide services to certain key United States
hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and
the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.
We intend to continue to leverage our relationship with TD and utilize the significant experience of our management team
to execute our growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of our existing
assets and expanding our systems through construction of additional assets. Our reportable business segments are:
•
•
•
Crude Oil Transportation & Logistics—the ownership and operation of a FERC-regulated crude oil pipeline system
and crude oil storage and terminalling facilities;
Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas
pipelines and integrated natural gas storage facilities; and
Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities,
the provision of water business services primarily to the oil and gas exploration and production industry and the
transportation of NGLs.
Additional information about our operations and assets is contained in the business overview included in Item 1.—
Business under "Overview" and "Our Assets."
Summary of Results for the Year Ended December 31, 2016
During 2016, we completed the acquisitions of an additional 31.3% membership interest in Pony Express, a 25%
membership interest in Rockies Express and an additional 8% membership interest in Water Solutions. In addition, we issued
$400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes") and received aggregate net
proceeds of $427.7 million from the issuance of 10,113,695 common units through a combination of public and private
issuances.
Net income attributable to partners for the year ended December 31, 2016 was $263.5 million, with Adjusted EBITDA and
Distributable Cash Flow (each as defined below under "Non-GAAP Financial Measures") of $423.5 million and $408.5
million, respectively, compared to net income attributable to partners for the year ended December 31, 2015 of $160.5 million,
with Adjusted EBITDA and Distributable Cash Flow of $252.3 million and $220.5 million, respectively. The increase in net
income, Adjusted EBITDA, and Distributable Cash Flow was largely driven by the ramping up of commercial operations at
Pony Express and the lateral in Northeast Colorado, our acquisition of an additional 31.3% membership interest in Pony
Express on January 1, 2016, and our acquisition of a 25% membership interest in Rockies Express on May 6, 2016, as
discussed further under "Results of Operations" below.
Recent Developments
Distribution Declared
On January 24, 2017, the Board of Directors of our general partner declared a cash distribution for the quarter
ended December 31, 2016 of $0.815 per common unit. The distribution was paid on February 14, 2017, to unitholders of record
on February 3, 2017.
62
Exercise of Call Option and Repurchase of Additional Common Units Owned by TD
On February 1, 2017, we exercised the remainder of the call option granted by TD, as discussed in Note 4 – Acquisitions,
covering 1,703,094 common units for a cash payment of $72.4 million, and we repurchased 736,262 common units from TD
for a negotiated cash payment of approximately $35.3 million, or $47.99 per common unit, which repurchase was approved by
the conflicts committee of the board of directors of our general partner. These 2,439,356 common units in the aggregate equal
the number of common units sold under our equity distribution agreements since November 3, 2016 and were deemed canceled
and no longer issued and outstanding as of such transaction date.
Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC
Effective January 1, 2017, we acquired 100% of the issued and outstanding membership interests in Terminals and 100%
of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $140 million.
Terminals owns and operates several fully operational assets providing storage capacity and additional injection points for
the Pony Express System, including the Sterling Terminal near Sterling, Colorado, with approximately 1.3 million bbls of
storage capacity and the Buckingham Terminal in Weld County, Colorado, with four truck unloading skids capable of receiving
up to approximately 16,000 bbls per day. Terminals also owns a 20% interest in the Deeprock Development, which owns the
Cushing Terminal in Cushing, Oklahoma, with approximately 2.3 million bbls of storage capacity. In addition, Terminals owns
projects currently under development, including approximately 550 acres in Cushing, Oklahoma and approximately 250 acres
in Guernsey, Wyoming which is under development to provide additional storage capacity and other potential service
opportunities.
NatGas is the operator of the Rockies Express Pipeline and receives a fee from Rockies Express as compensation for its
services.
Ultra Settlement
In early 2016, Ultra defaulted on its firm transportation service agreement with Rockies Express for approximately 0.2
Bcf/d through November 11, 2019 on the Rockies Express Pipeline and 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 U.S.
Bankruptcy Code in U.S. 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 an agreement to settle Rockies Express' approximately $303
million claim against Ultra's bankruptcy estate. The settlement agreement includes Ultra's agreement to: (i) make a cash
payment to Rockies Express of $150 million in accordance with the plan of reorganization, but no later than October 30, 2017;
and (ii) enter 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. The settlement is part of
Ultra's Chapter 11 reorganization plan, which must be submitted to the U.S. Bankruptcy Court for approval.
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.
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. Although crude oil and natural gas prices declined significantly from the second half of 2014 through the first
half of 2016, and could experience further declines or remain at or near current levels for the foreseeable future, we
nevertheless believe that prices may have stabilized during the latter part of 2016 and that the long-term prospects for continued
crude oil and natural gas production increases are favorable.
63
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. 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 continue to recover and stabilize.
Current Commodity Environment
Starting in the second half of 2014, the prices of crude oil, natural gas, and NGLs were extremely volatile and declined
significantly. This volatility and downward pressure on commodity prices continued through the first half of 2016. Such
volatility and reduced prices impact our business in several ways.
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, 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 until there is further commodity price recovery and stability in the markets. The commodity price declines over the
past two years 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. We intend to pursue acquisition
opportunities from third parties as they become available and expect to continue to acquire assets from TD's portfolio of
midstream assets, which includes TD's 50% interest in the Rockies Express Pipeline. We expect TD to retain its 2% ownership
interest in Pony Express for the foreseeable future. Pursuant to the TEP Omnibus Agreement, TD granted us the right of first
offer to acquire each of the remaining Retained Assets if TD decides to sell those assets. Other than its obligations under the
TEP Omnibus Agreement, TD is under no obligation to offer to sell us additional assets or to pursue acquisitions jointly with
us, and we are under no obligation to buy any assets from TD or pursue any such joint acquisitions. However, given the
significant economic interest in us held by TD and its affiliates, we believe TD will be incentivized to offer us the opportunity
to acquire its assets.
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, such as the use of drag reducing agents in our crude oil pipelines. For example, in
2014, Pony Express completed the conversion and construction of its approximately 698-mile crude oil pipeline commencing
in Guernsey, Wyoming, and terminating in Cushing, Oklahoma. In 2015, Pony Express completed the construction of an
approximately 66-mile lateral in Northeast Colorado commencing in Weld County, Colorado, and interconnecting with the
pipeline just east of Sterling, Colorado. 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.
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.
64
In addition, the Federal Reserve increased short-term interest rates which marginally impacted the rates on our floating rate
revolving credit facility. 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. 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 Distributable Cash Flow. Adjusted EBITDA and Distributable Cash Flow are non-GAAP measures and are
defined below.
Contract Profile and Volumes
Our results are driven primarily by the volume of crude oil transportation, storage and terminalling capacity, natural gas
transportation and storage capacity, NGL transportation capacity, and water transportation, gathering and disposal capacity
under firm fee contracts, as well as the volume of natural gas that we process and the fees assessed for such services.
Operating Costs and Expenses
The primary components of our operating costs and expenses that we evaluate include cost of sales, cost of transportation
services, operations and maintenance and general and administrative costs. Our operating expenses are driven primarily by
expenses related to the operation, maintenance and growth of our asset base.
Adjusted EBITDA and Distributable Cash Flow
Adjusted EBITDA and Distributable Cash Flow 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 partnerships in the midstream energy industry,
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 distributions to our unitholders;
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the returns on investment of various expansion
and growth opportunities.
We believe that the presentation of Adjusted EBITDA and Distributable Cash Flow provides useful information to
investors in assessing our financial condition and results of operations. Adjusted EBITDA and Distributable Cash Flow 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 Distributable Cash
Flow be considered alternatives to available cash, operating surplus, distributions of available cash from operating surplus or
other definitions in our partnership agreement. Adjusted EBITDA and Distributable Cash Flow 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 Distributable Cash Flow may be defined differently by other companies
in our industry, our definition of Adjusted EBITDA and Distributable Cash Flow 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. We also use Distributable Cash Flow, which we generally define as Adjusted EBITDA, plus
deficiency payments received from or utilized by our customers and preferred distributions received from Pony Express in
excess of its distributable cash flow attributable to our net interest, less cash interest expense, maintenance capital expenditures,
distributions to noncontrolling interests in excess of earnings allocated to noncontrolling interests, and certain cash reserves
permitted by our partnership agreement, to analyze our performance.
65
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. As discussed in Note 2 – Summary of Significant Accounting Policies, prior to
December 31, 2015, we received preferred distributions from Pony Express. Effective January 1, 2016 with our acquisition of
an additional 31.3% membership interest in Pony Express, distributable cash flow from Pony Express is distributed pro rata
based on ownership. Pony Express collects deficiency payments for barrels committed by the customer 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 by TEP. Earnings at Pony
Express prior to December 31, 2015 were allocated between TEP and noncontrolling interests in accordance with a substantive
profit sharing arrangement rather than pro rata by ownership. Distributions made by Pony Express to its noncontrolling
interests reduce the Distributable Cash Flow available to TEP.
66
Distributable Cash Flow and Adjusted EBITDA are not presentations made in accordance with GAAP. The following table
presents a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities and a reconciliation
of Distributable Cash Flow to net cash provided by operating activities, the most directly comparable GAAP financial
measures, for each of the periods indicated:
Reconciliation of Adjusted EBITDA to Net Income
Net income attributable to partners .......................................................... $
Add:
Interest expense, net of noncontrolling interest...................................
Depreciation and amortization expense, net of noncontrolling
interest .................................................................................................
Distributions from unconsolidated investment....................................
Non-cash loss (gain) related to derivative instruments, net of
noncontrolling interest.........................................................................
Non-cash compensation expense (1) .....................................................
Non-cash loss from disposal of assets .................................................
Loss on extinguishment of debt...........................................................
Less:
Equity in earnings of unconsolidated investment................................
Non-cash loss allocated to noncontrolling interest..............................
Gain on remeasurement of unconsolidated investment.......................
Adjusted EBITDA.................................................................................... $
Reconciliation of Adjusted EBITDA and Distributable Cash Flow to
Net Cash Provided by Operating Activities
Net cash provided by operating activities ................................................ $
Add:
Interest expense, net of noncontrolling interest...................................
Other, including changes in operating working capital.......................
Adjusted EBITDA.................................................................................... $
Add:
Year Ended December 31,
2016
2015
(in thousands)
2014
263,529
$
160,546
$
70,681
40,688
85,971
75,900
1,547
5,780
1,849
—
15,517
75,529
—
—
5,103
4,795
226
(51,780)
—
—
423,484
$
—
(9,377)
—
252,339
$
7,648
45,389
1,464
(184)
5,136
—
—
(717)
(10,151)
(9,388)
109,878
409,484
$
289,296
$
79,444
40,688
(26,688)
423,484
$
15,517
(52,474)
252,339
$
7,648
22,786
109,878
Deficiency payments received, net......................................................
33,496
16,511
Pony Express preferred distributions in excess of distributable cash
flow attributable to Pony Express........................................................
—
—
Less:
Cash interest cost.................................................................................
Maintenance capital expenditures, net ................................................
Distributions to noncontrolling interest in excess of earnings ............
Cash flow attributable to predecessor operations................................
Distributable Cash Flow........................................................................... $
(37,110)
(11,323)
—
—
408,547
$
(13,746)
(12,123)
(22,479)
—
220,502
$
5,378
5,429
(6,266)
(9,913)
(5,361)
(3,086)
96,059
(1) Represents TEP's portion of non-cash compensation expense related to Equity Participation Units, excluding amounts
allocated to TD, as discussed in Note 16 – Equity-Based Compensation.
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 Adjusted EBITDA to Operating Income in the Crude
Oil Transportation & Logistics Segment (1)
Operating income ..................................................................................... $
Add:
Depreciation and amortization expense, net of noncontrolling
interest .................................................................................................
Adjusted EBITDA attributable to noncontrolling interests.................
Non-cash loss related to derivative instruments, net of
noncontrolling interest.........................................................................
Less:
Non-cash loss allocated to noncontrolling interest..............................
Segment Adjusted EBITDA..................................................................... $
Reconciliation of Adjusted EBITDA to Operating Income in the
Natural Gas Transportation & Logistics Segment (1)
Operating income ..................................................................................... $
Add:
Depreciation and amortization expense...............................................
Distributions from unconsolidated investment....................................
Non-cash loss (gain) related to derivative instruments .......................
Other income, net ................................................................................
Segment Adjusted EBITDA..................................................................... $
Reconciliation of Adjusted EBITDA to Operating Income in the
Processing & Logistics Segment (1)
Operating income ..................................................................................... $
Add:
Depreciation and amortization expense, net of noncontrolling
interest .................................................................................................
Non-cash gain related to derivative instruments .................................
Non-cash loss from disposal of assets .................................................
Distributions from unconsolidated investment....................................
Adjusted EBITDA attributable to noncontrolling interests.................
Segment Adjusted EBITDA..................................................................... $
Total Segment Adjusted EBITDA............................................................ $
Corporate general and administrative costs.........................................
Elimination of intersegment activity ...................................................
Total Adjusted EBITDA........................................................................... $
Year Ended December 31,
2016
2015
(in thousands)
2014
215,784
$
159,467
$
3,601
52,464
(4,288)
431
—
264,391
$
39,359
(24,245)
—
10,553
11,708
—
(9,377)
165,204
$
(10,151)
15,711
49,907
$
41,802
$
40,887
20,976
75,900
116
1,723
22,927
—
—
2,639
23,788
—
(184)
3,102
148,622
$
67,368
$
67,593
1,081
$
4,728
$
20,577
12,531
(291)
1,849
—
(77)
15,093
428,106
(4,622)
—
$
$
13,243
—
4,795
—
(20)
22,746
255,318
(2,979)
—
$
$
423,484
$
252,339
$
11,048
—
—
1,464
—
33,089
116,393
(2,500)
(4,015)
109,878
(1) Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for
the Crude Oil Transportation & Logistics, Natural Gas Transportation & Logistics, and Processing & Logistics segments.
For reconciliations to the consolidated financial data, see Note 19 – Reportable Segments to our Consolidated Financial
Statements in Item 8.—Financial Statements and Supplementary Data in this Form 10-K.
68
Results of Operations
The following provides a summary of our consolidated results of operations for the periods indicated:
Year Ended December 31,
2016
2015
(in thousands, except operating data)
2014
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 (exclusive of depreciation and amortization shown
below) ..................................................................................................
Cost of transportation services (exclusive of depreciation and
amortization shown below) .................................................................
Operations and maintenance................................................................
Depreciation and amortization ............................................................
General and administrative..................................................................
Taxes, other than income taxes............................................................
Loss on disposal of assets....................................................................
Total Operating Costs and Expenses ..............................................
Operating Income .....................................................................................
Other Income (Expense):
Interest expense, net .................................................................................
Unrealized loss on derivative instrument .................................................
Equity in earnings of unconsolidated investment ....................................
Gain on remeasurement of unconsolidated investment............................
Other income, net .....................................................................................
Total Other Income (Expense) .................................................................
Net income ...............................................................................................
Net (income) loss attributable to noncontrolling interests ..................
Net income attributable to partners .......................................................... $
Other Financial Data
374,949
$
300,436
$
119,962
77,394
32,817
605,122
71,920
58,341
53,386
84,896
53,633
24,727
1,849
348,752
256,370
(40,688)
(1,291)
51,780
—
1,723
11,524
267,894
(4,365)
263,529
119,895
82,133
33,733
536,197
75,285
53,597
49,138
83,476
50,195
21,796
4,795
338,282
197,915
(15,514)
—
—
—
2,413
(13,101)
184,814
(24,268)
160,546
252,339
236,256
1,679
122
$
$
$
$
28,343
126,733
181,249
35,231
371,556
167,545
24,109
39,577
47,048
33,160
6,704
—
318,143
53,413
(7,292)
—
717
9,388
3,103
5,916
59,329
11,352
70,681
109,878
85,229
1,698
152
Adjusted EBITDA (1) ........................................................................... $
423,484
Operating Data:
Crude oil transportation average throughput (Bbls/d) (2).....................
Gas transportation average firm contracted volumes (MMcf/d) (3) .....
Natural gas processing inlet volumes (MMcf/d) .................................
285,507
1,627
103
(1) For more information regarding Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly
comparable GAAP measure, please see "Non-GAAP Financial Measures" above.
(2) Approximate average daily throughput for the years ended December 31, 2015 and 2014 is reflective of the volumetric
ramp up due to commercial in-service of the Pony Express System beginning in October 2014, including the lateral in
Northeast Colorado in the second quarter of 2015, and delays in the construction and expansion efforts of third-party
pipelines with which Pony Express shares joint tariffs.
(3) Volumes transported under firm fee contracts, excluding Rockies Express.
69
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Revenues. Total revenues were $605.1 million for the year ended December 31, 2016, compared to $536.2 million for the
year ended December 31, 2015, which represents an increase of $68.9 million, or 13%, in total revenues. The overall increase
in revenue was largely driven by increased revenues of $76.3 million in the Crude Oil Transportation & Logistics segment,
partially offset by decreased revenues of $4.3 million and $2.8 million in the Processing & Logistics and Natural Gas
Transportation & Logistics segments, respectively, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $348.8 million for the year ended December 31, 2016
compared to $338.3 million for the year ended December 31, 2015, which represents an increase of $10.5 million, or 3%. The
overall increase in operating costs and expenses is primarily driven by increased operating costs and expenses of $20.0
million in the Crude Oil Transportation & Logistics segment, partially offset by decreased operating costs and expenses
of $10.9 million and $0.7 million in the Natural Gas Transportation & Logistics and Processing & Logistics segments,
respectively, as discussed further below, as well as a $2.3 million increase in corporate general and administrative costs due to
increased overhead costs allocated from TD.
Interest expense, net. Interest expense of $40.7 million for the year ended December 31, 2016 was primarily composed of
interest and fees associated with our revolving credit facility and the 2024 Notes issued on September 1, 2016. Interest expense
of $15.5 million for the year ended December 31, 2015 was primarily composed of interest and fees associated with our
revolving credit facility, partially offset by interest income of $0.4 million on the cash balance swept to TD under the Pony
Express cash management agreement. The increase in interest and fees in 2016 is primarily associated with our revolving credit
facility due to increased borrowings to fund a portion of our 2015 acquisitions and our recent acquisitions of an additional
31.3% membership interest in Pony Express effective January 1, 2016 and a 25% membership interest in Rockies Express
effective May 6, 2016, as well as the higher incremental borrowing rate on the 2024 Notes, the proceeds of which were used to
repay borrowings under our revolving credit facility.
Unrealized loss on derivative instrument. Unrealized loss on derivative instrument of $1.3 million represents the change in
fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony
Express effective January 1, 2016.
Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $51.8 million for the
year ended December 31, 2016 reflects our portion of earnings and the amortization of a negative basis difference of $9.1
million associated with our acquisition of a 25% membership interest in Rockies Express effective May 6, 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 Interior and Rockies Express as discussed in Note 18 – Legal and
Environmental Matters.
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, 2016
was $1.7 million compared to $2.4 million for the year ended December 31, 2015. The decrease in other income was driven by
lower income related to reimbursable projects at TIGT due to a contract termination during the year ended December 31, 2016.
Net (income) loss attributable to noncontrolling interests. Net income attributable to noncontrolling interests of $4.4
million for the year ended December 31, 2016 primarily reflects the net income allocated to TD's 2% noncontrolling interest in
Pony Express. Net income attributable to noncontrolling interest of $24.3 million for the year ended December 31, 2015
primarily reflects the net income allocated to TD's 66.7% noncontrolling interest in Pony Express for the period from January
1, 2015 to February 28, 2015 and TD's 33.3% noncontrolling interest for the period from March 1, 2015 to December 31, 2015.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Revenues. Total revenues were $536.2 million for the year ended December 31, 2015, compared to $371.6 million for the
year ended December 31, 2014, which represents an increase of $164.6 million, or 44%, in total revenues. The
overall increase in revenue was primarily driven by increased revenues of $275.9 million in the Crude Oil Transportation &
Logistics segment, partially offset by decreases in revenues of $102.7 million and $8.4 million in the Processing & Logistics
and Natural Gas Transportation & Logistics segments, respectively, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $338.3 million for the year ended December 31, 2015
compared to $318.1 million for the year ended December 31, 2014, which represents an increase of $20.1 million, or 6%. The
overall increase in operating costs and expenses was primarily driven by increased operating costs and expenses of $120.0
million in the Crude Oil Transportation & Logistics segment, partially offset by decreases in operating costs and expenses of
$86.8 million and $9.3 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments,
respectively, as discussed further below.
70
Interest expense, net. Interest expense of $15.5 million for the year ended December 31, 2015 was primarily composed of
interest and fees associated with TEP's revolving credit facility, partially offset by interest income of $0.4 million on the cash
balance swept to TD under the Pony Express cash management agreement. Interest expense of $7.3 million for the year ended
December 31, 2014 was primarily composed of interest and fees associated with TEP's revolving credit facility, partially offset
by interest income of $1.5 million on the cash balance swept to TD under the Pony Express cash management agreement. The
increase in interest and fees associated with TEP's revolving credit facility in 2015 was driven by increased borrowings
throughout 2014 and 2015 to fund the acquisitions of Trailblazer and a 66.7% membership interest in Pony Express.
Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.4
million for the year ended December 31, 2014 was related to the remeasurement to fair value of our original 50% equity
investment in Grasslands Water Services I, LLC ("GWSI") in connection with TEP's consolidation of the Water Solutions
business on May 13, 2014.
Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.7 million for
the year ended December 31, 2014 was related to our investment in GWSI prior to TEP's consolidation of the Water Solutions
business on May 13, 2014.
Other income, net. Other income, net typically includes rental income, income earned from certain customers related to the
capital costs we incurred to connect these customers to our system, and the allowance for funds used during construction at our
regulated entities. Other income for the year ended December 31, 2015 was $2.4 million compared to $3.1 million for the year
ended December 31, 2014.
Net (income) loss attributable to noncontrolling interests. Net income attributable to noncontrolling interests of $24.3
million for the year ended December 31, 2015 primarily reflects the net income allocated to TD's 66.7% noncontrolling interest
in Pony Express for the period from January 1, 2015 to February 28, 2015 and TD's 33.3% noncontrolling interest for the
period from March 1, 2015 to December 31, 2015. Net loss attributable to noncontrolling interest of $11.4 million for the year
ended December 31, 2014 primarily reflects TD's 66.7% noncontrolling interest in Pony Express.
The following provides a summary of our Crude Oil Transportation & Logistics segment results of operations for the
periods indicated:
Segment Financial Data – Crude Oil Transportation & Logistics (1)
2016
Year Ended December 31,
2015
(in thousands)
2014
Revenues:
Crude oil transportation services............................................................. $
Sales of natural gas, NGLs, and crude oil...............................................
Total revenues.....................................................................................
Operating costs and expenses:
374,949
$
300,436
$
28,343
5,554
380,503
3,791
304,227
Cost of sales ............................................................................................
Cost of transportation services ................................................................
Operations and maintenance ...................................................................
Depreciation and amortization ................................................................
General and administrative .....................................................................
Taxes, other than income taxes ...............................................................
4,728
55,519
13,075
51,362
20,650
19,385
4,257
47,367
8,795
47,168
20,620
16,553
Total operating costs and expenses ....................................................
164,719
144,760
Operating income
$
215,784
$
159,467
$
(1) Segment results as presented represent total revenue and operating income, including intersegment activity. For
reconciliations to the consolidated financial data, see Note 19 – Reportable Segments to our Consolidated Financial
Statements in Item 8.—Financial Statements and Supplementary Data in this Form 10-K.
71
—
28,343
—
7,025
717
12,067
4,683
250
24,742
3,601
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Revenues. Crude Oil Transportation & Logistics segment revenues were $380.5 million for the year ended December 31,
2016, compared to $304.2 million for the year ended December 31, 2015, which represents an increase of $76.3 million, or
25%, in segment revenues due to a $74.5 million increase in crude oil transportation services revenue and a $3.8 million
increase in sales of natural gas, NGLs, and crude oil primarily due to increased volumes sold during the year ended December
31, 2016. The increase in crude oil transportation services was primarily driven by a $42.6 million increase in revenue from a
full period of operations on the lateral in Northeast Colorado, which began commercial operations during the second quarter of
2015, a $19.6 million increase related to the activation of one of our joint tariffs in the second quarter of 2015, and lower
revenue of $9.8 million during the year ended December 31, 2015 due to a force majeure at one of our joint tariff partners.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were
$164.7 million for the year ended December 31, 2016 compared to $144.8 million for the year ended December 31, 2015,
which represents an increase of $20.0 million, or 14%. The overall increase in operating costs and expenses was primarily
driven by an $8.2 million increase in cost of transportation services, primarily due to $4.2 million associated with drag-
reduction agents and higher electrical costs at pump stations associated with increased transportation volumes, and increases of
$4.3 million, $4.2 million, and $2.8 million in operations and maintenance costs, depreciation and amortization, and taxes,
other than income taxes, respectively, all primarily driven by the costs associated with a full period of operations on the lateral
in Northeast Colorado.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Revenues. Crude Oil Transportation & Logistics segment revenues were $304.2 million for the year ended December 31,
2015 compared to $28.3 million for the year ended December 31, 2014. Revenue for the year ended December 31, 2015
represents a full year of operations at Pony Express, including approximately $62.6 million of revenue from a partial year of
operations on the lateral in Northeast Colorado, which began commercial operations during the second quarter of 2015, and
approximately $32.8 million related to the activation of one of our joint tariffs in the second quarter of 2015. Revenue for the
year ended December 31, 2014 represents a partial year of operations at the mainline portion of the Pony Express System,
which began commercial operations in October 2014.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment
were $144.8 million for the year ended December 31, 2015 compared to $24.7 million for the year ended December 31, 2014.
Operating costs and expenses for the year ended December 31, 2015 represents a full year of operations at Pony Express as
well as a partial year of operations on the lateral in Northeast Colorado, which began commercial operations during the second
quarter of 2015. Operating costs and expenses for the year ended December 31, 2014 represents a partial year of operations at
the mainline portion of the Pony Express System, which began commercial operations in October 2014.
The following provides a summary of our Natural Gas Transportation & Logistics segment results of operations for the
periods indicated:
Segment Financial Data – Natural Gas Transportation & Logistics (1)
2016
2015
2014
Year Ended December 31,
(in thousands)
Revenues:
Natural gas transportation services ......................................................... $
Sales of natural gas, NGLs, and crude oil...............................................
Processing and other revenues ................................................................
125,603
$
125,279
$
131,990
3,241
25
6,346
32
7,868
222
Total revenues.....................................................................................
128,869
131,657
140,080
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 ....................................................
3,804
5,051
28,458
20,976
16,335
4,338
78,962
6,342
10,927
27,767
22,927
17,052
4,840
89,855
Operating income......................................................................................... $
49,907
$
41,802
$
7,025
18,090
27,422
23,788
16,767
6,101
99,193
40,887
72
(1) Segment results as presented represent total revenue and operating income, including intersegment activity. For
reconciliations to the consolidated financial data, see Note 19 – Reportable Segments to our Consolidated Financial
Statements in Item 8.—Financial Statements and Supplementary Data in this Form 10-K.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Revenues. Natural Gas Transportation & Logistics segment revenues were $128.9 million for the year ended December 31,
2016, compared to $131.7 million for the year ended December 31, 2015, which represents a decrease of $2.8 million, or 2%,
in segment revenues driven by a $3.1 million decrease in sales of natural gas, NGLs, and crude oil as a result of lower volumes
of natural gas sold. The decrease in sales of natural gas, NGLs, and crude oil was partially offset by a $0.3 million increase in
natural gas transportation services primarily driven by a $2.3 million increase at TIGT, partially offset by a $1.9 million
decrease at Trailblazer due to warmer weather in the first quarter of 2016, resulting in lower volumes transported during the
year ended December 31, 2016. The increase in natural gas transportation services revenue at TIGT was primarily driven by
increased tariff rates, 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 17 – Regulatory Matters.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were
$79.0 million for the year ended December 31, 2016 compared to $89.9 million for the year ended December 31, 2015, which
represents a decrease of $10.9 million, or 12%. The overall decrease in operating costs and expenses was primarily driven by
a $5.9 million decrease in cost of transportation services due to lower costs associated with fuel reimbursements as a result of
the change in the fuel recovery structure discussed above, a $2.5 million decrease in cost of sales due to lower volumes of
natural gas sold, and a $2.0 million decrease in depreciation and amortization due to lower depreciation rates as of May 1, 2016
as a result of the TIGT rate case settlement.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Revenues. Natural Gas Transportation & Logistics segment revenues were $131.7 million for the year ended December 31,
2015, compared to $140.1 million for the year ended December 31, 2014, which represents an $8.4 million, or 6%, decrease in
segment revenues primarily due to a $6.7 million decrease in natural gas transportation services revenue driven by lower fuel
reimbursements as a result of decreased prices and a $1.5 million decrease in revenue from the sales of natural gas, NGLs, and
crude oil as a result of a 46% decrease in natural gas prices, partially offset by favorable hedge settlements and increased
volumes sold.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were
$89.9 million for the year ended December 31, 2015 compared to $99.2 million for the year ended December 31, 2014, which
represents a decrease of $9.3 million, or 9%. The overall decrease in operating costs and expenses was primarily driven by a
$7.2 million decrease in the cost of transportation services, due to lower fuel reimbursements as a result of decreased prices, a
$1.3 million decrease in taxes, other than income taxes, due to revised property tax estimates as a result of successful appeals
with state taxing authorities on the assessed value of property, a $0.9 million decrease in depreciation and amortization driven
by a change in rates at Trailblazer as a result of the rate case settlement in 2014, and a $0.7 million decrease in cost of sales, due
to a 51% decrease in natural gas prices, partially offset by increased volumes sold.
73
The following provides a summary of our Processing & Logistics segment results of operations for the periods indicated:
Segment Financial Data – Processing & Logistics (1)
Revenues:
Year Ended December 31,
2016
2015
2014
(in thousands)
Sales of natural gas, NGLs, and crude oil............................................... $
Processing and other revenues ................................................................
Total revenues.....................................................................................
68,599
$
71,996
$
32,792
101,391
33,701
105,697
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 ...............................................................
Loss on disposal of assets .......................................................................
63,646
3,154
11,853
12,558
6,246
1,004
1,849
64,686
687
12,576
13,381
4,441
403
4,795
Total operating costs and expenses ....................................................
100,310
100,969
Operating income......................................................................................... $
1,081
$
4,728
$
173,381
35,009
208,390
160,520
236
11,438
11,193
4,073
353
—
187,813
20,577
(1) Segment results as presented represent total revenue and operating income, including intersegment activity. For
reconciliations to the consolidated financial data, see Note 19 – Reportable Segments to our Consolidated Financial
Statements in Item 8.—Financial Statements and Supplementary Data in this Form 10-K.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Revenues. Processing & Logistics segment revenues were $101.4 million for the year ended December 31, 2016, compared
to $105.7 million for the year ended December 31, 2015, which represents a $4.3 million, or 4%, decrease in segment revenues.
The decrease in segment revenues was primarily due to a $3.4 million decrease in the sales of natural gas, NGLs, and crude oil
driven by lower NGL and natural gas sales due to lower volumes processed, partially offset by increased NGL prices, and a
$0.9 million decrease in processing and other revenues driven by lower processing fees of $4.9 million due to decreased
volumes processed, partially offset by a $4.0 million increase in revenue primarily attributable to the recently acquired Western
and West Texas assets.
Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $100.3 million
for the year ended December 31, 2016 compared to $101.0 million for the year ended December 31, 2015, which represents a
decrease of $0.7 million, or 1%. The decrease in operating costs and expenses was driven by (i) a decrease of $2.9 million in
loss on disposal of assets as a result of the $1.8 million loss on assets destroyed by fire as a result of a lightning strike during
the year ended December 31, 2016, compared to a $4.8 million non-cash loss recognized on the sale of compressor and other
assets in 2015; (ii) a decrease of $1.0 million in cost of sales, driven by decreased NGL volumes processed as discussed above;
(iii) a $0.8 million decrease in depreciation and amortization driven by an intangible asset becoming fully amortized as of
December 31, 2015, partially offset by increased depreciation related to the new NGL transportation line; and (iv) a $0.7
million decrease in operations and maintenance costs due to less downtime for plant maintenance activities during the year
ended December 31, 2016 compared to the year ended December 31, 2015, partially offset by higher costs associated with the
recently acquired Western and West Texas assets. These decreases were partially offset by (i) a $2.5 million increase in cost of
transportation services due to costs associated with Western, which was acquired on December 16, 2015; (ii) a $1.8 million
increase in general and administrative costs due to increased costs allocated to Water Solutions as a result of increased
operating income related to our acquisitions of Western and West Texas; and (iii) a $0.6 million increase in taxes, other than
income taxes, due to higher property tax estimates for 2016 as a result of the Western acquisition.
74
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Revenues. Processing & Logistics segment revenues were $105.7 million for the year ended December 31, 2015, compared
to $208.4 million for the year ended December 31, 2014, which represents a $102.7 million, or 49%, decrease in segment
revenues. The decrease in segment revenues was primarily due to a $101.4 million decrease in the sales of natural gas, NGLs,
and crude oil driven by a 58% decrease in NGL prices and lower volumes processed, and a $1.3 million decrease in processing
and other revenues driven by lower processing fees at TMID due to decreased volumes processed under a large, fee-based
contract, partially offset by increased revenue at Water Solutions, including water transportation services and revenue
associated with a contract to construct a water pipeline for a customer during the year ended December 31, 2015. Prior to its
consolidation in May 2014, TEP's investment in Water Solutions was accounted for under the equity method of accounting and
as a result TEP recognized no revenues from Water Solutions for the period from January 1, 2014 to May 13, 2014.
Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $101.0 million
for the year ended December 31, 2015 compared to $187.8 million for the year ended December 31, 2014, which represents a
decrease of $86.8 million, or 46%. The decrease in operating costs and expenses was driven by a decrease of $95.8 million in
cost of sales, primarily due to decreased NGL prices and volumes processed as discussed above. The decrease in cost of sales
was partially offset by $4.8 million of non-cash losses recognized on the sale of compressor and other assets in 2015, and
overall increases in the cost of transportation services, operations and maintenance costs, depreciation and amortization, and
general and administrative costs, all primarily driven by the costs associated with Water Solutions, which was consolidated in
May 2014.
Liquidity and Capital Resources Overview
Our primary sources of liquidity for the year ended December 31, 2016 were proceeds from the issuance of long-term debt
as discussed further below, borrowings under our revolving credit facility, cash generated from operations, and proceeds from
the issuance of common units. We expect our sources of liquidity in the future to include:
•
•
•
cash generated from our operations;
borrowing capacity available under our revolving credit facility; and
future issuances of additional partnership units and/or debt securities.
We believe that cash on hand, cash generated from operations and availability under our revolving credit facility will be
adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements and our
planned cash distributions to unitholders. We believe that future internal growth projects or potential acquisitions will be funded
primarily through a combination of borrowings under our revolving credit facility and issuances of debt and/or equity
securities.
Our total liquidity as of December 31, 2016 and 2015 was as follows:
December 31, 2016
December 31, 2015
Cash on hand ............................................................................................... $
(in thousands)
1,873
$
Total capacity under the revolving credit facility (1) ...............................
Less: Outstanding borrowings under the revolving credit facility (2) .....
Available capacity under the revolving credit facility.......................
Total liquidity .............................................................................................. $
1,750,000
(1,015,000)
735,000
736,873
$
1,611
1,100,000
(753,000)
347,000
348,611
(1) Effective January 4, 2016, in connection with the acquisition of an additional 31.3% membership interest in Pony
Express, TEP exercised the committed accordion feature to increase the total capacity of the revolving credit facility to
$1.5 billion. In connection with the acquisition of a 25% membership interest in Rockies Express, TEP amended the
revolving credit facility to increase the total capacity to $1.75 billion, which increase became effective May 6, 2016.
(2) As of February 3, 2017, our outstanding borrowings under the revolving credit facility were approximately $1.130
billion.
75
Revolving Credit Facility
We have a senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of
lenders (as amended, the "Credit Agreement") which will mature on May 17, 2018. As of December 31, 2016, the revolving
credit facility has a total capacity of $1.75 billion and includes a $75 million sublimit for letters of credit and a $60 million
sublimit for swing line loans. The unused portion of the revolving credit facility is subject to a commitment fee, which ranges
from 0.300% to 0.500%, based on our total leverage ratio. As of December 31, 2016, the weighted average interest rate on
outstanding borrowings was 2.48%. During the year ended December 31, 2016, our weighted average effective interest rate,
including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 2.75%.
The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict
our ability (as well as the ability of our restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on
assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default
under the credit agreement then exists or would result from making such a distribution), change the nature of our business,
engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates
and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, we are required to maintain a consolidated
leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following
the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of
December 31, 2016, we are in compliance with the covenants required under the revolving credit facility.
Senior Unsecured Notes
On September 1, 2016, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the
Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016
(the "Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of the Issuers' 5.50% senior
notes due 2024 (the "2024 Notes"). TEP used the net proceeds of the issuance to repay outstanding borrowings under its
existing revolving credit facility.
The 2024 Notes are general unsecured senior obligations of the Issuers. The 2024 Notes are unconditionally guaranteed
jointly and severally on a senior unsecured basis by TEP's existing direct and indirect wholly owned subsidiaries (other than the
Co-Issuer) and certain of TEP's future subsidiaries (the "Guarantors"). The 2024 Notes rank equal in right of payment with all
existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of
the Issuers. The 2024 Notes will mature on September 15, 2024 and interest on the 2024 Notes is payable in cash semi-annually
in arrears on each March 15 and September 15, commencing March 15, 2017. TEP may redeem the 2024 Notes prior to their
scheduled maturity at the applicable redemption price set forth in the Indenture, plus accrued and unpaid interest.
The Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries
to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness;
(iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments;
(v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or
into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity
interests in subsidiaries; and (viii) enter into transactions with affiliates. As of December 31, 2016, we are in compliance with
the covenants required under the 2024 Notes.
Equity Distribution Agreements
On October 31, 2014, we entered into an equity distribution agreement pursuant to which we may sell from time to time
through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate
offering price of up to $200 million. On May 13, 2015, the amount was subsequently amended to $100.2 million in order to
account for follow-on equity offerings under our S-3 shelf registration statement. On May 17, 2016, we entered into a new
equity distribution agreement allowing for the sale of common units with an aggregate offering price of up to $657.5 million.
Sales of common units, if any, will be made by means of ordinary brokers' transactions, to or through a market maker or
directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed
by the Partnership and one or more of the managers. We intend to use the net cash proceeds from any sale of the units for
general partnership purposes, which may include, among other things, the Partnership's exercise of the call option with respect
to the 6,518,000 common units issued to TD in connection with the Partnership's acquisition of an additional 31.3% of Pony
Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to
working capital.
76
During the year ended December 31, 2016, we issued and sold 7,696,708 common units with a weighted average sales
price of $44.46 per unit under our equity distribution agreements for net cash proceeds of approximately $337.7 million (net of
approximately $4.5 million in commissions and professional service expenses). During the period from January 1, 2017 to
February 15, 2017, we issued and sold an additional 2,075,546 common units with a weighted average sales price of $48.19 per
unit under our equity distribution agreements for net cash proceeds of approximately $99.0 million (net of approximately $1.0
million in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as
described above.
During the year ended December 31, 2015, we issued and sold 65,744 common units with a weighted average sales price
of $45.58 per unit under our equity distribution agreement for net cash proceeds of approximately $3.0 million (net of
approximately $30,000 in commissions and professional service expenses). We used the net cash proceeds for general
partnership purposes as described above.
During the year ended December 31, 2014, we issued and sold 28,625 common units with a weighted average sales price
of $44.20 per unit under our equity distribution agreement for net cash proceeds of approximately $1.1 million (net of
approximately $215,000 in commissions and professional service expenses). We used the net cash proceeds for general
partnership purposes as described above.
Private Placement
On April 28, 2016, we issued an aggregate of 2,416,987 common units for net cash proceeds of $90.0 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.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. While various other factors may impact
our working capital requirements from period to period, our working capital requirements have typically been, and we expect
will continue to be, driven by changes in accounts receivable, accounts payable and deferred revenue. We manage our working
capital needs through borrowings and repayments of borrowings under our revolving credit facility. Factors impacting changes
in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, and
the level of spending for capital expenditures. Changes in the market prices of energy commodities, primarily NGLs, 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 crude oil transported, the amount of deficiency payments
received, and the volume of prior deficiencies utilized during the period.
As of December 31, 2016, we had a working capital deficit of $38.3 million compared to a working capital deficit of $11.7
million at December 31, 2015, which represents a decrease in working capital of $26.6 million. The overall decrease in
working capital was primarily attributable to changes in the following components:
•
•
•
an increase in deferred revenue of $34.2 million primarily from deficiency payments collected by Pony Express;
an increase in accrued liabilities of $6.5 million primarily due to $7.3 million of interest accrued at December 31, 2016
associated with the 2024 Notes issued on September 1, 2016, partially offset by a decrease in environmental accruals
due to remediation spending during the year ended December 31, 2016; and
an increase in accrued taxes of $2.5 million as a result of higher tax assessments for 2016 due to the Pony Express
lateral in Northeast Colorado and the recently acquired Western assets, partially offset by reduced assessments at
certain assets as a result of successful appeals with state taxing authorities on the assessed value of property.
These working capital decreases were partially offset by:
•
•
an increase of $11.0 million in derivative assets at fair value as a result of the call option derivative asset remaining as
of December 31, 2016; and
an increase of $4.0 million in prepayments and other current assets as a result of prepayment of insurance policies by
TEP, which had previously been paid by TD and reimbursed by TEP as they were incurred.
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.
77
Cash Flows
The following table and discussion presents a summary of our cash flow for the periods indicated:
Year Ended December 31,
2016
2015
(in thousands)
2014
Net cash provided by (used in):
Operating activities ............................................................ $
Investing activities.............................................................. $
Financing activities ............................................................ $
409,484
$
(581,704) $
$
172,482
289,296
$
(845,270) $
$
556,718
79,444
(1,102,729)
1,024,152
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Operating Activities. Cash flows provided by operating activities were $409.5 million and $289.3 million for the years
ended December 31, 2016 and 2015, respectively. The increase in net cash flows provided by operating activities of $120.2
million was primarily driven by the increase in operating results as discussed above, $51.8 million of distributions received
from Rockies Express, and a net increase in cash inflows from changes in working capital, primarily driven by a $17.6 million
increase in net cash inflows from accounts receivable due to collection of receivables during the year ended December 31, 2016
associated primarily with an increase in incremental barrels shipped at Pony Express, and a $13.2 million increase in deferred
revenue associated primarily with deficiency payments collected by Pony Express during the year ended December 31, 2016.
Investing Activities. Cash flows used in investing activities were $581.7 million for the year ended December 31, 2016.
Investing cash outflows for the year ended December 31, 2016 were primarily driven by:
•
•
•
•
cash outflows of $436.0 million for the acquisition of a 25% membership interest in Rockies Express on May 6, 2016;
capital expenditures of $70.7 million, primarily due to post in-service spending on Pony Express System projects and
the Pipeline Integrity Management Program at Trailblazer;
cash outflows of $49.1 million for a portion of the acquisition of an additional 31.3% membership interest in Pony
Express on January 1, 2016, the remainder of which is classified as a financing activity as discussed below; and
contributions to Rockies Express in the amount of $50.0 million.
These cash outflows were partially offset by $24.1 million of distributions from Rockies Express in excess of cumulative
earnings recognized.
Cash flows used in investing activities were $845.3 million for the year ended December 31, 2015. Investing cash outflows
for the year ended December 31, 2015 were primarily driven by:
•
•
the cash outflow of $700.0 million for the acquisition of an additional 33.3% membership interest in Pony Express,
which allowed TD to continue funding the pipeline construction at Pony Express; and
the cash outflow of $75.0 million for the acquisition of Western, and capital expenditures of $65.4 million, primarily
due to construction of the Pony Express System, including the lateral in Northeast Colorado.
Financing Activities. Cash flows provided by financing activities were $172.5 million for the year ended December 31,
2016. Financing cash inflows for the year ended December 31, 2016 were primarily driven by:
•
•
•
•
•
proceeds from the issuance of $400.0 million in aggregate principal amount of 5.50% Senior Notes due 2024;
the issuance of 7,696,708 common units under the Equity Distribution Agreements for net cash proceeds of $337.7
million;
net borrowings under the revolving credit facility of $262.0 million;
the issuance of 2,416,987 common units representing limited partnership interests in a private placement transaction
for net cash proceeds of $90.0 million; 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 18 – Legal and Environmental Matters.
78
These financing cash inflows were partially offset by cash outflows of:
•
•
•
$425.9 million for the portion of the acquisition of an additional 31.3% membership interest in Pony Express which
exceeds the cumulative capital spending on the underlying assets acquired;
distributions to unitholders of $292.8 million; and
$204.6 million for the partial exercise of the call option granted by TD covering 4,814,906 common units.
Cash flows provided by financing activities were $556.7 million for the year ended December 31, 2015. Financing cash
inflows for the year ended December 31, 2015 were primarily driven by:
•
•
net cash proceeds of $554.1 million from the issuance of 11,200,000 common units in a public offering and 65,744
common units issued under the Equity Distribution Agreements during 2015; and
net borrowings under the revolving credit facility of $194.0 million.
These financing cash inflows were partially offset by cash outflows of:
•
•
distributions to unitholders of $161.8 million; and
distributions to noncontrolling interests of $25.1 million, primarily driven by distributions to TD from Pony Express.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Operating Activities. Cash flows provided by operating activities were $289.3 million and $79.4 million for the years
ended December 31, 2015 and 2014, respectively. The increase in net cash flows provided by operating activities of $209.9
million was primarily driven by the increase in operating results and a net increase in cash inflows from changes in working
capital, primarily driven by a $31.6 million decrease in net cash outflows from accounts payable and accrued liabilities due to
increased property tax accruals and related party payables and a $14.0 million increase in net cash inflows from deficiency
payments received by Pony Express, partially offset by a decrease in net cash inflows of $15.3 million from accounts
receivable, due to increased receivables at Pony Express.
Investing Activities. Cash flows used in investing activities were $845.3 million for the year ended December 31, 2015.
Investing cash outflows for the year ended December 31, 2015 were primarily driven by the acquisitions of Western and an
additional 33.3% membership interest in Pony Express, as discussed above.
Cash flows used in investing activities were $1.1 billion for the year ended December 31, 2014. Investing cash outflows
for the year ended December 31, 2014 were primarily driven by:
•
•
•
capital expenditures of $665.7 million, primarily due to construction at Pony Express, including the lateral in
Northeast Colorado, as well as the capacity expansion projects at TMID and other expansion projects at Trailblazer;
cash outflows of $270.0 million associated with the related party loan to TD under the Pony Express cash management
agreement; and
cash outflows of $150.0 million, $27.0 million, and $7.6 million for the acquisitions of Trailblazer, Pony Express, and
Water Solutions, respectively.
These cash outflows were partially offset by cash inflows of $20.0 million from the return of funds deposited with Shell in
support of the crude oil resale obligation of Pony Express.
Financing Activities. Cash flows provided by financing activities were $556.7 million for the year ended December 31,
2015. Financing cash inflows for the year ended December 31, 2015 were primarily driven by proceeds from the issuance of
common units and net borrowings under the revolving credit facility, partially offset by distributions to unitholders and
noncontrolling interests, as discussed above.
Cash flows provided by financing activities were $1.0 billion for the year ended December 31, 2014. Financing cash
inflows for the year ended December 31, 2014 were primarily driven by:
•
•
•
•
net borrowings under the revolving credit facility of $424.0 million;
net proceeds of $320.4 million from the issuance of 8,050,000 common units in a public offering and 28,625 common
units issued under the Equity Distribution Agreements during 2014;
net contributions from Predecessor Entities of $312.1 million; and
a contribution from TD of $27.5 million representing the difference between the carrying amount of the Replacement
Gas Facilities, as defined in Note 5 – Related Party Transactions, and the proceeds received from TD.
These cash inflows were partially offset by distributions to unitholders of $68.1 million.
79
Distributions
We do not have a legal obligation to pay distributions except as provided in our partnership agreement. A distribution
of $0.815 per unit, or $88.2 million in the aggregate, for the three months ended December 31, 2016 was declared on
January 24, 2017 and was paid on February 14, 2017 to unitholders of record on February 3, 2017. As of February 15, 2017, we
had a total of 72,973,429 common and general partner units outstanding, which equates to an aggregate minimum quarterly
distribution of approximately $21.0 million per quarter and approximately $83.9 million per year. We intend to continue to pay
quarterly distributions at or above the amount of the minimum quarterly distribution, which is $0.2875 per unit.
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 to 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).
We expect to incur approximately $55 million for capital expenditures in 2017, of which approximately $39 million is
expected for expansion projects and approximately $16 million, net of anticipated reimbursements from affiliates, is expected
for maintenance capital expenditures.
The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our
budgeting process and as we approve, execute, and monitor our capital spending. The following table summarizes the
maintenance and expansion capital expenditures incurred at our consolidated entities:
Year Ended December 31,
2016
2015
(in thousands)
2014
Maintenance capital expenditures ......................................... $
Expansion capital expenditures.............................................
Total capital expenditures incurred .................................. $
11,323
30,576
41,899
$
$
12,123
16,859
28,982
$
$
9,913
193,704
203,617
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 decrease in maintenance capital
expenditures to $11.3 million for the year ended December 31, 2016 from $12.1 million for the year ended December 31, 2015
is primarily driven by decreased maintenance capital expenditures in the Processing & Logistics segment. Maintenance capital
expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the
level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. The increase in
expansion capital expenditures to $30.6 million for the year ended December 31, 2016 from $16.9 million for the year ended
December 31, 2015 is primarily driven by increased expansion capital expenditures in the Crude Oil Transportation & Logistics
segment due to post in-service spending on Pony Express System projects. Expansion capital expenditures of $16.9 million for
the year ended December 31, 2015 consisted primarily of spending on the NGL pipeline in Northeast Colorado. During the year
ended December 31, 2015, substantially all of the expansion capital expenditures related to Pony Express System projects were
funded by TD as discussed in Note 4 – Acquisitions and Note 12 – Partnership Equity and Distributions.
The increase in maintenance capital expenditures to $12.1 million for the year ended December 31, 2015 from $9.9
million for the year ended December 31, 2014 is primarily driven by increased maintenance capital expenditures in the Natural
Gas Transportation & Logistics and Processing & Logistics segments. Maintenance capital expenditures on our assets occur on
a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital
expenditures naturally varies from year to year and from quarter to quarter. The decrease in expansion capital expenditures to
$16.9 million for the year ended December 31, 2015 from $193.7 million for the year ended December 31, 2014 is primarily
driven by the significant spending on the Pony Express System prior to commencement of commercial operations in October
2014. Expansion capital expenditures of $16.9 million for the year ended December 31, 2015 consisted primarily of spending
on the NGL pipeline in Northeast Colorado prior to commencement of commercial service in the fourth quarter of 2015.
80
In addition, we invested cash in unconsolidated affiliates of $50.0 million during the year ended December 31, 2016 and
$2.0 million during the year ended December 31, 2014 to fund our share of capital projects. There were no investments in
unconsolidated affiliates during the year ended December 31, 2015. We expect to make contributions to unconsolidated
affiliates of approximately $24 million to fund our 25% portion of capital projects at Rockies Express during the year ending
December 31, 2017.
We intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we
expect that we will distribute to our unitholders most of the cash generated by our operations. We expect to fund future capital
expenditures with funds generated from our operations, borrowings under our revolving credit facility, the issuance of
additional partnership units and/or the issuance of 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, 2016:
Contractual Obligations
Debt obligations (1)....................................................
Interest on debt obligations (2)...................................
Operating lease and service contract obligations (3) .
Land site lease and right-of-way (4) ..........................
Other purchase commitments (5) ...............................
Total
Payments Due By Period
Total
Less Than 1
Year
1-3 Years
(in thousands)
$ 1,415,000
204,297
$
— $ 1,015,000
53,466
47,220
593,239
2,440
13,989
28,103
274
7,993
57,700
416
4,042
3-5 Years
More Than
5 Years
$
— $
44,000
59,858
475
1,885
400,000
59,611
447,578
1,275
69
$ 2,228,965
$
83,590
$ 1,130,624
$
106,218
$
908,533
(1) Debt obligations at December 31, 2016 consisted of borrowings under the revolving credit facility and the 2024 Notes. For
additional information, see Note 11 – Long-term Debt to the Consolidated Financial Statements in Item 8.—Financial
Statements and Supplementary Data.
(2)
Interest on debt obligations is estimated using current borrowings and interest rates as of December 31, 2016. For
additional information, see Note 11 – Long-term Debt to the Consolidated Financial Statements in Item 8.—Financial
Statements and Supplementary Data.
(3) Operating leases and service contracts consist of leases for crude oil storage as well as office space and equipment. Lease
obligations include approximately $255.8 million in future minimum lease payments to Terminals related to the Sterling
Terminal facilities, which we acquired effective January 1, 2017. Lease obligations for the crude oil storage at the Sterling
and Deeprock Terminals assume renewal for the full 20-year lease term. For additional information, see Note 13 –
Commitments & Contingent Liabilities to our Consolidated Financial Statements in Item 8.—Financial Statements and
Supplementary Data in this Form 10-K.
(4) Land site lease and right-of-way contracts consist of payments to landowners, primarily in our Crude Oil Transportation &
Logistics and Natural Gas Transportation & Logistics segments. For additional information, see Note 13 – Commitments &
Contingent Liabilities to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data
in this Form 10-K.
(5) Other purchase commitments primarily relate to planned non-reimbursable capital expenditures and operating and
maintenance expenditures.
On May 17, 2013, in connection with the closing of TEP's IPO, TEP and its general partner entered into the TEP Omnibus
Agreement, which provides that, among other things, TEP will reimburse TD and its affiliates for all expenses they incur and
payments they make on TEP's behalf, including the costs of employee and director compensation and benefits as well as the
cost of the provision of certain centralized corporate functions performed by TD, including legal, accounting, cash
management, insurance administration and claims processing, risk management, health, safety and environmental, information
technology and human resources in each case to the extent reasonably allocable to TEP.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
81
Critical Accounting Policies and Estimates
Our significant accounting policies and the anticipated impact of recently issued accounting standards are described in
Note 2 – Summary of Significant Accounting Policies to the consolidated financial statements included in Item 8 of this Annual
Report. 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
Using the impairment review methodology
described herein, we have not recorded any
impairment charges on long-lived assets during
the year ended December 31, 2016. 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.
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.
82
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Assumptions
We determine fair value using widely
accepted valuation techniques, primarily
discounted cash flow and market multiple
analyses. These techniques are also used
when assigning the purchase price to
acquired assets and liabilities. 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 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. 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.
When available, quoted market prices or
prices obtained through external sources
are used to determine a contract's fair
value. For contracts with a delivery
location or duration for which quoted
market prices are not available, fair value is
determined based on pricing models
developed primarily from historical
information and the expected relationship
with quoted market prices.
Estimating the fair value of each award, the
number of awards that will ultimately vest,
and the forfeiture rate requires management
to apply judgment to estimate the tenure of
our employees and the achievement of
certain performance targets over the
performance period.
We primarily use a discounted cash flow
analysis, supplemented by a market approach
analysis, to perform the assessment. 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. In estimating cash
flows, we incorporate current market
information, as well as historical and other
factors, into our forecasted commodity prices. 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 2016 using the methodology
described herein, and determined there was no
impairment.
If our estimates of fair value are inaccurate, we
may be exposed to losses or gains that could be
material. See Item 7A.—Quantitative and
Qualitative Disclosures About Market Risk for
details regarding the impact of potential
changes in the crude oil and natural gas forward
price curves on our derivative instruments at
December 31, 2016.
If actual results are not consistent with our
assumptions and judgments or our assumptions
and estimates change due to new information,
we may experience material changes in
compensation expense.
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.
Risk Management Activities
Derivative assets and
liabilities are recorded on
our consolidated balance
sheets at their estimated fair
value as of each reporting
date. Changes in the fair
value of derivative
contracts are recognized in
earnings in the period in
which the change occurs.
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.
83
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
As of December 31, 2016, approximately 99% of our reserved processing capacity was subject to firm or volumetric fee
contracts, with the majority of fee revenue based on the volumes actually processed. The remaining 1% was subject to
commodity sensitive contracts such as percent of proceeds or keep whole processing contracts. The profitability of our
commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility
in prevailing NGL and natural gas prices. We do not currently hedge the commodity exposure in our commodity sensitive
contracts in our Processing & Logistics segment and we do not expect to in the foreseeable future. Starting in the second half of
2014, the prices of crude oil, natural gas, and NGLs became extremely volatile and declined significantly. Downward pressure
and volatility on commodity prices continued in 2015 before recovering somewhat in 2016. These declines directly and
indirectly resulted in lower realizations and processing volumes on our percent of proceeds and keep whole processing
contracts. Our Processing & Logistics segment comprised approximately 4%, 9% and 30% of our Adjusted EBITDA for the
years ended December 31, 2016, 2015 and 2014, respectively.
The following table summarizes the percentage of our Adjusted EBITDA at each reportable segment by contract type for
the year ended December 31, 2016:
Crude Oil
Transportation
& Logistics
Natural Gas
Transportation
& Logistics
Processing &
Logistics
Corporate &
Other
Consolidated
Firm fee .................................
Volumetric fee.......................
Commodity exposed .............
Other......................................
Total.......................................
62%
<1%
<1%
—%
62%
33%
1%
<1%
1%
35%
2%
1%
1%
—%
4%
— %
— %
— %
(1)%
(1)%
97%
2%
1%
—%
100%
Historically, we have had a limited amount of direct commodity price exposure related to natural gas collected for
electrical compression costs and lost and unaccounted for gas on the TIGT System. Accordingly, we have historically entered
into derivative contracts with third parties for a substantial majority of the natural gas we expected to collect for the purpose of
hedging our commodity price exposures. In 2016, we also entered into long natural gas swaps covering a portion of the natural
gas that TMID expects to purchase in 2017. In addition, we have a limited amount of direct commodity price exposure related
to crude oil collected as part of our contractual pipeline loss allowance at Pony Express. During 2016, we began entering into
derivative contracts for the sale of crude oil inventory.
We measure the risk of price changes in our natural gas swaps 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 solely for the purpose of mitigating the risks that accompany certain of our
business activities and, therefore, both the sensitivity analysis model and the change in the market value of our outstanding
derivative contracts are offset largely by changes in the value of the underlying physical commodity prices.
The following table summarizes our commodity derivatives and the change in fair value that would be expected from a
10% price increase or decrease as of December 31, 2016, assuming a parallel shift in the forward curve through the end of
2017:
Fair Value
Effect of 10%
Price Increase
(in thousands)
Effect of 10%
Price Decrease
Natural gas derivative contracts (1)............................................... $
Natural gas derivative contracts (2)............................................... $
Crude oil derivative contract (3).................................................... $
291
$
(116) $
(440) $
142
$
(105) $
(702) $
(142)
105
702
(1) Represents long natural gas swaps outstanding with a notional volume of approximately 0.4 Bcf covering a portion of
the natural gas that is expected to be purchased by our Processing & Logistics segment throughout 2017.
84
(2) Represents short natural gas swaps outstanding with a notional volume of approximately 0.3 Bcf covering a portion of
the natural gas that is expected to be sold by our Natural Gas Transportation & Logistics segment in the first quarter of
2017.
(3) Represents the sale of 125,000 barrels of crude oil by our Crude Oil Transportation & Logistics segment which will
settle throughout 2017.
The Commodity Futures Trading Commission ("CFTC") has promulgated regulations to implement the Dodd-Frank Wall
Street Reform and Consumer Protection Act's changes to the Commodity Exchange Act, including the definition of commodity-
based swaps subject to those regulations. The CFTC regulations implemented new reporting and record keeping requirements
related to those swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or
classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate
that most, if not all, of our swap transactions should qualify for an exemption to the clearing and exchange-execution
requirements, we will still be subject to record keeping and reporting requirements.
Interest Rate Risk
As described in "Liquidity and Capital Resources Overview" above, on September 1, 2016 we issued $400 million in
5.50% senior notes due 2024. In addition, we currently have a $1.75 billion revolving credit facility with borrowings of
approximately $1.0 billion as of December 31, 2016. Borrowings under the revolving credit facility will bear interest, at our
option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate
plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in
each case, an applicable margin. The applicable margin ranges from 0.75% to 2.75%, based upon our total leverage ratio and
whether we have elected the base rate or the reserve adjusted Eurodollar rate.
We do not currently hedge the interest rate risk on our borrowings under the revolving credit facility. However, in the
future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to
fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the
fair value of the debt by $0.5 million based on our debt obligations as of December 31, 2016.
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 slightly under 45% of our
revenues derived from customers who have an investment grade credit rating or are part of corporate families with investment
grade credit ratings as of December 31, 2016. This represents a decrease in the portion of our revenues derived from customers
with an investment grade credit rating from 2015, primarily as a result of credit downgrades at several of our customers and
throughout the industry due to the soft commodity price environment.
We also have indirect credit risk exposure with respect to our investment in Rockies Express. See Item 1A.—Risk Factors
for additional information.
85
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Partners of Tallgrass Energy Partners, LP
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, equity and
cash flows present fairly, in all material respects, the financial position of Tallgrass Energy Partners, LP and its subsidiaries at
December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2016, 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, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these
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 these financial statements and on the
Partnership's internal control over financial reporting based on our audits (which were integrated audits in 2016 and 2015). We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether effective internal control over financial reporting was maintained in
all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. 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.
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 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 15, 2017
86
TALLGRASS ENERGY PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
December 31, 2016 December 31, 2015
(in thousands)
Current Assets:
ASSETS
Cash and cash equivalents ..................................................................................... $
Accounts receivable, net........................................................................................
Gas imbalances......................................................................................................
Inventories .............................................................................................................
Derivative assets at fair value................................................................................
Prepayments and other current assets....................................................................
Total Current Assets..........................................................................................
Property, plant and equipment, net.............................................................................
Goodwill.....................................................................................................................
Intangible asset, net ....................................................................................................
Unconsolidated investment ........................................................................................
Deferred financing costs, net......................................................................................
Deferred charges and other assets ..............................................................................
Total Assets................................................................................................................. $
Current Liabilities:
LIABILITIES AND EQUITY
Accounts payable (including $10,554 at December 31, 2015 related to variable
interest entities) ..................................................................................................... $
Accounts payable to related parties.......................................................................
Gas imbalances......................................................................................................
Derivative liabilities at fair value ..........................................................................
Accrued taxes ........................................................................................................
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:
$
$
$
1,873
59,469
1,597
12,805
10,967
6,820
93,531
2,012,263
343,288
93,522
461,915
4,815
9,637
3,018,971
24,076
5,879
1,239
556
16,328
16,525
60,757
6,446
131,806
1,407,981
7,063
1,415,044
1,611
57,757
1,227
13,793
—
2,835
77,223
2,025,018
343,288
96,546
—
5,105
14,894
2,562,074
22,218
7,852
1,605
—
13,844
10,019
26,511
6,880
88,929
753,000
5,143
758,143
Common unitholders (72,485,954 and 60,644,232 units issued and outstanding
at December 31, 2016 and 2015, respectively) .....................................................
General partner (834,391 units issued and outstanding at December 31, 2016
and 2015, respectively)..........................................................................................
Total Partners' Equity........................................................................................
Noncontrolling interests ........................................................................................
Total Equity ......................................................................................................
Total Liabilities and Equity........................................................................................ $
2,070,495
1,618,766
(632,339)
1,438,156
33,965
1,472,121
3,018,971
$
(348,841)
1,269,925
445,077
1,715,002
2,562,074
The accompanying notes are an integral part of these consolidated financial statements.
87
TALLGRASS ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
2016
2015
(in thousands, except per unit amounts)
2014
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 (exclusive of depreciation and amortization shown
below)................................................................................................
Cost of transportation services (exclusive of depreciation and
amortization shown below) ...............................................................
Operations and maintenance .............................................................
Depreciation and amortization ..........................................................
General and administrative ...............................................................
Taxes, other than income taxes .........................................................
Loss on disposal of assets .................................................................
Total Operating Costs and Expenses..........................................
Operating Income .....................................................................................
Other Income (Expense):
Interest expense, net ..........................................................................
Unrealized loss on derivative instrument..........................................
Equity in earnings of unconsolidated investment .............................
Gain on remeasurement of unconsolidated investment ....................
Other income, net ..............................................................................
Total Other Income (Expense)...................................................
Net income ...............................................................................................
Net (income) loss attributable to noncontrolling interests ................
Net income attributable to partners .......................................................... $
Allocation of income to the limited partners:
Net income attributable to partners ................................................... $
Predecessor operations interest in net income ..................................
Net income attributable to partners, excluding predecessor
operations interest .............................................................................
General partner interest in net income ..............................................
Common and subordinated unitholders' interest in net income ........ $
Basic net income per common and subordinated unit ...................... $
Diluted net income per common and subordinated unit ................... $
Basic average number of common and subordinated units
outstanding ........................................................................................
Diluted average number of common and subordinated units
outstanding ........................................................................................
374,949
$
300,436
$
119,962
77,394
32,817
605,122
71,920
58,341
53,386
84,896
53,633
24,727
1,849
348,752
256,370
(40,688)
(1,291)
51,780
—
1,723
11,524
267,894
(4,365)
263,529
263,529
—
263,529
(102,465)
161,064
2.26
2.23
71,150
72,107
$
$
$
$
$
119,895
82,133
33,733
536,197
75,285
53,597
49,138
83,476
50,195
21,796
4,795
338,282
197,915
(15,514)
—
—
—
2,413
(13,101)
184,814
(24,268)
160,546
160,546
—
160,546
(46,478)
114,068
1.95
1.91
58,597
59,575
$
$
$
$
$
28,343
126,733
181,249
35,231
371,556
167,545
24,109
39,577
47,048
33,160
6,704
—
318,143
53,413
(7,292)
—
717
9,388
3,103
5,916
59,329
11,352
70,681
70,681
(1,508)
69,173
(7,399)
61,774
1.39
1.36
44,346
45,394
The accompanying notes are an integral part of these consolidated financial statements.
88
TALLGRASS ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY
Limited Partners
General Partner
Common
Subordinated
Units
Amount
Units
Amount
Units
Amount
Predecessor
Equity
Total
Partners'
Equity
Noncontrolling
Interests
Total Equity
(in thousands)
Balance at January 1, 2014. $
247,221
24,300
$
455,197
16,200
$274,666
827
$
14,078
$ 991,162
$
317,939
$ 1,309,101
Net income (loss).............
1,508
—
39,141
—
22,633
Issuance of units to
public, net of offering
costs .................................
Distributions to
unitholders .......................
Noncash compensation
expense ............................
Contribution from TD......
(Distributions to)
Contributions from
Predecessor Entities, net..
Contributions from
noncontrolling interest.....
Distributions to
noncontrolling interests ...
Issuance of general
partner units.....................
—
—
—
—
(97,887)
—
—
—
Acquisition of Trailblazer
(91,090)
Acquisition of Water
Solutions..........................
Acquisition of 33.3%
Pony Express
membership interest ........
—
(59,752)
8,079
320,385
—
—
—
—
—
—
—
—
—
385
—
70
(41,567)
— (23,166)
10,154
—
—
—
—
—
14,023
—
3,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
8
—
—
—
7,399
70,681
(11,352)
59,329
—
320,385
(3,384)
(68,117)
—
27,488
10,154
27,488
—
—
—
—
320,385
(68,117)
10,154
27,488
—
—
—
(97,887)
410,012
312,125
—
—
5,429
5,429
(5,406)
(5,406)
263
263
(72,933)
(150,000)
—
—
263
(150,000)
—
—
1,400
1,400
(8,654)
(65,406)
38,406
(27,000)
Balance at December 31,
2014 .................................... $
— 32,834
$
800,333
16,200
$274,133
835
$ (35,743) $1,038,723
$
756,428
$ 1,795,151
Net income ......................
—
—
108,888
—
5,180
Issuance of units to
public, net of offering
costs .................................
Distributions to
unitholders .......................
Noncash compensation
expense ............................
Common units issued
under LTIP, net of units
tendered by employees to
satisfy tax withholding
obligations .......................
Contributions from
noncontrolling interest.....
Distributions to
noncontrolling interests ...
Acquisition of additional
33.3% membership
interest in Pony Express ..
Acquisition of
noncontrolling interests ...
Conversion of
subordinated units............
— 11,266
554,084
—
—
—
—
—
—
—
—
—
(118,729)
9,337
344
(6,603)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(7,857)
—
—
—
—
—
—
— 16,200
271,456
(16,200)
(271,45
6)
—
—
—
—
—
—
—
46,478
160,546
24,268
184,814
—
554,084
(35,248)
(161,834)
—
9,337
—
—
—
554,084
(161,834)
9,337
—
—
—
(6,603)
—
(6,603)
—
—
110,127
110,127
(69,474)
(69,474)
— (324,328)
(324,328)
(375,672)
(700,000)
—
—
—
—
—
—
(600)
(600)
—
—
Balance at December 31,
2015 .................................... $
— 60,644
$ 1,618,766
— $
—
835
$ (348,841) $1,269,925
$
445,077
$ 1,715,002
The accompanying notes are an integral part of these consolidated financial statements.
89
TALLGRASS ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY
Net income ......................
—
—
161,064
—
7,697
337,671
—
—
—
2,417
90,009
—
—
(202,996)
7,879
—
6,518
268,607
— (4,815)
(204,634)
—
—
—
—
—
—
—
—
—
—
—
(5,373)
—
—
—
—
—
—
—
—
—
—
—
Issuance of units to
public, net of offering
costs .................................
Issuance of units in a
private placement, net of
offering costs ...................
Distributions to
unitholders .......................
Noncash compensation
expense ............................
Acquisition of additional
31.3% membership
interest in Pony Express ..
Partial exercise of call
option...............................
Contributions from TD....
Contributions from
noncontrolling interest.....
Distributions to
noncontrolling interests ...
Acquisition of
noncontrolling interests ...
Common units issued
under LTIP, net of units
tendered by employees to
satisfy tax withholding
obligations .......................
Balance at December 31,
2016 .................................... $
— 72,486
$ 2,070,495
— $
—
25
(498)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
102,465
263,529
4,365
267,894
—
—
—
—
—
337,671
—
90,009
(89,838)
(292,834)
—
7,879
—
—
—
—
337,671
90,009
(292,834)
7,879
— (279,967)
(11,360)
(417,679)
(429,039)
—
—
—
—
—
(33,993)
(238,627)
17,894
17,894
—
—
(238,627)
17,894
—
—
—
—
9,304
9,304
(6,534)
(6,534)
(59)
(5,432)
(568)
(6,000)
—
—
(498)
—
(498)
835
$ (632,339) $1,438,156
$
33,965
$ 1,472,121
The accompanying notes are an integral part of these consolidated financial statements.
90
TALLGRASS ENERGY PARTNERS, 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..........................................
Noncash compensation expense..................................................................
Noncash change in the fair value of derivative financial instruments ........
Loss on disposal of assets ...........................................................................
Gain on remeasurement of unconsolidated investment ..............................
Changes in components of working capital:
Accounts receivable and other ....................................................................
Gas imbalances ...........................................................................................
Inventories...................................................................................................
Accounts payable and accrued liabilities ....................................................
Deferred revenue.........................................................................................
Other operating, net .........................................................................................
Net Cash Provided by Operating Activities..........................................................
Cash Flows from Investing Activities:
Capital expenditures.........................................................................................
Acquisition of unconsolidated affiliate............................................................
Acquisition of Pony Express membership interest ..........................................
Contributions to unconsolidated affiliate.........................................................
Distributions from unconsolidated investment in excess of cumulative
earnings ............................................................................................................
Issuance of related party loan ..........................................................................
Acquisition of Trailblazer ................................................................................
Acquisition of Western.....................................................................................
Acquisition of additional equity interests in Water Solutions..........................
Other investing, net..........................................................................................
Net Cash Used in Investing Activities..................................................................
Cash Flows from Financing Activities:
Acquisition of Pony Express membership interest ..........................................
Proceeds from issuance of long-term debt.......................................................
Proceeds from public offering, net of offering costs .......................................
Distributions to unitholders..............................................................................
Borrowings under revolving credit facility, net...............................................
Partial exercise of call option...........................................................................
Proceeds from private placement, net of offering costs...................................
Contributions from Predecessor Entities, net...................................................
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 ........................................................... $
Year Ended December 31,
2016
2015
(in thousands)
2014
267,894
$
184,814
$
59,329
91,453
(51,780)
51,780
5,780
1,556
1,849
—
2,024
1,157
(938)
9,966
33,815
(5,072)
409,484
(70,719)
(436,022)
(49,118)
(50,013)
24,120
—
—
—
—
48
(581,704)
(425,882)
400,000
337,671
(292,834)
262,000
(204,634)
90,009
—
17,894
(11,742)
172,482
262
1,611
1,873
$
87,367
—
—
5,103
—
4,795
—
(15,605)
(757)
(5,169)
9,799
20,612
(1,663)
289,296
(65,387)
—
(700,000)
—
—
—
—
(75,000)
—
(4,883)
(845,270)
—
—
554,084
(161,834)
194,000
—
—
—
—
(29,532)
556,718
744
867
1,611
49,041
(717)
717
5,136
(184)
—
(9,388)
(348)
1,504
(8,367)
(21,787)
6,619
(2,111)
79,444
(665,650)
—
(27,000)
(1,999)
747
(270,000)
(150,000)
—
(7,600)
18,773
(1,102,729)
—
—
320,385
(68,117)
424,000
—
—
312,125
27,488
8,271
1,024,152
867
—
867
$
The accompanying notes are an integral part of these consolidated financial statements.
91
TALLGRASS ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Supplemental Disclosures:
Cash payments for interest, net........................................................................ $
(29,754) $
(14,021) $
(6,801)
Schedule of Noncash Investing and Financing Activities:
Property, plant and equipment acquired via the cash management agreement
with TD ............................................................................................................ $
Contributions from noncontrolling interests settled via the cash
management agreement with TD ..................................................................... $
Distributions to noncontrolling interests settled via the cash management
agreement with TD .......................................................................................... $
— $
138,936
— $
68,277
$
$
158,357
—
— $
(69,017) $
(5,361)
The accompanying notes are an integral part of these consolidated financial statements.
92
TALLGRASS ENERGY PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business
Tallgrass Energy Partners, LP ("TEP" or the "Partnership") is a publicly traded, growth-oriented limited partnership formed
to own, operate, acquire and develop midstream energy assets in North America. "We," "us," "our" and similar terms refer to
TEP together with its consolidated subsidiaries. Our operations are located in and provide services to certain key United States
hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and
the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations. Our reportable business segments
are:
•
•
•
Crude Oil Transportation & Logistics—the ownership and operation of a FERC-regulated crude oil pipeline system
and crude oil storage and terminalling facilities;
Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas
pipelines and integrated natural gas storage facilities; and
Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities,
the provision of water business services primarily to the oil and gas exploration and production industry and the
transportation of NGLs.
Crude Oil Transportation & Logistics. We currently provide crude oil transportation to customers in Wyoming, Colorado,
and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated
crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma, which includes a lateral in
Northeast Colorado commencing in Weld County, Colorado, and interconnecting with the pipeline just east of Sterling,
Colorado (the "Pony Express System"). We also provide crude oil storage and terminalling services through our 100%
membership interest in Tallgrass Terminals, LLC ("Terminals") acquired effective January 1, 2017, which owns and operates
crude oil terminals near Sterling, Colorado (the "Sterling Terminal") and in Weld County, Colorado (the "Buckingham
Terminal"). Terminals also owns a 20% membership interest in Deeprock Development, LLC ("Deeprock Development"),
which owns a crude oil terminal in Cushing, Oklahoma (the "Cushing Terminal").
Natural Gas Transportation & Logistics. We provide natural gas transportation and storage services for customers in the
Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 25% 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") acquired effective January 1, 2017, which operates
the Rockies Express Pipeline, (2) the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation
and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and (3) the
Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border
to Beatrice, Nebraska (the "Trailblazer Pipeline").
Processing & Logistics. We also provide services for customers in Wyoming at the Casper and Douglas natural gas
processing facilities and the West Frenchie Draw natural gas treating facility (collectively, the "Midstream Facilities"), and
NGL transportation services in Northeast Colorado and Wyoming. We perform water business services, including freshwater
transportation and produced water gathering and disposal, in Colorado and Texas through BNN Water Solutions, LLC ("Water
Solutions").
The table below summarizes our equity ownership as of December 31, 2016:
Unit holder
Public Unitholders (1) .................
Tallgrass Equity, LLC................
Tallgrass Development, LP (2)....
Tallgrass MLP GP, LLC (3).........
Total (4) .......................................
Limited Partner
Common Units
44,427,380
20,000,000
8,058,574
—
72,485,954
General
Partner Units
—
Percentage of
Outstanding Limited
Partner Common Units
61.29%
—
—
834,391
834,391
27.59%
11.12%
—%
100.00%
Percentage of
Outstanding Common
and General Partner
Units
60.59%
27.28%
10.99%
1.14%
100.00%
(1) As discussed in Note 12 – Partnership Equity and Distributions, we issued and sold an additional 2,092,440 common
units subsequent to December 31, 2016. As of February 15, 2017, there were 46,519,820 common units held by public
unitholders outstanding.
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(2) As discussed in Note 10 – Risk Management and Note 12 – Partnership Equity and Distributions, 2,439,356 of the
common units held by Tallgrass Development, LP ("TD") as of December 31, 2016 were subsequently deemed
cancelled as of February 1, 2017. As of February 15, 2017, there were 5,619,218 common units held by TD
outstanding.
(3) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.
(4) As of February 15, 2017, there were 72,973,429 total limited partner and general partner units outstanding.
The term "Trailblazer Predecessor" refers to Trailblazer Pipeline Company LLC ("Trailblazer") for the period from
November 13, 2012 to its acquisition by TEP on April 1, 2014, and the term "Pony Express Predecessor" refers to Pony Express
for the period from November 13, 2012 to September 1, 2014, the date on which TEP acquired a 33.3% membership interest.
Trailblazer Predecessor and Pony Express 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 Trailblazer Predecessor prior to April 1, 2014 and of Pony Express Predecessor prior
to September 1, 2014. For additional information regarding these acquisitions, see Note 4 – Acquisitions.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying financial statements and related notes were prepared in accordance with the accounting principles
contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of generally
accepted accounting principles in the United States of America ("GAAP"). 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.
The accompanying consolidated financial statements of TEP include historical cost-basis accounts of the assets of
Trailblazer for the periods prior to April 1, 2014, the date TEP acquired Trailblazer from TD, and Pony Express for the periods
prior to September 1, 2014, the date TEP acquired a controlling 33.3% membership interest in Pony Express, and include
charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation
methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone
basis. TEP and the Predecessor Entities are all considered "entities under common control" as defined under GAAP and, as
such, the transfers between the entities of the assets and liabilities have been recorded by TEP at historical cost.
As further discussed in Note 4 – Acquisitions, TEP closed the acquisition of Trailblazer on April 1, 2014 and the
acquisition of a 33.3% membership interest in Pony Express effective September 1, 2014. As the acquisitions of Trailblazer and
the initial 33.3% membership interest in Pony Express are considered transactions between entities under common control, and
a change in reporting entity, the financial information presented has been recast to include Trailblazer and the
initial 33.3% membership interest in Pony Express for all periods presented. The acquisitions of an additional 33.3% and
31.3% membership interest in Pony Express effective March 1, 2015, and January 1, 2016, respectively, represent transactions
between entities under common control and acquisitions of noncontrolling interests. As a result, financial information for
periods prior to March 1, 2015 and January 1, 2016 have not been recast to reflect the additional 33.3% and 31.3% membership
interests.
The consolidated financial statements include the accounts of TEP and its subsidiaries and controlled affiliates. Significant
intra-entity items have been eliminated in the presentation. Net 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 April 1, 2014 for Trailblazer and September 1, 2014 for Pony Express, 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. Prior to
January 1, 2016, Pony Express participated in a cash management agreement with TD, which currently holds a 2.0% common
membership interest in Pony Express, under which cash balances were swept periodically and recorded as loans from Pony
Express to TD. Effective January 1, 2016, Pony Express entered into a cash management agreement with TEP.
Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and
noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the
allocation of cash distributions and may not follow the respective ownership percentages held by TEP. Concurrent with TEP's
acquisition of an initial 33.3% membership interest in Pony Express effective September 1, 2014, TEP, TD, and Pony Express
entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the
Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65
million (prorated to approximately $5.4 million for the quarter ended September 30, 2014) through the quarter ended
September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony
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Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC
Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5
million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ended
December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to
the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC
Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 are attributed to TEP
and its 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 do not have material assets that can only be used to
settle specific obligations of the consolidated VIEs. Pony Express was considered to be a VIE under the applicable authoritative
guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1,
2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express.
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.
Net equity distributions 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 April 1, 2014 for Trailblazer and September
1, 2014 for Pony Express, 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 $0.6
million at December 31, 2016 and 2015.
Inventories
Inventories primarily consist of gas in underground storage, materials and supplies, natural gas liquids and crude oil. Gas
in underground storage, sometimes referred to as working gas, and natural gas liquids are recorded at the lower of historical
cost or market using the average cost method. 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
allowance oil, which we can then sell. As pipeline allowance oil is accumulated, it is recorded as inventory at the lower of
historical cost or market using the average cost method. Materials and supplies are valued at weighted average cost and
periodically reviewed for physical deterioration and obsolescence. For additional information, see "Gas in Underground
Storage" below.
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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 $2.9
million and $2.8 million included in "Deferred charges and other assets" in the consolidated balance sheets at December 31,
2016 and 2015, respectively. Regulatory assets at December 31, 2016 and December 31, 2015 were primarily attributable to
costs associated with both TIGT's 2015 Rate Case Filing and Trailblazer's 2013 Rate Case Filing as well as fuel tracker assets at
our regulated natural gas pipelines. We recorded regulatory liabilities of approximately $1.7 million and $2.2 million included
in "Other current liabilities" in the consolidated balance sheet at December 31, 2016 and 2015, 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 17 – 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 account for intangible assets in accordance with ASC 805, which established that an intangible asset is identifiable if it
meets either the separability criterion or the contractual-legal criterion. Further, in accordance with ASC 805, 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.
Intangible assets arose at BNN Redtail, LLC ("Redtail") as a result of a significant customer contract with favorable market
terms which was acquired as part of the Water Solutions transaction discussed in Note 4 – Acquisitions. This intangible asset
was amortized on a straight-line basis over a period of 1.6 years, the remaining term of the contract at the time of acquisition,
and was fully amortized as of December 31, 2015.
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;
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•
•
•
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 or market.
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.
The rates of depreciation for the various classes of depreciable assets are as follows:
Crude oil pipelines .......................................................................
Natural gas pipelines ....................................................................
Processing & treating assets .........................................................
Water business assets....................................................................
Replacement Gas Facilities (1) ......................................................
General & other ............................................................................
Range of
Depreciation
Rates
2.8%
0.7 - 5.0%
3.3%
2.3 - 20.0%
10.0%
2.9 - 25.0%
(1) Represents the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 17 –
Regulatory Matters.
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.
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 with 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.
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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 an operating segment as defined in the
segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach
depending on facts and circumstances of the reporting unit. If we, after performing the qualitative assessment, determine it is
"more likely than not" that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is
unnecessary. When goodwill is evaluated for impairment using the two-step test, the carrying amount of the reporting unit is
compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying
amount exceeds the reporting unit's fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation
process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any.
When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable
sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized
as an impairment loss. See Note 8 – Goodwill and Other Intangible Assets for additional information regarding impairment
testing performed during 2016.
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
value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether
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 9 –
Investments in Unconsolidated Affiliates for additional information regarding our investment in unconsolidated affiliates.
Revenue Recognition
We recognize revenues as services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery
has occurred, title has transferred and collectability is reasonably assured. We provide various types of natural gas storage and
transportation services and crude oil transportation services to our customers in which the commodity remains the property of
these customers at all times.
Crude oil transportation services occur in the Crude Oil Transportation & Logistics segment. We provide various types of
crude oil transportation services to our customers and, other than pipeline allowance oil, do not take title to the crude oil and do
not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels
per month. For barrels physically received by us and delivered to the customers' agreed upon destination point, revenue is
recognized in the period the service is provided. Shipper deficiencies, or 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, are charged
at the committed tariff rate per barrel and recorded as a liability until the barrels are physically transported and delivered. In the
case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and
delivered. 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 allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be
sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered
from the customer. When pipeline loss allowance oil is eventually sold, we record revenue at the contractual sales price and
cost of sales at average cost as discussed in "Inventories" above.
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Natural gas transportation and storage services occur in the Natural Gas Transportation & Logistics segment. In many
cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fee reserving the right to
transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn
from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The
per-unit charge is recognized as revenue when the volumes are delivered to the customers' agreed upon delivery point, or when
the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible
service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be
interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service,
revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service
agreements. In addition to "firm" and "interruptible" transportation services, we also provide natural gas park and loan services
to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized as services are provided, based
on the terms negotiated under these contracts.
Natural gas liquids sales occur in the Processing & Logistics segment and consist of the sale of outputs from our
processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based
arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered
by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the
producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We
keep the difference between the proceeds received and the amount remitted back to the producer. We generally report gross
revenues in the consolidated statements of income, as we typically act as the principal in these transactions, take custody of the
product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent fees for processing,
treating and fractionation of natural gas and NGLs earned under fee-based arrangements and revenue from water services
earned in the Processing & Logistics segment.
Natural gas sales occur in both the Natural Gas Transportation & Logistics segment and in the Processing & Logistics
segment. In the Natural Gas Transportation & Logistics segment, transportation services revenue is recognized when a portion
of the natural gas transported by customers is collected as a contractual fee to compensate us for fuel consumed by pipeline and
storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are
delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold, we record
natural gas sales revenue at the contractual sales price and cost of sales at average cost. In addition, when operational
conditions allow, we occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to
operate the storage facility. In the Processing & Logistics segment, we purchase natural gas primarily for use in our operations
and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual
arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate
revenue by selling the volumes of natural gas received or purchased that exceed our business needs.
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
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.
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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 10 – Risk
Management. For information regarding the fair value of financial instruments not measured at fair value in the consolidated
balance sheets, see Note 11 – Long-term Debt.
Risk Management Activities
We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of crude
oil and natural gas. We record derivative contracts at their estimated fair values as of each reporting date. For more information
on our risk management activities, see Note 10 – Risk Management.
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, a portion of the expense recognized relating to equity-based compensation grants is charged to TD.
Income Taxes
Prior to September 1, 2014, TEP was comprised solely of limited liability companies that were flow-through entities (that
is, partnerships or disregarded entities) for income tax purposes. As discussed above, effective September 1, 2014 TEP acquired
a 33.3% membership interest in Pony Express, which in turn owned 99.8% of Tallgrass Pony Express Pipeline (Colorado), Inc.
("PXP Colorado"), a C corporation. At that time, PXP Colorado was in the process of constructing the lateral in Northeast
Colorado and had not yet commenced operations or generated any income. PXP Colorado was subsequently merged into Pony
Express prior to the commencement of commercial operations on the lateral in Northeast Colorado.
On September 14, 2015, TEP, through its membership interest in Pony Express, formed a new C corporation, Tallgrass
Colorado Pipeline, Inc. ("Tallgrass Colorado"), which is 99.8% owned by Pony Express. The remaining 0.2% interest in
Tallgrass Colorado is held by direct and indirect wholly owned subsidiaries of TEP. Tallgrass Colorado was formed for the
purpose of the potential construction of a lateral pipeline that would interconnect with the Pony Express System's existing
lateral in Northeast Colorado and has not yet commenced operations or generated any income. In addition, during the year
ended December 31, 2015, we formed Tallgrass Energy Finance Corp., a wholly owned subsidiary that has no material assets
and was formed for the sole purpose of being a co-issuer of our senior notes issued on September 1, 2016. Accordingly, no
provision for federal or state income taxes has been recorded in our consolidated financial statements.
100
Accounting Pronouncements Not Yet Adopted
Revenue Recognition
In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with
Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition
guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is
that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that
reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core
principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance
obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations
in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also
mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing
and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include
qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and
assets recognized from the costs to obtain or fulfill a contract.
Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in
Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,
ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting
Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance
Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope
Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606,
Revenue from Contracts with Customers.
The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 are effective for public
entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period.
Early application is permitted for annual reporting periods beginning after December 15, 2016.
We are currently evaluating the impact of our pending adoption of the revised guidance. The status of our implementation
is as follows:
• We have formed an implementation team that meets to discuss implementation challenges, technical interpretations,
industry-specific treatment of certain revenue contract types, and project status.
• We are currently reviewing contracts for each revenue stream identified within each of our business segments.
Through this process, we are determining and documenting expected changes in revenue recognition upon adoption of
the revised guidance.
• We plan to evaluate the potential information technology and internal control changes that will be required for
adoption based on the findings from our contract review process.
• We plan to provide internal training and awareness related to the revised guidance to the key stakeholders throughout
our organization.
We will continue to conduct our contract review process throughout 2017 and, as a result, areas of impact may be
identified. We are in the process of quantifying the impact of adoption but cannot reasonably estimate such amount at this time.
We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. This approach allows us to
apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or
substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a
cumulative adjustment to equity. Consolidated revenues presented in our comparative financial statements for periods prior to
January 1, 2018 would not be revised.
ASU No. 2016-02, "Leases (Topic 842)"
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update
to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by
recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.
The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes
primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.
The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December
15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the
impact of ASU 2016-02.
101
ASU No. 2016-09, "Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment
Accounting"
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to
Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based
payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and
classification on the statement of cash flows. Among other changes, ASU 2016-09 allows an entity to make an entity-wide
accounting policy election to either estimate the number of awards expected to vest (consistent with current GAAP) or account
for forfeitures when they occur.
The amendments in ASU 2016-09 are effective for public entities for annual periods and interim periods within those
annual periods beginning after December 15, 2016. Early adoption is permitted. We are currently evaluating the impact of ASU
2016-09, but do not anticipate a material impact on our consolidated financial statements.
ASU No. 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business"
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a
Business. ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with
evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing a
screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially
all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of
similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further
evaluated. The ASU also narrows the definition of the term "output" so that the term is consistent with how outputs are
described under the revenue recognition guidance in Topic 606.
The amendments in ASU 2017-01 are effective for public entities for annual periods and interim periods within those
annual periods beginning after December 15, 2017. Early adoption is permitted in certain circumstances. We are currently
evaluating the impact of ASU 2017-01, but do not anticipate a material impact on our consolidated financial statements.
ASU No. 2017-04, "Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment"
In January 2017, the FASB issued ASU No. 2017-04, which simplifies the subsequent measurement of goodwill by
eliminating "Step 2" from the goodwill impairment test, which involved calculating the implied fair value of goodwill by
determining the fair value at the impairment testing date of a reporting unit's assets and liabilities. Instead, under the simplified
test approach, and entity should recognize an impairment charge for the amount by which the carrying amount exceeds the
reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that
reporting unit.
The amendments in ASU 2017-04 are effective for public entities for annual periods and interim periods within those
annual periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests
performed on testing dates after January 1, 2017. We are currently evaluating the impact of ASU 2017-04.
Accounting Pronouncements Recently Adopted
ASU No. 2016-15, "Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments"
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash
Receipts and Cash Payments. ASU 2016-15 provides explicit guidance on accounting for eight specific cash flow issues with
the objective of reducing diversity in practice, including debt prepayment or debt extinguishment costs, settlement of certain
debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of
insurance claims, proceeds from the settlement of corporate owned life insurance policies, distributions received from equity
method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the
predominance principle.
The amendments in ASU 2016-15 are effective for public entities for fiscal years beginning after December 15, 2017, and
interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. During the third
quarter of 2016, we adopted the standard on a retrospective basis for all periods presented. The adoption of ASU 2016-15 did
not have a material impact on our financial position, results of operations, or cash flows.
102
ASU No. 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments"
In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting
for Measurement-Period Adjustments. ASU 2015-16 simplifies the accounting for measurement-period adjustments for
provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively
account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the
reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the
provisional amounts must be calculated as if the accounting had been completed at the acquisition date.
The amendments in ASU 2015-16 were effective for public entities for annual periods and interim periods within those
annual periods beginning after December 15, 2015. The adoption of ASU 2015-16 did not have a material impact on our
financial position and results of operations.
ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis"
In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation
Analysis. ASU 2015-02 changes the analysis that a reporting entity must perform to determine whether it should consolidate
certain types of legal entities. ASU 2015-02 modifies the evaluation of whether limited partnerships and other similar legal
entities are considered VIEs or voting interest entities, eliminates the presumption that a general partner should consolidate a
limited partnership, and changes certain aspects of the consolidation analysis for reporting entities that are involved with VIEs,
particularly for those with fee arrangements and related party relationships.
The amendments in ASU 2015-02 were effective for public entities for annual periods and interim periods within those
annual periods beginning after December 15, 2015. The adoption of ASU 2015-02 did not have a material impact on our
financial position and results of operations.
ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the
Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period"
In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for
Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite
Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific
performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target
may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a
performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead,
compensation cost should be recognized in the period in which it becomes probable that the performance target will be
achieved.
ASU 2014-12 was effective for annual periods and interim periods within those annual periods beginning after December
15, 2015. The adoption of ASU 2014-12 did not have a material impact on our financial position and results of operations.
3. Variable Interest Entities
Prior to January 1, 2016, Pony Express was considered to be a VIE as TEP did not have the obligation to absorb expected
losses from Pony Express as a result of the minimum quarterly preference payments as discussed in Note 4 – Acquisitions. In
addition, for the period from our acquisition of the initial 33.3% membership interest effective September 1, 2014 to our
acquisition of an additional 33.3% membership interest effective March 1, 2015, TEP, as the managing member of Pony
Express, had voting rights disproportionate to its ownership interest. As a result, we determined that Pony Express was a VIE of
which TEP was the primary beneficiary and consolidated Pony Express accordingly. As discussed in Note 2 – Summary of
Significant Accounting Policies, in conjunction with our acquisition of an additional 31.3% membership interest effective
January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in
Pony Express.
We have not provided any additional financial support to Pony Express other than our initial capital contribution of $570
million and our pro rata portion of expansion capital projects as discussed below, and have no contractual commitments or
obligations to provide additional financial support. To the extent the costs of construction of the Pony Express System,
including the lateral in Northeast Colorado, exceed the $270 million retained by Pony Express as discussed in Note 4 –
Acquisitions, TD is obligated to fund the remaining costs. As of December 31, 2015, the costs to complete construction
exceeded the amount retained, and as such TD continued to fund remaining costs associated with construction of the mainline
and lateral in Northeast Colorado. Although TEP has no obligation to provide further financial support to Pony Express,
expansion capital projects are funded by TEP and TD on a pro rata basis in accordance with the Pony Express LLC Agreement.
Contributions from TEP to Pony Express to fund expansion capital projects totaled $4.4 million for the year ended
December 31, 2015.
103
The carrying amounts and classifications of the Pony Express assets and liabilities included in TEP's consolidated balance
sheet at December 31, 2015 are as follows:
December 31, 2015
Current assets .................................................................................................................................... $
Noncurrent assets ..............................................................................................................................
Total assets................................................................................................................................. $
Current liabilities............................................................................................................................... $
Total liabilities ........................................................................................................................... $
46,800
1,391,906
1,438,706
51,349
51,349
4. Acquisitions
TEP Acquisition of a 25% Membership Interest in Rockies Express Pipeline LLC
On May 6, 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. For additional information,
see Note 9 – Investments in Unconsolidated Affiliates.
TEP Acquisitions of 98% of Pony Express
Effective September 1, 2014, TEP acquired a controlling 33.3% membership interest in Pony Express for total
consideration of approximately $600 million. At closing, Pony Express, TD, and TEP entered into the Second Amended Pony
Express LLC Agreement, which set forth the relative rights of TD and TEP as the owners of Pony Express. Of the total
consideration of $600 million, TEP directly paid TD $30 million, consisting of $27 million in cash and 70,340 TEP common
units with an aggregate fair value of approximately $3 million, in exchange for the transfer by TD to TEP of
a 1.9585% membership interest in Pony Express (computed before giving effect to the issuance of the new membership interest
by Pony Express to TEP). TEP also contributed cash of $570 million to Pony Express in exchange for a newly issued
membership interest which, when combined with the membership interest transferred from TD and the parties' entry at closing
into the Second Amended Pony Express LLC Agreement, constituted TEP's 33.3% membership interest in Pony Express, which
represented 100% of the preferred membership units issued by Pony Express. Of the $570 million cash consideration received
by Pony Express, $300 million was immediately distributed to TD at closing and $270 million was retained by Pony Express to
fund the estimated remaining costs of construction for the Pony Express System and the lateral in Northeast Colorado. The
$270 million cash balance was subsequently swept to TD under a cash management agreement between Pony Express and TD
and was recorded as a related party loan which bears interest at TD's incremental borrowing rate. The related party loan was
repaid in full in 2015.
The terms of TEP's first acquisition of a 33.3% membership interest in Pony Express provided TEP a minimum quarterly
preference payment of $16.65 million through the quarter ended September 30, 2015 (prorated to approximately $5.4
million for the quarter ended September 30, 2014) with distributions thereafter shared in accordance with the terms of the
Second Amended Pony Express LLC Agreement. At the effective date of that transaction, TEP determined that Pony Express
was a VIE of which TEP was the primary beneficiary, and consolidated Pony Express accordingly. For additional discussion
and disclosure, see Note 3 – Variable Interest Entities. The acquisition of the initial 33.3% membership interest in Pony Express
represented a transaction between entities under common control and a change in reporting entity.
Effective March 1, 2015, TEP acquired an additional 33.3% membership interest in Pony Express for cash consideration
of $700 million. At closing, Pony Express, TD, and TEP entered into the Pony Express LLC Agreement, which sets forth the
relative rights of TD and TEP as the owners of Pony Express. The terms of the transaction increased the minimum quarterly
preference payment provided to TEP to $36.65 million through the quarter ending December 31, 2015 (prorated to
approximately $23.5 million for the quarter ended March 31, 2015) with distributions thereafter shared in accordance with the
terms of the Pony Express LLC Agreement.
104
Upon the effective date of the second acquisition, TEP reevaluated its VIE assessment and determined that Pony Express
continued to be considered a VIE of which TEP is the primary beneficiary. The acquisition of the additional 33.3% 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 have not been recast to reflect the
additional 33.3% membership interest. The transaction resulted in a deemed distribution to our general partner as discussed
further in Note 12 – Partnership Equity and Distributions.
Effective January 1, 2016, TEP 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%. 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 10 – Risk Management, in July 2016 and October
2016, we partially exercised the option covering 3,563,146 and 1,251,760 of the common units, respectively. On February 1,
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, TEP derecognized a portion
of the derivative asset balance, recognizing approximately $34.0 million through equity for year ended December 31, 2016, as
discussed further in Note 12 – Partnership Equity and Distributions.
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. The transaction resulted in a deemed
distribution to our general partner as discussed further in Note 12 – Partnership Equity and Distributions.
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.
TEP Acquisition of BNN Western, LLC
On December 16, 2015, Whiting Oil and Gas Corporation ("Whiting"), Redtail, and BNN Western, LLC ("Western"), a
newly formed Delaware limited liability company, entered into a definitive Transfer, Purchase and Sale Agreement, pursuant to
which Redtail acquired 100% of the outstanding membership interests of Western from Whiting in exchange for total cash
consideration of $75 million. Western's assets consist of a fresh water delivery and storage system and produced water
gathering and produced water disposal system, which together comprise 62 miles of pipeline along with associated fresh water
ponds and disposal wells. As part of the transaction with Whiting, Whiting also executed a five-year fresh water service
contract and a nine-year gathering and disposal contract, each of which commenced in December 2015.
At December 31, 2015, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts
based on the preliminary purchase price allocation. The $75 million purchase price of the assets was allocated entirely to
property, plant and equipment. 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 September 30, 2016.
Unaudited pro forma revenue and net income attributable to partners for the years ended December 31, 2015 and 2014 is
presented below as if the acquisition of Western had been completed on January 1, 2014:
Revenue .......................................................................................................................
Net income attributable to partners .............................................................................
538,033
161,184
373,470
71,347
Year Ended December 31,
2015
2014
(in thousands)
105
The pro forma financial information is not necessarily indicative of what the actual results of operations or financial
position of TEP 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 TEP for any future periods or as of any date. The pro forma
financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result
from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma
revenue and net income includes adjustments to give effect to TEP's consolidated interest in the estimated results of operations
of Western for the periods presented.
TEP Acquisition of Trailblazer
On April 1, 2014, TEP closed the acquisition of Trailblazer from a wholly owned subsidiary of TD for total consideration
valued at approximately $164 million, consisting of $150 million in cash and the issuance of 385,140 common units (valued at
approximately $14 million based on the March 31, 2014 closing price of TEP's common units). On that same date, the general
partner contributed additional capital in the amount of approximately $263,000 in exchange for the issuance of 7,860 general
partner units in order to maintain its 2% general partner interest. The acquisition of Trailblazer represents a change in reporting
entity and a transaction between entities under common control. The excess purchase price over the net book value of
Trailblazer's assets and liabilities was accounted for as a deemed distribution as discussed further in Note 12 – Partnership
Equity and Distributions.
Formation of BNN Water Solutions, LLC
On November 26, 2013, TEP, through its wholly-owned subsidiary Tallgrass Energy Investments, LLC ("TEI"), entered
into a joint venture agreement with BNN Energy LLC ("BNN") to form Grasslands Water Services I, LLC ("GWSI"), which
subsequently built and began operating an intrastate fresh water pipeline in Colorado. TEP accounted for its 50% equity interest
in GWSI as an equity method investment. On May 13, 2014, TEI entered into a contribution agreement with BNN and several
other parties to form a new entity known as Water Solutions. Under the terms of the contribution agreement, TEI agreed to
contribute its existing 50% interest in GWSI, along with $7.6 million cash, in exchange for an 80% membership interest in
Water Solutions. As part of the transaction, GWSI was renamed Redtail, became a subsidiary of Water Solutions, and issued
preferred equity interests to TEI. Among the assets contributed by BNN and the other parties to the transaction were the
other 50% interest in Redtail and a 100% equity interest in Alpha Reclaim Technology, LLC ("Alpha"), a company which
sources treated wastewater from municipalities in Texas. Alpha is wholly-owned by Redtail.
Upon closing of the transaction, TEP obtained a controlling financial interest in Water Solutions and accordingly has
accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously
held 50% equity interest in Redtail to its fair value of $11.9 million, recognized a gain of $9.4 million, and consolidated Water
Solutions. The 20% equity interest in Water Solutions held by noncontrolling interests was recorded at its acquisition date fair
value of $1.4 million. The fair values of the previously held equity interest and the noncontrolling interest were determined
using a discounted cash flow analysis. These fair value measurements are based on significant inputs 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.
At December 31, 2014, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts
based on the preliminary purchase price allocation. During the three months ended June 30, 2015, the preliminary purchase
price allocation with respect to Water Solutions was finalized with no material adjustments.
On May 20, 2015, TEP acquired an additional 12% equity interest in Water Solutions from NR2, LLC for cash
consideration of $600,000, which was accounted for as an acquisition of noncontrolling interest. On July 1, 2016, TEP acquired
the remaining 8% noncontrolling equity interest in Water Solutions and additional interests in certain of Water Solutions'
subsidiaries from Regency Investments I, LLC and BSEG Water Group LLC for total cash consideration of $6.0 million, which
was accounted for as an acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate
membership interest in Water Solutions is 100%.
5. Related Party Transactions
As a result of our relationship with TD and its affiliates, we have entered into a number of related party transactions. The
following disclosure includes those related party disclosures which are not otherwise disclosed in these notes to our
consolidated financial statements.
We have no employees. Prior to our IPO, TD, through its wholly-owned subsidiary Tallgrass Operations, LLC ("Tallgrass
Operations"), provided and charged us for direct and indirect costs of services provided to us or incurred on our behalf
including employee labor costs, information technology services, employee health and retirement benefits, and all other
expenses necessary or appropriate to the conduct of our business. We recorded these costs on the accrual basis in the period in
which TD incurred them. On May 17, 2013, in connection with the closing of the IPO, TEP and its general partner entered into
an Omnibus Agreement with TD and certain of its affiliates, including Tallgrass Operations (the "TEP Omnibus Agreement").
106
The TEP Omnibus Agreement provides that, among other things, TEP will reimburse TD and its affiliates for all expenses they
incur and payments they make on TEP's behalf, including the costs of employee and director compensation and benefits as well
as the cost of the provision of certain centralized corporate functions performed by TD, including legal, accounting, cash
management, insurance administration and claims processing, risk management, health, safety and environmental, information
technology and human resources in each case to the extent reasonably allocable to TEP.
Due to the cash management agreement discussed in Note 2 – Summary of Significant Accounting Policies, intercompany
balances at the Predecessor Entities were periodically settled and treated as equity distributions prior to April 1, 2014 for
Trailblazer and prior to September 1, 2014 for Pony Express. Balances lent to TD under the Pony Express cash management
agreement effective September 1, 2014 are classified as related party receivables in the consolidated balance sheets. There was
no interest income from TD recognized for the year ended December 31, 2016. During the years ended December 31, 2015 and
2014 we recognized interest income from TD of $0.4 million and $1.5 million, respectively, on the receivable balance under the
Pony Express cash management agreement in effect through December 31, 2015.
Totals of transactions with affiliated companies, excluding transactions otherwise disclosed, are as follows:
Cost of transportation services (1) ............................................ $
Charges to TEP: (2)
Property, plant and equipment, net .................................. $
Other deferred charges..................................................... $
Operation and maintenance.............................................. $
General and administrative .............................................. $
Year Ended December 31,
2016
2015
(in thousands)
2014
29,244
2,741
44
24,895
38,567
$
$
$
$
$
25,046
4,320
7
23,520
33,432
$
$
$
$
$
—
17,936
27
18,783
23,475
(1) Reflects rent expense for the crude oil storage at the Sterling and Deeprock Terminals. For more information, see Note
13 – Commitments & Contingent Liabilities.
(2) Charges to TEP, inclusive of Pony Express, include directly charged wages and salaries, other compensation and
benefits, and shared services.
Details of balances with affiliates included in "Receivable from related parties" and "Accounts payable to related parties"
in the consolidated balance sheets are as follows:
December 31, 2016
December 31, 2015
(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC ........................................................ $
Total receivable from related parties ........................................ $
Accounts payable to related parties:
Tallgrass Operations, LLC............................................................... $
Tallgrass Equity, LLC......................................................................
Deeprock Development, LLC..........................................................
Rockies Express Pipeline LLC ........................................................
$
$
$
560
560
5,798
68
13
—
Total accounts payable to related parties.................................. $
5,879
$
Balances of gas imbalances with affiliated shippers are as follows:
15
15
7,792
36
17
7
7,852
Affiliate gas imbalance receivables ........................................................ $
Affiliate gas imbalance payables ............................................................ $
December 31, 2016
December 31, 2015
(in thousands)
177
$
— $
92
227
107
Pursuant to the terms of a Purchase and Sale Agreement dated August 1, 2012, TD, through August 31, 2014, reimbursed
TIGT for all costs TIGT incurred with respect to the Pony Express Abandonment, as defined in Note 17 – Regulatory Matters,
including, but not limited to, development costs, capital costs and related interest costs associated with the construction of
certain gas facilities necessary to maintain existing natural gas service on the TIGT System (the "Replacement Gas Facilities").
The Replacement Gas Facilities are required as part of the Pony Express Abandonment in order for TIGT to continue service to
existing customers after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain
other equipment, to Pony Express in 2013. For more information, see Note 17 – Regulatory Matters. Any costs incurred by
TIGT subsequent to August 31, 2014 are reimbursed directly by Pony Express.
TIGT's expenditures for the Replacement Gas Facilities are captured in "Prepayments and other current assets" in the
consolidated balance sheets as they are incurred and interest is accrued until reimbursement takes place (which is typically
monthly). During the year ended December 31, 2014 we received proceeds from TD of $69.2 million and incurred expenditures
of $41.7 million. We recognized a contribution of $27.5 million from TD in our consolidated statement of equity which
represents the difference between the carrying amount of the Replacement Gas Facilities and the proceeds received from TD.
At December 31, 2016 and 2015, TEP had not incurred any expenditures for the Replacement Gas Facilities that had not been
reimbursed.
6.
Inventory
The components of inventory at December 31, 2016 and 2015 consisted of the following:
December 31, 2016
December 31, 2015
Crude oil ...................................................................................................... $
Materials and supplies .................................................................................
Natural gas liquids.......................................................................................
Gas in underground storage.........................................................................
(in thousands)
5,180
$
6,377
265
983
Total inventory ..................................................................................... $
12,805
$
2,661
8,581
395
2,156
13,793
7. Property, Plant and Equipment
A summary of net property, plant and equipment by classification is as follows:
Crude oil pipelines .................................................................................. $
Natural gas pipelines ...............................................................................
Processing and treating assets .................................................................
Water business assets ..............................................................................
General and other ....................................................................................
Construction work in progress ................................................................
Accumulated depreciation and amortization...........................................
Total property, plant and equipment, net (1) ........................................ $
December 31, 2016
December 31, 2015
(in thousands)
1,202,125
$
1,172,684
572,150
256,901
85,077
71,508
18,228
(193,726)
2,012,263
$
550,710
254,073
81,098
69,181
30,699
(133,427)
2,025,018
(1) Property, plant and equipment, net includes approximately $435.9 million of assets at our regulated natural gas
pipelines.
Depreciation expense was approximately $81.9 million, $75.5 million, and $40.9 million for the years ended December 31,
2016, 2015, and 2014, respectively. Capitalized interest was approximately $0.6 million, $0.9 million, and $1.2 million for the
years ended December 31, 2016, 2015, and 2014, respectively.
108
Under a lease agreement effective October 3, 2015, Tallgrass Midstream, LLC ("TMID"), as lessor, leases capacity on an
NGL pipeline that was constructed for a third party. Rental income was approximately $3.2 million and $0.8 million for the
years ended December 31, 2016 and 2015, 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, $0.8 million, and $1.0
million for the years ended December 31, 2016, 2015, and 2014, respectively, and was recorded as "Other income, net" in the
accompanying consolidated statements of income.
As of December 31, 2016, future minimum rental income under non-cancelable operating leases as the lessor were as
follows (in thousands):
Year
2017......................................................................................
$
2018......................................................................................
2019......................................................................................
2020......................................................................................
2021......................................................................................
Thereafter .............................................................................
Total...................................................................................... $
Total
3,967
3,982
3,997
3,385
3,180
11,934
30,445
8. Goodwill and Other Intangible Assets
Reconciliation of Goodwill
There were no changes in goodwill for the years ended December 31, 2016 and 2015. The following table presents the
carrying amount of goodwill by segment for the periods indicated:
December 31, 2016 December 31, 2015
(in thousands)
Natural Gas Transportation & Logistics..................................................................... $
Processing & Logistics...............................................................................................
Total goodwill............................................................................................................. $
255,558
87,730
343,288
$
$
255,558
87,730
343,288
Annual Goodwill Impairment Analysis
We did not elect to apply the qualitative assessment option during our 2016 annual goodwill impairment testing; instead
we proceeded directly to the two-step quantitative test. In Step 1 of the two-step quantitative test, we compared the fair value of
each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash
flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the
enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a
stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in
various assumptions. This approach required us to make long-term forecasts of future operating results and various other
assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative
expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined
using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting
unit, the results of the Step 1 impairment analysis indicated no potential impairment as the fair value of the reporting units was
greater than their respective book values. As a result, in accordance with the Codification guidance, Step 2 of the impairment
analysis was not necessary as part of the annual impairment analysis in 2016.
109
Other Intangible Assets
A summary of amortized intangible assets is as follows:
Pony Express oil conversion use rights................................................... $
Accumulated amortization ......................................................................
Intangible assets, net .......................................................................... $
December 31, 2016
December 31, 2015
(in thousands)
105,973
(12,451)
93,522
$
$
105,973
(9,427)
96,546
Amortization of intangible assets was approximately $3.0 million, $8.0 million, and $6.2 million for the years ended
December 31, 2016, 2015, and 2014, respectively. As discussed in Note 2 – Summary of Significant Accounting Policies, the
Redtail customer contract was fully amortized as of December 31, 2015.
Estimated future amortization for the intangible asset is as follows (in thousands):
Year
2017......................................................................................
$
2018......................................................................................
2019......................................................................................
2020......................................................................................
2021......................................................................................
Thereafter .............................................................................
Total...................................................................................... $
Total
3,028
3,028
3,028
3,028
3,028
78,382
93,522
9.
Investments in Unconsolidated Affiliates
Rockies Express
Our investment in Rockies Express is recorded under the equity method of accounting and reported as "Unconsolidated
investment" on our consolidated balance sheets. As of May 6, 2016, the difference between the fair value of our investment in
Rockies Express of $436.0 million and the book value of the underlying net assets of approximately $840.7 million resulted in
a negative basis difference of approximately $404.7 million. The basis difference was allocated to property, plant and
equipment and long-term debt based on their respective fair values at the date of acquisition. The amount of the basis difference
allocated to property, plant and equipment is accreted over 35 years, which equates to the 2.86% composite depreciation rate
utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt
is amortized over the remaining life of the various debt facilities. The basis difference at December 31, 2016 was allocated as
follows:
Basis Difference
(in thousands)
Amortization Period
Long-term debt........................................................................................ $
Property, plant and equipment.................................................................
Total basis difference.......................................................................... $
8,421
(404,046)
(395,625)
2 - 25 years
35 years
During the period from May 6, 2016 to December 31, 2016, we recognized equity in earnings from Rockies Express of
$51.8 million, inclusive of the amortization of the negative basis difference discussed above, and received distributions from
and made contributions to Rockies Express of $75.9 million and $50.0 million, respectively.
110
Summarized financial information for Rockies Express is as follows:
Current assets .................................................................................................................................... $
Noncurrent assets .............................................................................................................................. $
Current liabilities............................................................................................................................... $
Noncurrent liabilities......................................................................................................................... $
Members' equity................................................................................................................................ $
195,698
6,079,292
188,139
2,656,836
3,430,015
December 31, 2016
(in thousands)
Period from May 6,
2016 to December 31,
2016
Revenue............................................................................................................................................. $
Operating income .............................................................................................................................. $
Net income to Members .................................................................................................................... $
421,324
190,050
170,562
GWSI
Our investment in GWSI, which owns a fresh water transportation pipeline, was initially recorded under the equity method
of accounting as we had the ability to exercise significant influence, but not control, over this investment. There was $0.7
million equity in earnings recognized for the year ended December 31, 2014. There was no equity in earnings recognized for
the years ended December 31, 2015 and 2016. As discussed in Note 4 – Acquisitions, during the year ended December 31,
2014, TEP acquired a controlling interest in GWSI, which was subsequently renamed Redtail, and consolidated its investment
in Redtail as of May 13, 2014 accordingly.
10. Risk Management
We occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our
normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in
the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the
market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas
sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and
changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.
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, 2016
December 31, 2015
Call option derivative (1)............................................ Current assets.........
Natural gas derivative contracts (2)............................ Current assets.........
Natural gas derivative contracts (2)............................ Current liabilities ...
Crude oil derivative contract (3) ................................ Current liabilities ...
$
$
$
$
(in thousands)
10,676
291
116
440
$
$
$
$
—
—
—
—
(1) As discussed in Note 4 – Acquisitions, in conjunction with our acquisition of an additional 31.3% membership interest
in Pony Express effective January 1, 2016, TD granted us an 18-month call option covering the 6,518,000 common
units issued to TD. As of February 1, 2017, no common units remained subject to the call option.
(2) As of December 31, 2016, the fair value shown for natural gas derivative contracts was comprised of derivative
volumes for short and long natural gas fixed-price swaps totaling 0.3 Bcf and 0.4 Bcf, respectively. As of
December 31, 2015, there were no natural gas derivative contracts outstanding.
(3) As of December 31, 2016, the fair value shown for crude oil derivative contracts was comprised of derivative
contracts representing the sale of 125,000 barrels throughout 2017. As of December 31, 2015, there were no crude oil
derivative contracts outstanding.
111
Effect of Derivative Contracts in the Statements of Income
The following table summarizes the impact of derivative contracts for the years ended December 31, 2016, 2015 and 2014:
Location of
gain (loss) recognized
in income on derivatives
Amount of gain (loss) recognized in income on
derivatives
Year Ended December 31,
2016
2015
(in thousands)
2014
Derivatives not designated as
hedging contracts:
Call option derivative .................
Natural gas derivative contracts..
Crude oil derivative contract ......
Unrealized loss on derivative
instrument ....................................
Sales of natural gas, NGLs, and
crude oil .......................................
Sales of natural gas, NGLs, and
crude oil .......................................
$
$
$
(1,291) $
— $
—
74
$
427
$
(410)
(40) $
— $
—
Exercise of Call Option
In July 2016 and October 2016, we partially exercised the call option granted by TD in January 2016 as discussed in Note
4 – Acquisitions covering 3,563,146 and 1,251,760 common units, respectively, for cash payments of $151.4 million and $53.2
million, respectively. On February 1, 2017, we exercised the remainder of the call option covering an additional 1,703,094
common units for a cash payment of $72.4 million. These common units were deemed canceled upon the exercise of the call
option and as of such exercise date were no longer issued and outstanding. As of February 1, 2017, no common units remained
subject to the call option.
Credit Risk
We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our crude oil and natural
gas derivatives consist of major financial institutions. This concentration of counterparties may impact our overall exposure to
credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic,
regulatory or other conditions. The counterparty to our call option derivative was TD.
Our over-the-counter swaps are entered into with counterparties outside central trading organizations such as futures,
options or stock exchanges. These contracts are with financial institutions with investment grade credit ratings. While we enter
into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is
nevertheless possible that from time to time losses will result from counterparty credit risk in the future. As of December 31,
2016, the fair value of our crude oil and short natural gas derivative contracts were a liability, resulting in no credit exposure
from TEP's counterparties as of that date. The maximum potential exposure to credit losses on our long natural gas derivative
contract at December 31, 2016 was:
Asset Position
(in thousands)
Gross.................................................................................................................................................. $
Netting agreement impact..................................................................................................................
Cash collateral held ...........................................................................................................................
Net Exposure ..................................................................................................................................... $
291
(58)
—
233
As of December 31, 2016 and 2015, we did not have any outstanding letters of credit or cash in margin accounts in support
of our hedging of commodity price risks associated with the sale of natural gas nor did we have any margin deposits with
counterparties associated with natural gas contract positions.
Fair Value
Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or
over-the-counter ("OTC"). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they
are traded in an active market. We value exchange-traded derivative contracts using quoted market prices for identical
securities.
112
OTC commodity derivatives are valued using models utilizing a variety of inputs including contractual terms and
commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative
contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market.
We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic
forwards and swaps, model inputs can generally be verified and model selection does not involve significant management
judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. The call option granted by TD is
valued using a Black-Scholes option pricing model. Key inputs to the valuation model include the term of the option, risk free
rate, the exercise price and current market price, expected volatility and expected distribution yield of the underlying units. The
call option valuation is classified within Level 2 of the fair value hierarchy as the value is based on significant observable
inputs.
Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination
of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair
value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs
that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different
valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using
inputs unobservable in active markets are generally not material to our financial statements. When appropriate, valuations are
adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence.
In the absence of such evidence, management's best estimate is used.
The following table summarizes the fair value measurements of our derivative contracts as of December 31, 2016, based
on the fair value hierarchy established by the Codification:
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, 2016
Call option derivative .................................... $
Natural gas derivative contracts .................... $
10,676
291
$
$
— $
— $
10,676
291
$
$
—
—
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, 2016
Crude oil derivative contract....................... $
Natural gas derivative contracts .................. $
440
116
$
$
— $
— $
440
116
$
$
—
—
113
11. Long-term Debt
Long-term debt consisted of the following at December 31, 2016 and 2015:
Revolving credit facility.......................................................................... $
5.50% senior notes due September 15, 2024 ..........................................
Less: Deferred financing costs, net (1) ................................................
Total long-term debt, net......................................................................... $
December 31, 2016
December 31, 2015
(in thousands)
1,015,000
400,000
(7,019)
1,407,981
$
$
753,000
—
—
753,000
(1) Deferred financing costs, net as presented above relate solely to the 2024 Notes. Deferred financing costs associated
with our revolving credit facility are presented in noncurrent assets on our consolidated balance sheets.
Senior Unsecured Notes
On September 1, 2016, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the
Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016
(the "Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due
2024 (the "2024 Notes"). TEP used the net proceeds of the issuance to repay outstanding borrowings under its existing
revolving credit facility.
The 2024 Notes are general unsecured senior obligations of the Issuers. The 2024 Notes are unconditionally guaranteed
jointly and severally on a senior unsecured basis by TEP's existing direct and indirect wholly owned subsidiaries (other than the
Co-Issuer) and certain of TEP's future subsidiaries (the "Guarantors"). The 2024 Notes rank equal in right of payment with all
existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of
the Issuers. The 2024 Notes will mature on September 15, 2024 and interest on the 2024 Notes is payable in cash semi-annually
in arrears on each March 15 and September 15, commencing March 15, 2017. TEP may redeem the 2024 Notes prior to their
scheduled maturity at the applicable redemption price set forth in the Indenture, plus accrued and unpaid interest.
The Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries
to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness;
(iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments;
(v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or
into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity
interests in subsidiaries; and (viii) enter into transactions with affiliates. As of December 31, 2016, we are in compliance with
the covenants required under the 2024 Notes.
Revolving Credit Facility
On May 17, 2013, in connection with the IPO, TEP entered into a senior secured revolving credit facility with Barclays
Bank PLC, as administrative agent, and a syndicate of lenders (as amended, "the Credit Agreement"), which will mature on
May 17, 2018. As of December 31, 2016, the revolving credit facility has a total capacity of $1.75 billion and includes a $75
million sublimit for letters of credit and a $60 million sublimit for swing line loans. The unused portion of the revolving credit
facility is subject to a commitment fee, which ranges from 0.300% to 0.500%, based on our total leverage ratio. As of
December 31, 2016, the weighted average interest rate on outstanding borrowings was 2.48%. During the year ended December
31, 2016, our weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and
amortization of deferred financing costs, was 2.75%.
114
The following table sets forth the available borrowing capacity under the revolving credit facility as of December 31, 2016
and 2015:
Total capacity under the revolving credit facility (1)................................ $
Less: Outstanding borrowings under the revolving credit facility (2).
Available capacity under the revolving credit facility ............................ $
December 31, 2016
December 31, 2015
(in thousands)
1,750,000
(1,015,000)
735,000
$
$
1,100,000
(753,000)
347,000
(1) Effective January 4, 2016, in connection with the acquisition of an additional 31.3% membership interest in Pony
Express, TEP exercised the committed accordion feature to increase the total capacity of the revolving credit facility to
$1.5 billion. In connection with the acquisition of a 25% membership interest in Rockies Express, TEP amended the
revolving credit facility to increase the total capacity to $1.75 billion, which increase became effective May 6, 2016.
(2) As of February 3, 2017, our outstanding borrowings under the revolving credit facility were approximately $1.130
billion.
The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict
our ability (as well as the ability of our restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on
assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default
under the credit agreement then exists or would result from making such a distribution), change the nature of our business,
engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates
and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, we are required to maintain a consolidated
leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following
the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of
December 31, 2016, we are 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 our long-term debt, which is not measured at fair value
in the consolidated balance sheets as of December 31, 2016 and 2015, 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, 2016:
Revolving credit facility..... $
2024 Notes.......................... $
As of December 31, 2015:
— $
— $
1,015,000
398,000
Revolving credit facility..... $
— $
753,000
$
$
$
— $ 1,015,000
$ 1,015,000
— $
398,000
— $
753,000
$
$
392,981
753,000
The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of December 31, 2016 and
2015, the fair value of borrowings under the revolving credit facility approximates the carrying amount of the borrowings using
a discounted cash flow analysis. The 2024 Notes are carried at amortized cost, net of deferred financing costs. The estimated
fair value of the 2024 Notes is based upon quoted market prices adjusted for illiquid markets.
We are not aware of any factors that would significantly affect the estimated fair value subsequent to December 31, 2016.
12. Partnership Equity and Distributions
Equity Distribution Agreements
On October 31, 2014, we entered into an equity distribution agreement pursuant to which we may sell from time to time
through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering
price of up to $200 million. On May 13, 2015, the amount was subsequently amended to $100.2 million in order to account for
follow-on equity offerings under our S-3 shelf registration statement. On May 17, 2016, we entered into a new equity distribution
agreement allowing for the sale of common units with an aggregate offering price of up to $657.5 million. Sales of common units,
if any, will be made by means of ordinary brokers' transactions, to or through a market maker or directly on or through an electronic
115
communication network, a "dark pool" or any similar market venue, or as otherwise agreed by the Partnership and one or more
of the managers. We intend to use the net cash proceeds from any sale of the units for general partnership purposes, which may
include, among other things, the Partnership's exercise of the call option with respect to the 6,518,000 common units issued to TD
in connection with the Partnership's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing
of debt, funding for acquisitions, capital expenditures and additions to working capital.
During the year ended December 31, 2016, we issued and sold 7,696,708 common units with a weighted average sales
price of $44.46 per unit under our equity distribution agreements for net cash proceeds of approximately $337.7 million (net of
approximately $4.5 million in commissions and professional service expenses). During the period from January 1, 2017 to
February 15, 2017, we issued and sold an additional 2,075,546 common units with a weighted average sales price of $48.19 per
unit under our equity distribution agreements for net cash proceeds of approximately $99.0 million (net of approximately $1.0
million in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as
described above.
During the year ended December 31, 2015, we issued and sold 65,744 common units with a weighted average sales price
of $45.58 per unit under our equity distribution agreement for net cash proceeds of approximately $3.0 million (net of
approximately $30,000 in commissions and professional service expenses). We used the net cash proceeds for general
partnership purposes as described above.
During the year ended December 31, 2014, we issued and sold 28,625 common units with a weighted average sales price
of $44.20 per unit under our equity distribution agreements for net cash proceeds of approximately $1.1 million (net of
approximately $215,000 in commissions and professional service expenses). We used the net cash proceeds for general
partnership purposes as described above.
Private Placement
On April 28, 2016, we 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.
Repurchase of Common Units Owned by TD
Following an offer received from TD with respect to common units owned by TD not subject to the call option, we
repurchased 736,262 common units from TD at an aggregate price of approximately $35.3 million, or $47.99 per common unit,
on February 1, 2017, which was approved by the conflicts committee of the board of directors of our general partner. These
common units were deemed canceled upon our purchase and as of such transaction date were no longer issued and outstanding.
Tallgrass Development Purchase Program
On February 17, 2016, TEP and Tallgrass Energy GP, LP ("TEGP") announced that the Board of Directors of Tallgrass
Energy Holdings, LLC, the sole member of TEGP's general partner and the general partner of TD, has authorized an equity
purchase program under which TD may initially purchase up to an aggregate of $100 million of the outstanding Class A shares
of TEGP or the outstanding common units of TEP. TD may purchase Class A shares or Common Units from time to time on the
open market or in negotiated purchases. The timing and amounts of any such purchases will be subject to market conditions
and other factors, and will be in accordance with applicable securities laws and other legal requirements. The purchase plan
does not obligate TD to acquire any specific number of Class A shares or Common Units and may be discontinued at any time.
No purchases were made under this program during the year ended December 31, 2016.
Public Offerings
On February 27, 2015, we sold 10,000,000 common units representing limited partner interests in an underwritten public
offering at a price of $50.82 per unit, or $49.29 per unit net of the underwriter's discount, for net proceeds of approximately
$492.4 million after deducting the underwriter's discount and offering expenses. We used the net proceeds from the offering to
fund a portion of the consideration for the acquisition of an additional 33.3% membership interest in Pony Express as discussed
in Note 4 – Acquisitions. Pursuant to the underwriters' option to purchase additional units, we sold an additional 1,200,000
common units representing limited partner interests to the underwriters at a price of $50.82 per unit, or $49.29 per unit net of
the underwriter's discount, for net proceeds of approximately $59.3 million after deducting the underwriter's discount and
offering expenses. We used the net proceeds from this additional purchase of common units to reduce borrowings under our
revolving credit facility, a portion of which were used to fund the March 2015 acquisition of an additional 33.3% membership
interest in Pony Express as discussed in Note 4 – Acquisitions.
116
On July 25, 2014, we sold 8,050,000 common units representing limited partner interests in an underwritten public offering
at a price of $41.07 per unit, or $39.74 per unit net of the underwriter's discount, for net proceeds of approximately $319.3
million after deducting the underwriter's discount and offering expenses. We used the net proceeds from the offering to fund a
portion of the consideration for the acquisition of the initial 33.3% membership interest in Pony Express as discussed in Note 4
– Acquisitions.
Distributions to Holders of Common Units, General Partner Units and Incentive Distribution Rights
Our partnership agreement requires us to distribute our available cash, as defined in the partnership agreement, to
unitholders of record on the applicable record date within 45 days after the end of each quarter. Our partnership agreement
provides that available cash, each quarter, is first distributed to the common unitholders and the general partner on a pro rata
basis until each common unitholder has received $0.2875 per unit, which amount is defined in our partnership agreement as the
minimum quarterly distribution ("MQD").
The following table shows the distributions for the periods indicated:
Limited Partner
Common and
Subordinated
Units
Distributions
General Partner
Incentive
Distribution
Rights
General
Partner
Units
Distribution
per Limited
Partner
Common and
Subordinated
Unit
Total
$
58,793
$
28,358
$
1,008
$ 88,159
$
(in thousands, except per unit amounts)
57,332
54,442
48,238
42,984
36,347
35,135
31,322
23,782
20,092
18,596
13,288
26,987
24,262
19,816
15,332
11,567
10,418
6,934
4,039
1,208
758
126
976
911
830
724
660
627
530
473
363
330
274
85,295
79,615
68,884
59,040
48,574
46,180
38,786
28,294
21,663
19,684
13,688
0.8150
0.7950
0.7550
0.7050
0.6400
0.6000
0.5800
0.5200
0.4850
0.4100
0.3800
0.3250
Three Months Ended
Date Paid
December 31, 2016.... February 14, 2017.......
September 30, 2016 ... November 14, 2016 ....
June 30, 2016............. August 12, 2016..........
March 31, 2016.......... May 13, 2016 ..............
December 31, 2015.... February 12, 2016.......
September 30, 2015 ... November 13, 2015 ....
June 30, 2015............. August 14, 2015..........
March 31, 2015.......... May 14, 2015 ..............
December 31, 2014.... February 13, 2015.......
September 30, 2014 ... November 14, 2014 ....
June 30, 2014............. August 14, 2014..........
March 31, 2014.......... May 14, 2014 ..............
Subordinated Units
Under the terms of TEP's partnership agreement and upon the payment of the quarterly cash distribution to unitholders on
February 13, 2015, the subordination period ended. As a result, the 16,200,000 subordinated units then held by TD converted
into common units on a one for one basis on February 17, 2015.
General Partner Units
As of December 31, 2016, the general partner owns an approximate 1.14% general partner interest in TEP, represented by
834,391 general partner units. Under TEP's partnership agreement, the general partner may at any time, but is under no
obligation to, contribute additional capital to TEP in order to maintain or attain a 2% general partner interest.
Incentive Distribution Rights
The general partner also owns all of the IDRs. IDRs represent the right to receive an increasing percentage (13%, 23% and
48%) of quarterly distributions of available cash from operating surplus after the MQD and each target distribution level has
been achieved. The general partner may transfer these rights separately from its general partner interest, subject to restrictions
in our partnership agreement.
The following discussion related to incentive distributions assumes that our general partner holds a 2% general partner
interest and continues to own all of the IDRs.
117
If for any quarter:
• We have distributed available cash from operating surplus to all of the common unitholders (and during the
subordination period, to the subordinated unitholders) in an amount equal to the MQD for each outstanding unit for
such quarter; and
• We have distributed available cash from operating surplus on outstanding common units in an amount necessary to
eliminate any cumulative arrearages in the payment of the MQD to common unitholders;
then, we will distribute additional available cash from operating surplus for that quarter among the unitholders and the
general partner in the following manner:
•
•
•
•
first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.3048
per unit for that quarter (the "first target distribution");
second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of
$0.3536 per unit for that quarter (the "second target distribution");
third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.4313
per unit for that quarter (the "third target distribution"); and
thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
•
less the amount of cash reserves established by our general partner to:
provide for the proper conduct of our business (including reserves for future capital expenditures, for
anticipated future credit needs subsequent to that quarter, for legal matters and for refunds of collected rates
reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings);
comply with applicable law or regulation, or any of our debt instruments or other agreements; or
provide funds for distributions to unitholders and to our general partner for any one or more of the next four
quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the
establishment of such reserves will prevent us from distributing the MQD on all common units and any
cumulative arrearages on such common units for the current quarter);
•
plus, if our general partner so determines, all or any portion of the cash on hand on the date of distribution of available
cash for the quarter, including cash on hand resulting from working capital borrowings made subsequent to the end of
such quarter.
Other Contributions and Distributions
During the year ended December 31, 2016, TEP was deemed to have made noncash capital distributions of $280.0 million
and $34.0 million to the general partner, which represent the excess purchase price over the carrying value of the additional
31.3% membership interest in Pony Express acquired effective January 1, 2016 and the derecognition of a portion of the
derivative asset associated with the partial exercise of the call option, respectively. See Note 4 – Acquisitions for additional
information regarding these transactions. During the year ended December 31, 2016, TEP also received contributions of $17.9
million from TD to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed
in Note 18 – Legal and Environmental Matters, and recognized contributions from and distributions to noncontrolling interests
of $9.3 million, and $6.5 million, respectively, which primarily consisted of activity associated with TD's 2% noncontrolling
interest in Pony Express.
During the year ended December 31, 2015, TEP was deemed to have made a noncash capital distribution of $324.3
million to the general partner, which represents the excess purchase price over the carrying value of the additional 33.3%
membership interest in Pony Express acquired effective March 1, 2015. See Note 4 – Acquisitions for additional information
regarding the transaction. We also recognized contributions from noncontrolling interests of $110.1 million, which consisted
primarily of contributions from TD to Pony Express to fund construction of the lateral in Northeast Colorado, and distributions
to noncontrolling interests of $69.5 million, which consisted primarily of distributions from Pony Express to TD.
118
During the year ended December 31, 2014, we received net contributions of $312.1 million, $27.5 million, and $5.4
million from the Predecessor Entities, TD, and noncontrolling interests, respectively. Net contributions of 312.1 million from
the Predecessor Entities is composed of net contributions of $612.1 million relating to the cash management agreements with
TD, as well as a cash distribution of $300 million of the proceeds from the issuance of the preferred membership interest to
TEP from Pony Express to TD pursuant to the Pony Express Contribution and Sale Agreement. As discussed in Note 2 –
Summary of Significant Accounting Policies, prior to April 1, 2014 for Trailblazer and prior to September 1, 2014 for Pony
Express, the net amount of transfers for loans made each day through the centralized cash management system with TD, less
reimbursement payments under the agency agreement described in Note 5 – Related Party Transactions, was recognized as net
equity contributions or distributions during that time period. There were no equity contributions or distributions made to TD
subsequent to Trailblazer's acquisition by TEP on April 1, 2014 or the acquisition of Pony Express effective September 1, 2014.
The 27.5 million contribution from TD represents the difference between the carrying amount of the Replacement Gas
Facilities and the proceeds received from TD, as discussed in Note 5 – Related Party Transactions. The $5.4
million contribution from noncontrolling interests represents the cash contributed to Pony Express from TD to fund the
quarterly preference payment to TEP as discussed in Note 4 – Acquisitions. During the year ended December 31, 2014, Pony
Express made a distribution of $5.4 million to TD, which was settled via the Pony Express cash management agreement.
During the year ended December 31, 2014, TEP was deemed to have made a noncash, net capital distribution of $72.9
million to the general partner, which represents the excess purchase price over the carrying value of the Trailblazer net assets
acquired on April 1, 2014. Also during the year ended December 31, 2014, TEP was deemed to have made a capital distribution
of $8.7 million to the general partner, which represents the excess purchase price, consisting of $27 million in cash and limited
partner common units valued at $3.0 million issued directly to TD, over the net book value of the 1.9585% membership interest
in Pony Express transferred from TD to TEP in accordance with the Pony Express Contribution and Sale Agreement. See Note
4 – Acquisitions for additional information regarding the Trailblazer and Pony Express acquisitions.
13. Commitments & Contingent Liabilities
Leases
Rent expense under operating leases and right of way agreements totaled approximately $30.1 million, $25.8 million, and
$4.7 million for the years ended December 31, 2016, 2015, and 2014, respectively.
At December 31, 2016, future minimum rental commitments under major, non-cancelable operating leases were as follows
(in thousands):
Year
2017......................................................................................
$
2018......................................................................................
2019......................................................................................
2020......................................................................................
2021......................................................................................
Thereafter .............................................................................
Total...................................................................................... $
Total
28,377
28,788
29,328
29,959
30,374
448,853
595,679
Operating leases and service contracts consist of leases for crude oil storage as well as office space and equipment.
Pony Express entered into a lease agreement with Deeprock on November 7, 2012 for the use by Pony Express of storage
capacity at the Deeprock tank storage facility near Cushing, Oklahoma. The lease has a five-year term which commenced on
October 7, 2014. Pony Express made upfront payments totaling $10.9 million, of which $4.6 million was paid in 2013 and $6.3
million was paid in 2014. The upfront payments are recorded as "Deferred charges and other assets" on the accompanying
consolidated balance sheets and will be amortized over the lease term. Pony Express has the right to extend the term of the
lease for additional periods of five or two years, not to exceed a total of 20 years from when the lease commences. Future
minimum rental commitments in the table above assume renewal of the Deeprock lease for the full 20-year term as the storage
capacity at Deeprock is integral to the operations of the Pony Express System and renewal of the lease is reasonably assured as
a result.
119
On August 26, 2014, Pony Express entered into a lease agreement with Sterling for the use by Pony Express of storage
capacity at the Sterling tank storage facility in northeast Colorado. The lease has a five-year term which commenced on May 1,
2015. Pony Express has the right to extend the term of the lease for additional periods of five years, not to exceed a total of 20
years from the commencement of the lease agreement. Future minimum rental commitments in the table above assume renewal
of the Sterling lease for the full 20-year term as the storage capacity at Sterling is integral to the operations of the lateral in
Northeast Colorado and renewal of the lease is reasonably assured as a result. As discussed in Note 21 – Subsequent Events,
effective January 1, 2017 we acquired 100% of the issued and outstanding membership interests in Tallgrass Terminals, LLC
("Terminals"), which owns the Sterling Terminal.
Capital Expenditures
We had committed approximately $6.5 million for the future purchase of property, plant and equipment at December 31,
2016.
Other Purchase Obligations
Other purchase obligations primarily represent costs associated with Western's freshwater delivery and produced water
gathering and disposal systems acquired in December 2015. Actual costs associated with these contracts totaled approximately
$1.4 million and $4,000 for the years ended December 31, 2016 and 2015, respectively.
At December 31, 2016, future minimum commitments under long-term, non-cancelable contracts for other purchase
obligations were as follows (in thousands):
Year
2017......................................................................................
$
2018......................................................................................
2019......................................................................................
2020......................................................................................
2021......................................................................................
Thereafter .............................................................................
Total...................................................................................... $
Total
1,843
1,843
1,858
1,858
27
69
7,498
14. Net Income per Limited Partner Unit
The Partnership's net income is allocated to the general partner and the limited partners, including the holders of the
subordinated units, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid
to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners' interest in
net income, less general partner incentive distributions, by the weighted average number of outstanding limited partner units
during the period. As discussed in Note 12 – Partnership Equity and Distributions, the subordinated units were converted to
common units effective February 17, 2015.
We compute earnings per unit using the two-class method for Master Limited Partnerships as prescribed in the FASB
guidance. The two-class method requires that securities that meet the definition of a participating security be considered for
inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of
the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general
partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would
actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has
other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings
for a particular period.
We calculate net income available to limited partners based on the distributions pertaining to the current period's net
income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions
over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the
partnership agreement and as further prescribed in the FASB guidance under the two-class method.
The two-class method does not impact our overall net income or other financial results; however, in periods in which
aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per
limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the
incentive distribution rights (which are currently held by our general partner), even though we make distributions on the basis
of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions
for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.
120
Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of
units outstanding during each period. Diluted earnings per unit reflects the potential dilution of common equivalent units that
could occur if equity participation units are converted into common units.
All net income or loss from Trailblazer prior to its acquisition on April 1, 2014 and Pony Express prior to its acquisition
effective September 1, 2014 is allocated to predecessor operations in the table below. Historical earnings of transferred
businesses for periods prior to the date of those common control drop-down transactions are solely those of the general partner,
and therefore we have appropriately excluded any allocation to the limited partner units when determining net income available
to common and subordinated unitholders. We present the financial results of any transferred business prior to the drop down
transaction date in the line item "Predecessor operations interest in net income" in the table below.
The following table illustrates the Partnership's calculation of net income per common and subordinated unit for the years
ended December 31, 2016, 2015 and 2014:
Year Ended
December 31,
2016
Year Ended
December 31,
2015
(in thousands, except per unit amounts)
Year Ended
December 31,
2014
Net income .............................................................................. $
Net (income) loss attributable to noncontrolling interests .
Net income attributable to partners .........................................
Predecessor operations interest in net income ........................
General partner interest in net income ....................................
Net income available to common and subordinated
unitholders............................................................................... $
Basic net income per common and subordinated unit ............ $
Diluted net income per common and subordinated unit ......... $
Basic average number of common and subordinated units
outstanding ..............................................................................
Equity Participation Unit equivalent units ..............................
Diluted average number of common and subordinated units
outstanding ..............................................................................
$
$
$
$
267,894
(4,365)
263,529
—
(102,465)
161,064
2.26
2.23
71,150
957
72,107
184,814
(24,268)
160,546
—
(46,478)
114,068
1.95
1.91
$
$
$
$
58,597
978
59,575
59,329
11,352
70,681
(1,508)
(7,399)
61,774
1.39
1.36
44,346
1,048
45,394
15. Major Customers and Concentration of Credit Risk
During the year ended December 31, 2016 two non-affiliated customers, Continental Resources, Inc. ("Continental
Resources") and Shell Trading (US) Company ("Shell"), accounted for $97.8 million (16%) and $76.2 million (13%) of our
total operating revenues, respectively. During the year ended December 31, 2015 two non-affiliated customers, Continental
Resources and Shell, accounted for $84.5 million (16%) and $78.6 million (15%) of our total operating revenues, respectively.
In 2016 and 2015, revenues from Continental Resources were earned in our Crude Oil Transportation & Logistics segment,
while revenues from Shell were earned in our Crude Oil Transportation & Logistics, Processing & Logistics, and Natural Gas
Transportation & Logistics segments. During the year ended December 31, 2014 one non-affiliated customer, Phillips 66,
accounted for $113.6 million (31%) of our total operating revenues. All of the Phillips 66 revenues were earned in our
Processing & Logistics segment.
For the year ended December 31, 2016, the percentage of segment revenues from the top ten non-affiliated customers for
each segment was as follows:
Crude Oil Transportation & Logistics...............................
Natural Gas Transportation & Logistics ...........................
Processing & Logistics......................................................
95%
58%
91%
Percentage of
Segment Revenue
We attempt to mitigate credit risk by seeking collateral or financial guarantees and letters of credit from customers with
specific credit concerns. In support of credit extended to certain customers, we had received prepayments of $4.9 million and
$4.7 million at December 31, 2016 and 2015, respectively, included in the caption "Other current liabilities" in the
accompanying consolidated balance sheets.
121
16. Equity-Based Compensation
Long-term Incentive Plan
Effective May 13, 2013, the general partner adopted a Long-term Incentive Plan ("LTIP") pursuant to which awards in the
form of unrestricted units, restricted units, equity participation units, options, unit appreciation rights or distribution equivalent
rights may be granted to employees, consultants, and directors of the general partner and its affiliates who perform services for
or on behalf of TEP or its affiliates, including TD. Vesting and forfeiture requirements are at the discretion of the board of
directors of the general partner (the "Board") and can be delegated to a committee of the Board.
The LTIP limits the number of units that may be delivered pursuant to vested awards to 10,000,000 common units.
Common units canceled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for
delivery pursuant to other awards. The plan is administered by the Board or a committee thereof, which is referred to as the
plan administrator.
The Board may generally terminate or amend the LTIP at any time with respect to any units for which a grant has not yet
been made. The Board also has the right to alter or amend the LTIP or any part of the plan from time to time, including
increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units
are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or
benefits of the participant without the consent of the participant. The LTIP will expire on the earliest of (i) the date common
units are no longer available under the plan for grants, (ii) termination of the plan by the Board or (iii) May 13, 2023.
Equity Participation Units
On June 26, 2013, TEP's general partner approved the grant of up to 1.5 million equity participation units ("EPUs") for
issuance to employees and 177,500 EPUs to certain Section 16 officers under the LTIP. The EPU grants under the LTIP are
measured at their grant date fair value. The EPUs granted are non-participating with respect to distributions, therefore the grant
date fair value is discounted from the grant date fair value of TEP's common units for the present value of the expected future
distributions during the vesting period. Total equity-based compensation cost related to the EPU grants was approximately $7.9
million, $9.3 million, and $10.2 million for the years ended December 31, 2016, 2015, and 2014, respectively. Of the total
compensation cost, $5.8 million, $5.1 million, and $5.1 million for the years ended December 31, 2016, 2015, and 2014,
respectively, were recognized as compensation expense at TEP and the remainder was allocated to TD. As of December 31,
2016, $12.0 million of total compensation cost related to non-vested EPUs is expected to be recognized over a weighted
average period of 2.2 years, a portion of which will be charged to TD.
The following table summarizes the changes in the EPUs outstanding for the years ended December 31, 2016, 2015 and
2014:
Equity Participation
Units
Weighted Average
Grant Date Fair
Value
Outstanding at December 31, 2013 ...................................................................
Granted .........................................................................................................
Forfeited........................................................................................................
Outstanding at December 31, 2014 ...................................................................
Granted .........................................................................................................
Vested (1)........................................................................................................
Forfeited........................................................................................................
Outstanding at December 31, 2015 ...................................................................
Granted............................................................................................................
Vested (1) ..........................................................................................................
Forfeited ..........................................................................................................
Outstanding at December 31, 2016 ...................................................................
1,474,250
$
147,500
(96,000)
1,525,750
338,591
(480,555)
(58,825)
1,324,961
94,750
(35,998)
(43,829)
1,339,884
$
17.54
30.23
(17.83)
18.75
40.01
(19.39)
(16.98)
24.11
35.12
(23.74)
(20.08)
24.92
(1) During the years ended December 31, 2016 and 2015, approximately 24,933 and 344,383 common units (net of tax
withholding of approximately 11,065 and 136,172 common units) were issued in connection with the settlement of
vested awards, respectively.
122
17. Regulatory Matters
There are currently no proceedings challenging the currently effective transportation rates of Pony Express, Rockies
Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT") or Trailblazer Pipeline Company LLC ("Trailblazer").
Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable law, to challenge the rates that we
charge at our regulated entities. Further, applicable law governing service by Pony Express allows parties having standing to
file complaints in regard to existing tariff rates and provisions. If the complaint is not resolved, the FERC may conduct a
hearing and order a crude oil pipeline like the Pony Express System 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 can provide no assurance that
current rates will remain unchallenged. Any successful challenge could have a material, adverse effect on our future earnings
and cash flows.
Pony Express
On September 19, 2014 Pony Express filed with the FERC to adopt a tariff for initial local non-contract rates as well as
initial Rules and Regulations in accordance with the Interstate Commerce Act to be effective starting on October 1, 2014. Local
Contract Tariff rates were filed with the FERC on October 29, 2014 to be effective starting November 1, 2014. Joint Contract
Tariff rates for oil received into the Pony Express pipeline system from the Belle Fourche Pipeline were filed on October 16,
2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express System from
Hiland Pipeline Company were filed on February 27, 2015 and effective April 1, 2015.
On May 18, 2015, Pony Express filed with the FERC to implement tariff contract rates for Pony Express' newly
constructed lateral in Northeast Colorado effective June 1, 2015.
On May 29, 2015, tariff filings were made with the FERC in Docket No. IS15-492-000 to increase the Pony Express local
contract rates for service from the Guernsey origin, and for local non-contract rates from all origins, by amounts reflecting the
FERC annual index adjustment of approximately 4.6% effective July 1, 2015. A tariff filing was also made in Docket No.
IS15-493-000 on that date to increase joint tariff contract rates for service on Pony Express by approximately 4.6% effective
July 1, 2015.
On October 29, 2015, Pony Express made a tariff filing with the FERC in Docket No. IS16-42-000 to increase the contract
rates under its Local Pipeline Tariff for transportation from receipt points on its lateral in Northeast Colorado to various
delivery points in Oklahoma, by an amount reflecting the most recent FERC annual index adjustment of approximately 4.6%
effective December 1, 2015.
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%.
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
zones as the service provided pursuant to the Foundation and Anchor Shipper NRAs.
In September 2014, the FERC accepted amended contracts with three 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. Prior to December
2015, only one shipper with current MFN rights was still a party to the proceeding.
2015 Annual FERC Fuel Tracking Filings - Docket No. RP15-584-000
On February 27, 2015, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2015
in Docket No. RP15-584-000. This filing incorporated the revised fuel and lost and unaccounted-for and power cost tracker
mechanisms filed in Docket No. RP14-1003. The FERC issued an order accepting the filing on March 26, 2015 and on April 9,
2015, accepted an errata to the February 27, 2015 filing reflecting a corrected rate for the Cheyenne Booster rate (PCT
Reimbursement Charge).
123
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 proposed facilities will increase 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 0.8 Bcf/d on January 6, 2017.
2016 Annual and Interim FERC Fuel Tracking Filings - 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. The filing reflected a corrected rate for a previous
inadvertent error made in the allocation of Overthrust, Echo Springs, and Wamsutter fuel between non-expansion and
expansion volumes during the period from July 2014 through July 2016.
Electric Power Charge Clarification - 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 (i.e. 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.
TIGT
Pony Express Abandonment – FERC Docket CP12-495
On August 6, 2012, TIGT filed an application to: (1) abandon for FERC purposes approximately 433 miles of mainline
natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the "Pony Express
Assets"), and the natural gas service therefrom, by transferring those assets to Pony Express, which subsequently converted the
Pony Express Assets into crude oil pipeline facilities; and (2) construct and operate certain replacement-type facilities
necessary to continue service to existing natural gas firm transportation customers following the conversion, which we refer to
as the Replacement Gas Facilities. This project is referred to as the "Pony Express Abandonment." The FERC abandonment
does not constitute an abandonment for accounting purposes. Pursuant to the terms of the Purchase and Sale Agreement filed
with the FERC and cited by the FERC in approving the Pony Express Abandonment, Pony Express is required to reimburse
TIGT for the net book value of the Pony Express Assets plus other TIGT incurred costs required to construct the Replacement
Gas Facilities and to arrange substitute gas transportation services to certain TIGT shippers.
The Pony Express Abandonment and completion of the Pony Express Project by Pony Express re-deployed existing
pipeline assets to meet the growing market need to transport crude oil while at the same time continuing to operate TIGT's
natural gas transportation facilities to meet all current and expected needs of its natural gas customers. By a FERC order issued
September 12, 2013, TIGT was granted authorization to abandon the Pony Express Assets and construct the Replacement Gas
Facilities. On October 7, 2013 TIGT commenced the mobilization of personnel and equipment for the construction of the
Replacement Gas Facilities necessary to complete the Pony Express Abandonment to continue service to existing TIGT
customers. In December 2013, TIGT removed the Pony Express Assets from gas service and sold those assets to Pony Express.
On May 1, 2014, TIGT commenced commercial service through all of the Replacement Gas Facilities, with the exception of
Units 3 and 4 at the Tescott Compressor Station. Service through Units 3 and 4 at the Tescott Compressor Station commenced
on May 30, 2014.
124
General Rate Case Filing - FERC Docket RP16-137
On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the National Gas Act
("NGA"). The rate case proposed a general system-wide increase in the maximum tariff rates for all firm and interruptible
services offered by TIGT. In addition, TIGT proposed certain changes to the transportation rate design of its system to replace
the current rate zone structure with a single "postage stamp" rate. TIGT also proposed new incremental charges, including (i) a
charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a Cost Recovery
Mechanism ("CRM") charge to completely or partially reimburse TIGT for certain expenses and costs it incurs to comply with
anticipated new PHMSA and EPA regulations. TIGT also proposed to replace its fixed fuel and lost and unaccounted for
("FL&U") charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to
reflect the previous period's under/over collection and the forecasted FL&U expense for the upcoming period. TIGT also
proposed to implement a power cost tracker to recover the actual power costs incurred by TIGT to power its compressors.
Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under
the NGA and the FERC's regulations, TIGT's shippers and other interested parties, including the FERC's Trial Staff, have a
right to challenge any aspect of TIGT's rate case filing. Accordingly, numerous TIGT customers protested aspects of TIGT's
NGA Section 4 rate filing.
On November 30, 2015, the FERC issued an order accepting and suspending the proposed rates and a majority of the
proposed tariff records to be effective upon motion May 1, 2016, subject to refund, certain modifications to TIGT's proposed
CRM charge, and the outcome of an evidentiary hearing before a FERC Administrative Law Judge (the "TIGT Suspension
Order"). In the TIGT Suspension Order, the FERC also accepted two tariff records related to force majeure events and
reservation charge crediting to be effective December 1, 2015, subject to certain modifications. On December 21, 2015, TIGT
made a compliance filing with the FERC to modify TIGT's proposed CRM charge and update the tariff records related to force
majeure events and reservation charge crediting as directed by the FERC in the TIGT Suspension Order. No comments or
protests were filed in response to the compliance filing and the FERC accepted the compliance filing on February 1, 2016. On
March 31, 2016, the FERC issued an order denying certain rehearing requests pertaining to the proposed CRM charge and
removed from hearing the non-rate issues related to proposed pro forma tariff records, placing the non-rate issues under a
separate review process, and allowing interveners further opportunity to comment on the pro forma tariff. TIGT and certain
intervenors have since filed additional information and/or comments with respect to the proposed pro forma tariff. On February
3, 2017, the FERC accepted TIGT’s pro forma tariff records, subject to conditions, and directed TIGT to file the actual tariff
records within 30 days.
On June 8, 2016, TIGT filed an Offer of Settlement (the "TIGT Rate Case Settlement") with the FERC, which resolved all
issues set for hearing. On July 14, 2016, the presiding Administrative Law Judge certified the TIGT Rate Case Settlement to the
FERC, finding that settlement is uncontested, presents no issues of first impression, has no FERC policy implications, and
appears to be just, reasonable and in the public interest. On November 2, 2016, the FERC issued an order approving the TIGT
Rate Case Settlement, finding that it appears to be fair and reasonable and in the public interest. The FERC also directed TIGT
to file revised tariff records to implement the TIGT Rate Case Settlement, which TIGT filed, and the FERC subsequently
approved on December 23, 2016. The November 2, 2016 order also terminated all matters in the TIGT rate case, apart from the
non-rate issues related to the pro forma tariff which remain pending before the FERC. Per the terms of the TIGT Rate Case
Settlement, TIGT is required to file a new general rate case on May 1, 2019 (provided that such rate case is not pre-empted by a
pre-filing settlement), and no Supporting/Non-Contesting Participant, as defined in the TIGT Rate Case Settlement, is
permitted to, inter alia, file to change the settlement rates or any other provisions set forth in the TIGT Rate Case Settlement
prior to May 1, 2019.
Trailblazer
2013 Rate Case Filing - Docket No. RP13-1031
On January 22, 2014, Trailblazer, the FERC's Trial Staff, and the active parties in the pipeline's general rate case finalized a
settlement in principle resolving the pending rate issues, including: (i) establishing transportation rates, as well as fuel and lost
and unaccounted for charges; (ii) providing a limited profit sharing arrangement for certain revenues earned from interruptible
and short-term firm transport; and (iii) setting the minimum and maximum time that can elapse before Trailblazer's next rate
case at the FERC. Trailblazer filed a motion with the FERC's Chief Administrative Law Judge to accept the settlement rates on
an interim basis ("Interim Rates") while the participants finalized a definitive settlement. The Chief Administrative Law Judge
accepted the Interim Rates effective February 1, 2014. On February 24, 2014, Trailblazer filed an uncontested offer of
settlement ("Stipulation and Agreement") among active party shippers. The Stipulation and Agreement established the Interim
Rates as final settlement rates effective February 1, 2014, subject to the issuance of refunds to certain shippers for January 2014
transportation services and revised fuel and lost and unaccounted for rates, effective July 1, 2014. On March 11, 2014, the
Presiding Administrative Law Judge certified the Stipulation and Agreement. On May 29, 2014, the FERC approved the
Stipulation and Agreement. On June 30, 2014, Trailblazer filed tariff sheets to implement the Stipulation and Agreement
effective July 1, 2014. Estimated refunds were reserved from revenues recorded in January 2014. On July 1, 2014, Trailblazer
125
submitted refunds to its customers for amounts collected in excess of amounts that would have been collected under the
Settlement Rates, with interest, and on July 18, 2014, filed a report of refunds with the FERC. The FERC issued orders
accepting the tariff sheets with the requested effective date of July 1, 2014 and accepting the refund report filing on July 25,
2014 and August 7, 2014, respectively. Per the terms of the Stipulation and Agreement, Trailblazer is required to file a new rate
case with rates to be effective by January 1, 2019.
2015 Annual Fuel Tracker Filing - Docket No. RP15-841-000
On April 1, 2015, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2015 in Docket
No. RP15-841-000. This filing incorporates the revised fuel tracker and power cost tracker mechanisms agreed to in the
Stipulation and Agreement, which resolves all outstanding issues related to Trailblazer fuel recoveries. The FERC approved this
filing on April 23, 2015.
2016 Annual Fuel Tracker Filing – 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.
18. Legal and Environmental Matters
Legal
In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of
our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of
such routine items will not have a material adverse impact on our business, financial position, results of operations, or cash
flows.
We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and
reasonably estimable and, accordingly, have recorded no reserve for legal claims as of December 31, 2016 and 2015.
Rockies Express
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's bankruptcy estate. The settlement agreement includes Ultra's agreement to: (i) make a cash
payment to Rockies Express of $150 million in accordance with the plan of reorganization, but no later than October 30, 2017;
and (ii) enter 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. The settlement is part of
Ultra's Chapter 11 reorganization plan, which must be submitted to the U.S. Bankruptcy Court for approval.
126
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 entered into a binding settlement agreement to resolve the claims
brought by Michels in exchange for a $10 million cash payment by Rockies Express. The cash payment will be paid promptly
after entering into the definitive agreement with respect to the settlement.
Environmental, Health and Safety
We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality,
waste disposal, and other environmental matters. We believe that compliance with these laws will not have a material adverse
impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future
events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not
cause us to incur significant costs. We had environmental reserves of $4.0 million and $4.8 million at December 31, 2016 and
2015, respectively.
TMID
Casper Plant, EPA Notice of Violation
In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of
the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, 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.
Casper Gas Plant
On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the
Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with
WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues
and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as
well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely.
Settlement negotiations with WDEQ are currently ongoing.
Trailblazer
Pipeline Integrity Management Program
Trailblazer is currently operating at less than its current maximum allowable operating pressure ("MAOP"), public notice
of which was first provided in June 2014. As a result of smart tool surveys in 2014, Trailblazer has identified
approximately 25 - 35 miles of pipe that will likely need to be repaired or replaced in order for the pipeline to operate at its
MAOP of 1,000 pounds per square inch across all segments of the Trailblazer Pipeline. Such repair or replacement will likely
occur over a period of years, depending upon the remediation and repair plan implemented by Trailblazer. Segments of the
Trailblazer Pipeline that require full replacement could cost as much as $2.7 million per mile and repair costs on sections of the
pipeline that do not require full replacement are expected to be less on a per mile basis. The current pressure reduction is not
expected to prevent Trailblazer from fulfilling its firm service obligations at existing subscription levels and to date it has not
had a material adverse financial impact on us.
127
With respect to the approximately 25 - 35 miles of pipe that has been identified, Trailblazer completed 32 excavation digs
in 2015 at an aggregate cost of approximately $1.3 million. During 2016, Trailblazer completed additional excavation digs and
replaced approximately 8 miles of pipe at an aggregate cost of approximately $19.0 million. Trailblazer is currently exploring
all possible cost recovery options to recover such out of pocket costs, including recovery through a general rate increase,
negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.
In connection with our acquisition of the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for any out of
pocket costs incurred between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the
extent that such actions are necessitated by external corrosion caused by the pipeline's disbonded Hi-Melt CTE coating. The
contractual indemnity provided by TD is capped at $20 million and is subject to an annual $1.5 million deductible. In
connection with the 2016 repairs and remediation on the Trailblazer Pipeline, TEP has received $17.9 million from TD pursuant
to the contractual indemnity.
Pony Express
Pipeline Integrity
In connection with certain crack tool runs on the Pony Express System completed in 2015 and 2016, Pony Express
completed approximately $9.8 million of remediation for anomalies identified on the Pony Express System associated with
portions of the pipeline converted from natural gas to crude oil service, and expects to complete additional remediation in 2017
on the Pony Express System of approximately $9 million.
Terminals
System Failures
In January 2017, 10,000 bbls of crude oil were released at the Sterling Terminal, which was acquired as part of the
Terminals acquisition on January 1, 2017 as discussed in Note 21 – Subsequent Events. Initial reviews indicate that the release
was restricted to the containment area located at the Sterling Terminal and was the result of a defective roof drain system on a
storage tank. To date, approximately 9,000 bbls have been recovered. We believe that the total cost to remediate the release will
be less than $500,000.
19. Reportable Segments
Our operations are located in the United States. We are organized into three reportable segments: (1) Crude Oil
Transportation & Logistics, (2) Natural Gas Transportation & Logistics, and (3) Processing & Logistics.
Crude Oil Transportation & Logistics
The Crude Oil Transportation & Logistics segment is engaged in the ownership and operation of the Pony Express System,
which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, and other
nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The
Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System
just east of Sterling, Colorado and was placed in service in the second quarter of 2015.
Natural Gas Transportation & Logistics
The Natural Gas Transportation & Logistics segment is engaged in the ownership and operation of FERC-regulated
interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such
as third-party LDCs), industrial users and other shippers. The Natural Gas Transportation & Logistics segment includes our
25% membership interest in Rockies Express effective May 6, 2016, as discussed in Note 4 – Acquisitions
Processing & Logistics
The Processing & Logistics segment is engaged in the ownership and operation of natural gas processing, treating and
fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for
transportation to additional end markets, as well as water business services provided primarily to the oil and gas exploration
and production industry and the transportation of NGLs.
Corporate and Other
Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable
segments, such as interest and fees associated with our revolving credit facility, public company costs, and equity-based
compensation expense.
128
These segments are monitored separately by management for performance and are consistent with internal financial
reporting. These segments have been identified based on the differing products and services, regulatory environment and the
expertise required for their respective operations.
We consider Adjusted EBITDA 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, a non-
GAAP measure, 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.
The following tables set forth our segment information for the periods indicated:
Revenue:
Total
Revenue
2016
Inter-
Segment
External
Revenue
Total
Revenue
2015
Inter-
Segment
(in thousands)
External
Revenue
Total
Revenue
2014
Inter-
Segment
External
Revenue
Year Ended December 31,
Crude Oil
Transportation &
Logistics .................. $380,503
Natural Gas
Transportation &
Logistics ..................
128,869
$
— $380,503
$304,227
$
— $304,227
$ 28,343
$
— $ 28,343
(5,641)
123,228
131,657
(5,384)
126,273
140,080
(5,257)
134,823
Processing &
Logistics ..................
101,391
— 101,391
105,697
— 105,697
208,390
— 208,390
Corporate and Other
—
Total revenue ........... $610,763
—
—
—
$ (5,641) $605,122
$541,581
—
—
$ (5,384) $536,197
—
$376,813
—
—
$ (5,257) $371,556
Adjusted EBITDA:
Total
Adjusted
EBITDA
2016
Inter-
Segment
External
Adjusted
EBITDA
Total
Adjusted
EBITDA
2015
Inter-
Segment
(in thousands)
External
Adjusted
EBITDA
Total
Adjusted
EBITDA
2014
Inter-
Segment
External
Adjusted
EBITDA
Year Ended December 31,
Crude Oil
Transportation &
Logistics .................... $264,391
Natural Gas
Transportation &
Logistics ....................
148,622
Processing &
Logistics ....................
15,093
Corporate and Other ..
Reconciliation to Net Income:
(4,622)
Add:
Equity in earnings
of unconsolidated
investment.............
Non-cash loss
allocated to
noncontrolling
interest...................
Gain on
remeasurement of
unconsolidated
investment.............
$ 5,383
$ 269,774
$ 165,204
$ 5,384
$ 170,588
$ 15,711
$ — $ 15,711
(5,641)
142,981
67,368
(5,384)
61,984
67,593
(4,015)
63,578
258
—
15,351
(4,622)
22,746
(2,979)
—
—
22,746
(2,979)
33,089
(2,500)
—
—
33,089
(2,500)
51,780
—
—
129
—
9,377
—
717
10,151
9,388
Less:
Interest expense,
net of
noncontrolling
interest...................
Depreciation and
amortization
expense, net of
noncontrolling
interest...................
Distributions from
unconsolidated
investment.............
Non-cash (loss)
gain related to
derivative
instruments, net of
noncontrolling
interests .................
Non-cash
compensation
expense .................
Non-cash loss
from disposal of
assets .....................
Loss on
extinguishment of
debt .......................
Net income
attributable to
partners ......................
Capital Expenditures:
(40,688)
(15,517)
(7,648)
(85,971)
(75,900)
(1,547)
(5,780)
(1,849)
—
(75,529)
—
—
(5,103)
(4,795)
(226)
(45,389)
(1,464)
184
(5,136)
—
—
$ 263,529
$ 160,546
$ 70,681
Year Ended December 31,
2016
2015
(in thousands)
2014
Crude Oil Transportation & Logistics...................................................... $
Natural Gas Transportation & Logistics...................................................
Processing & Logistics.............................................................................
Corporate and Other .................................................................................
Total capital expenditures......................................................................... $
29,893
$
38,802
$
631,883
28,475
12,351
—
10,478
16,107
—
20,580
13,187
—
70,719
$
65,387
$
665,650
Assets:
December 31, 2016 December 31, 2015
(in thousands)
Crude Oil Transportation & Logistics........................................................................ $
Natural Gas Transportation & Logistics.....................................................................
Processing & Logistics...............................................................................................
Corporate and Other ...................................................................................................
Total assets ................................................................................................................. $
1,410,654
$
1,439,418
1,176,117
411,999
20,201
706,576
409,795
6,285
3,018,971
$
2,562,074
130
20. Selected Quarterly Financial Data (Unaudited)
The following tables summarize our unaudited quarterly financial data for 2016 and 2015:
Quarter Ended 2016
First
Second
Third
Fourth
(in thousands, except per unit amounts)
Total revenues...................................................................... $
Operating income ................................................................ $
Net income........................................................................... $
Net income attributable to partners ..................................... $
Net income allocable to limited partners............................. $
Basic net income per limited partner unit............................ $
Diluted net income per limited partner unit ........................ $
145,405
60,990
45,111
44,070
23,717
0.35
0.35
$
$
$
$
$
$
$
146,931
59,896
93,158
92,048
66,728
0.93
0.92
$
$
$
$
$
$
$
152,125
64,598
61,818
60,734
33,060
0.45
0.45
Total revenues...................................................................... $
Operating income ................................................................ $
Net income........................................................................... $
Net income attributable to partners ..................................... $
Net income allocable to limited partners............................. $
Basic net income per limited partner unit............................ $
Diluted net income per limited partner unit ........................ $
Quarter Ended 2015
First
Second
Third
(in thousands, except per unit amounts)
114,675
25,718
22,990
32,319
24,881
0.47
0.46
$
$
$
$
$
$
$
132,970
56,355
53,231
44,899
33,869
0.56
0.55
$
$
$
$
$
$
$
138,168
52,919
49,550
42,679
30,533
0.50
0.50
$
$
$
$
$
$
$
$
$
$
$
$
$
$
160,661
70,886
67,807
66,677
37,559
0.52
0.51
Fourth
150,384
62,923
59,043
40,649
24,785
0.41
0.40
21. Subsequent Events
Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC
Effective January 1, 2017, we acquired 100% of the issued and outstanding membership interests in Tallgrass Terminals,
LLC ("Terminals") and 100% of the issued and outstanding membership interests in Tallgrass NatGas Operator, LLC
("NatGas") from TD for total cash consideration of $140 million.
Terminals owns several fully operational assets providing storage capacity and additional injection points for the Pony
Express System, including the Sterling Terminal near Sterling, Colorado, the Buckingham Terminal in northeast Colorado, and
a 20% interest in the Deeprock Development Terminal in Cushing, Oklahoma. Terminals also owns projects currently under
development, including acreage in Cushing, Oklahoma and Guernsey, Wyoming which is under development to provide
additional storage capacity and other potential opportunities.
NatGas is the operator of the Rockies Express Pipeline and receives a fee from Rockies Express as compensation for its
services.
Ultra Settlement
In January 2017, Rockies Express reached an agreement to settle its breach of contract claim against Ultra Resources, Inc.
See Note 18 – Legal and Environmental Matters for further discussion.
131
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, 2016, our principal executive officer and principal financial officer
concluded that our disclosure controls and procedures were effective at the reasonable assurance level.
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 financial statements for external purposes in
accordance with generally accepted accounting principles.
As of December 31, 2016, management assessed the effectiveness of our internal control over financial reporting based on
the criteria for effective internal control over financial reporting established in the 2013 "Internal Control - Integrated
Framework," 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, 2016.
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, 2016, 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, 2016 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
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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 Partners, LP
Our general partner manages our operations and activities on our behalf through its directors and officers. Our general
partner is not elected by our unitholders and will not be subject to re-election in the future. Directors of our general partner
oversee our operations. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly
participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the
extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our
general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.
Tallgrass Equity is the sole member of our general partner and has the right to appoint all of the officers and directors of
our general partner. TEGP owns a 36.94% membership interest in, and is the managing member of, Tallgrass Equity. TEGP
Management is TEGP's general partner. Tallgrass Energy Holdings is the sole member of TEGP Management and has the right
to appoint the entire board of directors of TEGP Management, including its independent directors.
Tallgrass Energy Holdings effectively controls our business and affairs through the exercise of its rights as the party that
controls Tallgrass Equity, including its right to appoint members to the board of directors of our general partner. EMG, Kelso
and Tallgrass KC, LLC (an entity owned by certain members of our management, "Tallgrass KC") own, in the aggregate,
approximately 100% of the outstanding membership interests in Tallgrass Energy Holdings. All of the executive officers and
certain of the directors of our general partner are also officers and/or directors of TEGP Management and Tallgrass Energy
Holdings.
As of December 31, 2016, 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 and the Exchange Act. The four independent directors
are Jeffrey A. Ball (for purposes of audit committee participation only), Terrance D. Towner, Roy N. Cook, and Jeffrey R.
Armstrong. 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
of its members are required to meet the independence and experience standards established by the NYSE and the Exchange
Act. As of December 31, 2016, the audit committee of the board of directors of our general partner had three members, each of
whom meet the independence 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 of the executive officers of our general partner are also officers of Tallgrass Equity, TEGP Management, 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. Neither our general partner nor Tallgrass Development and its
affiliates currently receive any management fee or other compensation in connection with the management or operation of our
business. However, our partnership agreement requires us to reimburse our general partner and its affiliates for all expenses
incurred and payments made on our behalf in connection with managing our business. These expenses include salary, bonus,
incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated
to our general partner by its affiliates. Our partnership agreement and the TEP Omnibus Agreement each provides that our
general partner will determine in good faith the expenses that are allocable to us. In addition, the TEP Omnibus Agreement
requires us to reimburse Tallgrass Energy Holdings and its affiliates for expenses they incur in providing general and
administrative services to us. Neither our partnership agreement nor the TEP Omnibus Agreement limits the amount of
expenses for which our general partner or Tallgrass Energy Holdings and its affiliates may be reimbursed.
133
Directors and Executive Officers of Our General Partner
The following table shows information for the directors and executive officers of our general partner as of February 15,
2017.
Name
David G. Dehaemers, Jr.
William R. Moler
Gary J. Brauchle
Christopher R. Jones
Richard L. Bullock
Gary D. Watkins
Frank J. Loverro
Stanley de J. Osborne
Jeffrey A. Ball
John T. Raymond
Terrance D. Towner
Roy N. Cook
Jeffrey R. Armstrong
Age
Position with our General Partner
56
51
43
40
61
44
47
46
42
46
58
59
47
President, Chief Executive Officer and Director
Executive Vice President, Chief Operating Officer and Director
Executive Vice President and Chief Financial Officer
Vice President, General Counsel and Secretary
Vice President, Human Resources, Tax and Risk Management
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
have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships
among any of our directors or executive officers.
David G. Dehaemers, Jr. has been a director and the President and Chief Executive Officer of our general partner since
February 2013 and of TEGP Management since February 2015. Mr. Dehaemers has served as the President and Chief
Executive Officer of Tallgrass Equity since February 2013 and as a director and the President and Chief Executive Officer of
Tallgrass Energy Holdings since August 2012. 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 and of TEGP
Management.
William R. Moler has been a director, Executive Vice President and Chief Operating Officer of our general partner since
February 2013 and of TEGP Management since February 2015. Mr. Moler has also served as Executive Vice President and
Chief Operating Officer of Tallgrass Equity since February 2013 and as a director, Executive Vice President and Chief
Operating Officer of Tallgrass Energy Holdings since October 2012. 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 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 and of TEGP
Management.
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Gary J. Brauchle has been Executive Vice President and Chief Financial Officer of our general partner since February
2013 and of TEGP Management since February 2015. Mr. Brauchle has also served as Executive Vice President and Chief
Financial Officer of 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 Vice President, General Counsel and Secretary of our general partner, TEGP Management
and Tallgrass Energy Holdings since May 2016. Previously, Mr. Jones served as Tallgrass's Assistant General Counsel,
beginning in October 2012. 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.
Richard L. Bullock has been Vice President of Human Resources, Tax and Risk Management of our general partner since
February 2013 and of TEGP Management since February 2015. Mr. Bullock has also served as Vice President of Human
Resources, Tax and Risk Management of Tallgrass Equity since February 2013 and of Tallgrass Energy Holdings since
November 2012. Previously, Mr. Bullock served as the Vice President, Chief Financial Officer and Treasurer of Tallgrass
Development and its general partner. Mr. Bullock previously served as Vice President and Chief Financial Officer of Tallgrass
MLP Fund I, L.P. from 2008 to 2011. Prior to Tallgrass, Mr. Bullock worked at Kinder Morgan Energy Partners, L.P.
Mr. Bullock joined Kinder Morgan Energy Partners, L.P. in 1997 where he served as Vice President, Controller and Chief
Accounting Officer through 2002 and, thereafter served as Vice President-Tax through October 2008. In those roles,
Mr. Bullock was principally responsible for all quarterly and annual SEC filings, integrating the accounting and financial
reporting functions for acquisitions, tax compliance and tax planning for both Kinder Morgan Energy Partners, L.P. and Kinder
Morgan, Inc. Mr. Bullock is a Certified Public Accountant. He received his undergraduate degree in Accounting from Missouri
State University in Springfield, Missouri.
Gary D. Watkins has been Vice President and Chief Accounting Officer and the principal accounting officer of our general
partner since April 2014 and of TEGP Management since February 2015. Mr. Watkins has also served as Vice President and
Chief Accounting Officer of Tallgrass Equity and of 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 2013 and of TEGP Management since
February 2015. Mr. Loverro has also served as a director of Tallgrass Energy Holdings since August 2012. 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 Ajax Resources, LLC, Delphin Shipping LLC, Hunt Marcellus, LLC, and
Poseidon Containers Holdings LLC. 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 boards of
directors of our general partner and of TEGP Management.
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Stanley de J. Osborne has served as a director of our general partner since February 2013 and of TEGP Management since
February 2015. Mr. Osborne has also served as a director of Tallgrass Energy Holdings since August 2012. 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 Ajax Resources, LLC, 4Refuel Canada LP, Hunt Marcellus,
LLC, Logan's Roadhouse, Inc., Traxys S.a.r.l, Power Team Services, LLC and LBM Acquisition, LLC. 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 boards of directors of our general partner and of TEGP
Management.
Jeffrey A. Ball has served as a director of our general partner since May 2013 and of TEGP Management since February
2015. Mr. Ball has also served as the Chairman of the audit committee of our general partner since May 2013 and as the
Chairman of the audit committee of TEGP Management since April 2015. Further, Mr. Ball has served as a director of Tallgrass
Energy Holdings since August 2012. 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 MLPs and the midstream sector.
Mr. Ball has completed over $53 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, Ferus Natural Gas Fuels (CNG), LLC, Ascent Resources, LLC, PRES
Holdings, 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 boards of directors of our
general partner and of TEGP Management.
John T. Raymond has served as a director of our general partner since February 2013 and of TEGP Management since
February 2015. Mr. Raymond has also served as a director of Tallgrass Energy Holdings since August 2012. Mr. Raymond is an
owner and founder of The Energy & Minerals Group. EMG is a diversified natural resource private equity fund manager with
approximately $14.6 billion of regulatory assets under management (RAUM) as of September 30, 2016. EMG has allocated
approximately $9.8 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 boards of directors of our general partner and of TEGP Management.
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 August 2013. Mr. Towner currently provides advisory services to various private equity clients and private
companies. 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.
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Roy N. Cook has served as a director of our general partner since September 2013. 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.
Jeffrey R. Armstrong has served as a director of our general partner and as a member of the audit committee of our general
partner since April 2014. Mr. Armstrong also serves as a director and a member of the audit committee of the general partner of
Arc Logistics Partners LP, a publicly traded limited partnership that is principally engaged in the terminalling, storage,
throughput and transloading of crude oil and petroleum products. In August 2014, Mr. Armstrong became the Chief Executive
Officer of Zenith Energy, LP, a privately held midstream energy company focused on international matters. In October 2014,
Mr. Armstrong became the chairman of MID-SHIP Group, a privately held logistics and transportation company. Mr.
Armstrong is the Manager and controlling shareholder of MID-SHIP Capital LLC, which owns 100% of MID-SHIP Securities
LLC, a member of the Financial Industry Regulatory Authority, or FINRA. From March 2001 until December 2013, Mr.
Armstrong was employed by Kinder Morgan and held various positions within the company including Vice President of
Corporate Strategy and President of the Terminals division. Prior to 2001, Mr. Armstrong was employed by GATX Corporation
where he held various commercial and operational roles including General Manager of the company's east coast operations. He
received his bachelor's degree from the U.S. Merchant Marine Academy and an MBA from the University of Notre Dame. We
believe that Mr. Armstrong's extensive experience as it relates both to general corporate strategy and specifically to the
terminals business, provides valuable 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 three
directors, Jeffrey A. Ball, Terrance D. Towner, and Jeffrey R. Armstrong. Each audit committee member has past experience in
accounting or related financial management experience. The board has determined that all of 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 our general partner and its affiliates, on one hand, and us and our unitholders, on the other. 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 our 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. The conflicts committee currently consists of three independent directors,
Roy N. Cook, Terrance D. Towner, and Jeffrey R. Armstrong, with Mr. Cook currently acting as the Chairman.
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 unitholders. Any unitholder
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
137
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
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 Partners, 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 common units and other equity securities. Officers, directors and greater than 10% unitholders 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 2016 pursuant to Section 16(a) of the Exchange Act, except that on
September 15, 2016, Tallgrass Energy Holdings, Tallgrass Development and Tallgrass Operations filed a Form 4 due July 25,
2016.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Executive Summary and Background
We and our general partner were formed in Delaware in February 2013. We do not directly employ any of the persons
responsible for managing our business. 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 an affiliate of our general partner, Tallgrass Management, LLC ("Tallgrass Management").
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 indirectly controls our general partner. Tallgrass Energy Holdings
owns 100% of Tallgrass Management and 100% of the general partner of TEGP. As of February 15, 2017, TEGP owns a
36.94% membership interest in and is managing member of Tallgrass Equity, which owns a 27.41% limited partner interest in
us and, through its ownership of all of the membership interests in our general partner, our general partner interest and our
incentive distribution rights. Tallgrass Energy Holdings also serves as the general partner of Tallgrass Development. We
reimburse Tallgrass Development for all salaries, benefits and other compensation expenses for employees of Tallgrass
Management (including the Named Executive Officers) to the extent such employees provide services to us pursuant to an
allocation agreed upon between our general partner and Tallgrass Development under the terms of the TEP 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 TEP.
138
Philosophy and Objectives
Since our initial public offering in May 2013, 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 unitholders, 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 unitholders, and to reward success in reaching such
goals.
We use three primary elements of compensation to fulfill that design: salary, cash bonus and long-term equity incentive
awards. Cash 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' cash 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 longer term performance objectives. The primary long-term measure of our performance is our ability to increase quarterly
distributions to our unitholders 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 master limited partnerships, but are moderate relative to energy industry
competitors for people with similar roles and responsibilities.
Cash Bonuses. Our cash bonuses are annual discretionary bonuses in which all of our current Named Executive Officers
potentially participate.
Long-Term Incentive Awards. Our Named Executive Officers receive grants under both the TEP and TEGP LTIP (as
defined below). TEP and TEGP share the same primary long-term performance measure of increasing quarterly distributions
while maintaining safe operations and long-term stable cash flow and financial health. As a result of TEGP’s controlling
membership interest in Tallgrass Equity and indirect ownership of a 27.41% limited partnership interest in TEP, all of TEP’s
general partner interest and all of TEP’s incentive distribution rights, failing to achieve that performance standard at TEP would
be detrimental to TEGP, and vice versa. We therefore believe granting our Named Executive Officers equity participation units
under the TEP LTIP and equity participation shares under the TEGP LTIP appropriately incentivizes our Named Executive
Officers to seek stable distribution growth at both entities. We expect equity participation unit awards under the TEP LTIP will
be the primary long-term equity incentive provided to our Named Executive Officers, and that grants of equity participation
shares will be made pursuant to the TEGP LTIP on a more limited basis.
Long-Term Incentive Awards of TEP. Effective May 13, 2013, our general partner adopted a Long-Term Incentive Plan
("TEP LTIP") pursuant to which awards based on common units of TEP in the form of restricted units, equity participation
units, unit options, unit appreciation rights, distribution equivalent rights and unit awards may be granted to employees,
consultants, and directors of TEP GP and its affiliates who perform services for or on behalf of TEP or its affiliates, including
Tallgrass Development. Historically, we have used equity participation unit grants issued under the TEP LTIP to encourage and
reward timely achievement of certain events or TEP distribution levels and align the long-term interests of our Named
Executive Officers with those of our unitholders. An equity participation unit is the right to receive, upon the satisfaction of
vesting criteria specified in the grant, a common unit.
The vesting conditions applicable to our outstanding equity participation unit awards can generally be divided into three
categories. The first category of awards was granted between June 2013 and September 2014 with vesting of such awards
contingent upon the Pony Express System going into commercial service, which occurred in October 2014. Thus, the awards in
this category will vest as long as the employee satisfies the continuing service requirement set forth in the applicable award
agreement. Generally, one-third of the awards in this category vested on May 13, 2015 and the remaining two-thirds will vest
on May 13, 2017. All of our Named Executive Officers other than Mr. Dehaemers were granted equity participation unit awards
in this category.
139
The second category of our equity participation unit awards were granted 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 we have 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 vesting 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, thus the awards in this category will vest 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 units in this second category.
The third category of our equity participation unit awards were granted 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.
Jones and Mr. Watkins are the only Named Executive Officers that were granted equity participation units in this third category.
Long-Term Incentive Awards of TEGP. Our Named Executive Officers also participate in the Long-Term Incentive Plan
established by the general partner of TEGP effective May 1, 2015 ("TEGP LTIP"). Pursuant to the TEGP LTIP, awards based
on Class A shares of TEGP in the form of restricted shares, equity participation shares, options, share appreciation rights,
distribution equivalent rights and share awards may be granted to employees, consultants, and directors of Tallgrass
Management and its affiliates who perform services for or on behalf of TEGP or its affiliates, including TEP and Tallgrass
Development (such awards, collectively with the awards under the TEP LTIP, the "LTIP Awards"). An equity participation share
is the right to receive, upon the satisfaction of vesting criteria specified in the grant, a TEGP Class A share.
In 2015, grants of equity participation shares were made under TEGP LTIP, including a grant made to Mr. Jones and to Mr.
Watkins, who are thus far the only Named Executive Officers to receive a grant under the TEGP LTIP. 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 TEGP pays a regular quarterly distribution of at least $0.35 on each outstanding Class A share (the "TEGP
Distribution Date") or May 12, 2019. If TEGP has not distributed at least $0.35 on each outstanding Class A Share for any full
quarter ending on or before May 12, 2020, the unvested equity participation shares will expire and no vesting will occur. Mr.
Jones and Mr. Watkins must also remain in continuous employment through the vesting date.
Relation of Compensation Elements to Compensation Objectives
Our compensation program is designed to motivate, reward and retain our Named Executive Officers. Cash bonuses serve
as a near-term motivation and reward for achieving positive short-term results, such as meeting specified distribution 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 cash 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 unitholders, (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. The first category of
awards was granted between June 2013 and September 2015 with vesting contingent, in part, upon the Pony Express System
going into commercial service, which occurred on October 2014. As noted above, two-thirds of those awards still remain
subject to the continuing service requirement set forth in the applicable award agreement, which has supported our goal of
long-term retention of Named Executive Officers. Additionally, one of the primary measures of our performance is our ability
to enhance the ability of our assets to generate distributable cash flow that we can use to increase quarterly distributions to our
unitholders. In the period since our initial public offering through December 31, 2016, our annual distribution per common unit
has grown at a compound annual rate of 35%. This distribution growth has, in part, supported our decision to pay cash bonuses
to our Named Executive Officers over 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.
140
Annual Discretionary Cash Bonuses. Annual discretionary bonuses are determined based on our performance relative to
our annual budget, our distribution 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.
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,
distributable cash flow, distribution coverage, and growth in the annualized quarterly distribution level per common unit
relative to annual growth targets. We also compare our market performance relative to our MLP peers and major indices. Our
primary performance metric is our ability to generate increasing and sustainable cash distributions to our unitholders.
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 cash 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 executive officer. Under existing LTIP Awards, achievement of performance
targets does not shorten the minimum service period requirement.
Application in 2016
At the beginning of 2016, we established the following financial performance objectives for 2016:
•
•
•
Distributable Cash Flow of $285 - 305 million for the year ended December 31, 2016;
Distribution coverage of 1.05 - 1.15x for the year ended December 31, 2016; and
Growth of approximately 20% in our annualized distribution rate for the calendar year 2016.
We achieved all of these goals:
•
•
Our Distributable Cash Flow for the year ended December 31, 2016 was approximately $408.5 million;
Our distribution coverage for the year ended December 31, 2016 was 1.27x; and
• We grew our annualized distribution rate during calendar year 2016 by 27.3%.
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 acquisition by us of a 25% membership interest in Rockies Express from a unit of Sempra U.S. Gas and Power in
May 2016;
141
•
•
The acquisition by us of 100% of the membership interests in Terminals and 100% of the membership interests in
NatGas from Tallgrass Development effective January 1, 2017; and
Substantially completing the Rockies Express Zone 3 Capacity Enhancement Project during 2016, for an additional
0.8 Bcf/d of east-to-west Zone 3 mainline capacity.
For 2016, the elements of compensation were applied as described below.
Salary. In 2016, we did not implement material salary increases for our Named Executive Officers.
Cash 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 2016 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. Pursuant to the TEP LTIP, Mr. Jones and Mr. Watkins each received a grant of 2,000 equity
participation units in 2016. No equity participation shares were granted to a Named Executive Officer under the TEGP LTIP in
2016. As noted below, we believe the substantial direct and indirect equity interests held by our management team, including
our Named Executive Officers, in TEP, TEGP, Tallgrass Equity and Tallgrass Energy Holdings aligns their interests with those
of our unitholders, and is taken into account when considering the level of equity incentives in TEP and TEGP 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 TEP common
units and TEGP 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 TEP or TEGP. Based on the closing price of TEP’s common
units and TEGP’s Class A shares on February 15, 2017, 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 2016. We believe
that the substantial direct and indirect equity interests held by our management team in TEGP, Tallgrass Energy Holdings and
TEP further aligns their interests with those of our unitholders, and is taken into account when considering the level of equity
incentives in TEP and TEGP granted to our Named Executive Officers under our compensation programs.
Equity Ownership in TEP. Our Named Executive Officers collectively own substantial equity in TEP. As of February 15,
2017, our Named Executive Officers directly owned, in the aggregate, 370,101 of our common units (excluding any unvested
LTIP Awards).
Equity Ownership in TEGP and Tallgrass Energy Holdings. Some of our Named Executive Officers directly own Class A
shares in TEGP and some of our Named Executive Officers indirectly own equity interests in Tallgrass Energy Holdings,
Tallgrass Equity and TEGP through Tallgrass KC, an entity controlled by Mr. Dehaemers. As of February 15, 2017, our Named
Executive Officers directly owned, in the aggregate, 572,652 of TEGP's Class A shares (excluding any unvested LTIP Awards).
As of February 15, 2017, Tallgrass KC owned 27,376,110 Class B Shares in TEGP and 27,376,110 Units in Tallgrass Equity,
representing an approximate 17.4% ownership interest in TEGP and Tallgrass Equity, respectively. On such date, Tallgrass KC
also owned approximately 27.61% of the outstanding equity interests in Tallgrass Energy Holdings.
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).
142
Change-in-Control Triggers and Termination Payments. The equity participation unit and equity participation share grants
to our Named Executive Officers include accelerated vesting triggered upon a change of control, as defined in the respective
award agreements. The provision of equity acceleration for defined changes of control 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." 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.
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 10 – Risk Management to our Consolidated Financial
Statements in Item 8.—Financial Statements and Supplementary Data. 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.
143
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 2016 (the "Named Executive Officers") for
services rendered to all Tallgrass-related entities, including TEP, TEGP, Tallgrass Management and Tallgrass Development, for
the fiscal years ending December 31, 2016, 2015 and 2014.
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
Year
2016
2015
2014
2016
2015
2014
2016
2015
2014
Salary (1)
$ 300,000
Bonus (2)
$ 651,467
$ 300,000
$ 601,000
$ 300,000
$ 251,000
$ 300,000
$ 576,468
$ 300,000
$ 551,000
$ 297,118
$ 501,000
$ 294,904
$ 275,000
$ 272,116
$ 576,144
$ 551,000
$ 501,000
Christopher R. Jones (5)
2016
$ 240,068
$ 426,467
Equity
Awards (3)
$
— $
All Other
Compensation (4)
27,544
$
$
$
$
$
$
$
$
$
— $
— $
— $
— $
— $
— $
— $
— $
27,796
31,274
24,544
27,796
30,436
27,537
27,665
26,059
69,836
$
24,486
Total
979,011
928,796
582,274
901,012
878,796
828,554
898,585
853,665
799,175
760,857
$
$
$
$
$
$
$
$
$
$
Vice President, General Counsel
and Secretary
Gary D. Watkins
Vice President and
Chief Accounting Officer
2016
2015
$ 222,975
$ 212,322
$ 201,470
$ 201,000
$
69,836
$ 1,226,264
$
$
23,081
22,152
$
517,362
$ 1,661,738
(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. In our annual report on Form 10-K/A for the year
ended December 31, 2014, the Named Executive Officer's adjusted annual salary, rather than the actual amount of salary
received, was reported in the salary column for 2014.
(2) Represents discretionary bonuses paid in 2017, 2016 and 2015 based on performance in 2016, 2015 and 2014, respectively,
as well as a bonus of $1,000 after tax that was paid to all employees in 2016 and a $1,000 pre-tax bonus that was paid to all
employees in 2015 and 2014.
(3) The amounts in this column include both equity participation units granted pursuant to the TEP LTIP and equity
participation shares granted pursuant to the TEGP LTIP. Mr. Jones and Mr. Watkins were the only Named Executive
Officers to receive grants under the TEP LTIP during 2016 and Mr. Watkins was the only Named Executive Officer to
receive grants under the TEGP LTIP during 2015. In addition, 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
TEP LTIP and equity participation shares granted under the TEGP LTIP. 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 Equity participation units and equity participation shares
are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TEP's common units
or TEGP'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 to our Consolidated
Financial Statements in Item 8.—Financial Statements and Supplementary Data. These amounts do not correspond to the
actual value that will be recognized by the executive.
144
(4) The amounts in the column include the following: contributions under the 401(k) savings plan (includes $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, $26,500 for Mr. Dehaemers, $26,500 for Mr. Moler, $26,477 for Mr. Brauchle, and
$21,232 for Mr. Watkins for the year ended December 31, 2015, and $30,000 for Mr. Dehaemers, $29,615 for Mr. Moler,
and $25,519 for Mr. Brauchle for the year ended December 31, 2014) and the dollar value of premiums paid for group life,
accidental death and dismemberment insurance.
(5) Mr. Jones was appointed Vice President, General Counsel and Secretary of TEP and TEGP effective July 1, 2016.
Narrative Disclosure to Summary Compensation Table
A narrative description of all material factors necessary to an understanding of the information included in the above
Summary Compensation Table is included in "Compensation Discussion and Analysis" and in the footnotes to such tables.
Grants of Plan-Based Awards Table
The following table provides information concerning each grant of an award made to a Named Executive Officer for 2016,
including, but not limited to awards made under the TEP LTIP and TEGP LTIP.
Grant Type
Grant Date
Number of
Shares or
Units
Grant Date
Fair Value of
Awards(1)
Christopher R. Jones
Vice President, General Counsel
TEP Equity Participation Units
11/2/2016
and Secretary
TEGP Equity Participation Shares
—
2,000 (2) $
— (3) $
69,836
—
Gary D. Watkins
Vice President and
TEP Equity Participation Units
11/2/2016
Chief Accounting Officer
TEGP Equity Participation Shares
—
2,000 (2) $
— (3) $
69,836
—
(1) The amounts in this column include EPUs granted pursuant to the TEP LTIP. In addition, 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 TEP LTIP and equity participation shares granted under the TEGP LTIP. 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 EPU and equity participation share
grants are measured at their grant date fair value. The EPUs and equity participation shares are non-participating, therefore
the grant date fair value is discounted from the grant date fair value of TEP's common units or TEGP'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 to our Consolidated Financial Statements in Item 8.—
Financial Statements and Supplementary Data. These amounts do not correspond to the actual value that will be
recognized by the executive.
(2) Vesting of the equity participation units will occur on November 1, 2019.
(3) There were no equity participation shares granted under the TEGP LTIP during the year ended December 31, 2016.
145
Outstanding Equity Awards at Fiscal Year-End
The following table reflects the outstanding equity awards of our Named Executive Officers as of December 31, 2016
under the TEP LTIP.
Equity Participation Unit Awards (1)
Number of EPU
Awards That Have
Not Vested
Market Value of EPU
Awards That Have
Not Vested (2)
Number of Unearned
EPUs That Have Not
Vested
Market or Payout
Value of Unearned
EPUs That Have Not
Vested
David G. Dehaemers, Jr. .................
William R. Moler ............................
Gary J. Brauchle..............................
Christopher R. Jones .......................
Gary D. Watkins..............................
—
$
33,333 (3) $
33,333 (3) $
23,800 (4) $
25,066 (5) $
—
1,581,651
1,581,651
1,129,310
1,189,382
— $
— $
— $
— $
— $
—
—
—
—
—
(1) The award agreements pursuant to which the EPUs set forth above were granted provide for the settlement of the
EPUs in common units.
(2) Reflects the closing price of $47.45 per TEP common unit at December 30, 2016.
(3) Mr. Moler and Mr. Brauchle each hold 33,333 EPUs that will vest on May 13, 2017.
(4) Mr. Jones holds 16,000 EPUs that will vest on May 13, 2017, 2,900 EPUs that will vest on May 13, 2018, 2,900 EPUs
that will vest on May 13, 2019, and 2,000 EPUs that will vest on November 1, 2019.
(5) Mr. Watkins holds 16,666 EPUs that will vest on May 13, 2017, 3,200 EPUs that will vest on May 13, 2018, 3,200
EPUs that will vest on May 13, 2019, and 2,000 EPUs that will vest on November 1, 2019.
The following table reflects all outstanding equity awards of our named executive officers as of December 31, 2016 under
the TEGP LTIP.
Equity Participation Share Awards (1)
Number of Equity
Participation Share
Awards That Have
Not Vested
Market Value of
Equity Participation
Share Awards That
Have Not Vested
Number of Unearned
Equity Participation
Shares That Have
Not Vested
Market or Payout
Value of Unearned
Equity Participation
Shares That Have
Not Vested (2)
David G. Dehaemers, Jr. .................
William R. Moler ............................
Gary J. Brauchle..............................
Christopher R. Jones .......................
Gary D. Watkins..............................
— $
— $
— $
— $
— $
—
—
—
—
—
—
—
$
$
$
—
35,000 (3) $
35,000 (3) $
—
—
—
938,000
938,000
(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 TEGP Class A Shares.
(2) Reflects the closing price of $26.80 per TEGP Class A share at December 30, 2016.
(3) Mr. Jones and Mr. Watkins each hold 35,000 equity participation shares that will vest upon the later to occur of the
TEGP Distribution Achievement Date or May 12, 2019. If TEGP has not distributed at least $0.35 on each outstanding
Class A Share for any full quarter ending on or before May 12, 2020, the unvested equity participation shares will
expire and no vesting will occur.
Units Vested
No TEP LTIP Awards or TEGP Equity Participation Share Awards vested during 2016.
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.
146
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 TEGP Management, 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 TEP 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:
•
•
"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 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 the entity with ultimate control over our general partner; (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 operating agreements of our general
partner or certain affiliates of Tallgrass Management, in his capacity as an officer of such entities.
"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, 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 TEP LTIP Awards and TEGP LTIP Awards held by our Named Executive Officers typically provide for acceleration of
vesting in connection with a change in control. The TEP LTIP Awards held by our Named Executive Officers vest and/or
become exercisable in full upon a "change in control" of us or our general partner and the TEGP LTIP Awards held by our
Named Executive Officers vest and/or become exercisable in full upon a "change in control" of TEGP or TEGP's general
partner.
147
Under the TEP LTIP, "change of control" means the occurrence of one or more of the following events:
•
•
•
any Person or group, other than Tallgrass Equity 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 TEP (excluding incentive distribution rights);
the limited partners of TEP 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 our general partner or its affiliates.
Under the TEGP LTIP, "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 TEGP Management or (B) the general partner interests in TEGP;
the limited partners of TEGP approve, in one or a series of transactions, a plan of complete liquidation of TEGP; or
the sale or other disposition by TEGP of all or substantially all of its assets in one or more transactions to any person
other than TEGP Management or an affiliate of the TEGP Management.
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 TEP LTIP and TEGP LTIP if a change in control occurred on December 31,
2016.
Upon a Change in
Control (1)
David G. Dehaemers, Jr.
TEP LTIP........................................................................................ $
TEGP LTIP..................................................................................... $
—
—
William R. Moler
TEP LTIP........................................................................................ $
TEGP LTIP..................................................................................... $
1,581,651
—
Gary J. Brauchle
TEP LTIP........................................................................................ $
TEGP LTIP..................................................................................... $
1,581,651
—
Christopher R. Jones
TEP LTIP........................................................................................ $
TEGP LTIP..................................................................................... $
1,129,310
938,000
Gary D. Watkins
TEP LTIP........................................................................................ $
TEGP LTIP..................................................................................... $
1,189,382
938,000
(1) The stated value upon a change in control is computed by assuming that a triggering change of control occurred on
December 30, 2016 and multiplying the closing market price (TEP: $47.45 and TEGP: $26.80) of the relevant units
and shares on such date by the number of units and shares that would have vested.
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. Each of the Named Executive Officers
has signed a confidentiality agreement in connection with their employment by Tallgrass Management.
148
Compensation of Directors
Officers or employees of Tallgrass Development or its affiliates, including directors affiliated with EMG or Kelso, who
also serve as directors of our general partner do not receive additional compensation for such service. In 2016, directors of our
general partner who are not also officers or employees of Tallgrass Development or its affiliates or affiliated with EMG or
Kelso received 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, an annual committee chair cash payment of $5,000.
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 TEP LTIP.
The following table sets forth certain information with respect to our non-employee director compensation during the year
ended December 31, 2016.
Name and Principal Position
Terrance D. Towner........................... $
Roy N. Cook ..................................... $
Jeffrey R. Armstrong......................... $
Fees Earned
EPU Awards
Non-Equity
Incentive Plan
Compensation
40,000
45,000
40,000
$
$
$
— $
— $
— $
— $
— $
— $
Total
40,000
45,000
40,000
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.
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, 2016 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
Terrance D. Towner
Roy N. Cook
Jeffrey R. Armstrong
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth the beneficial ownership of our units as of February 8, 2017 owned by:
•
•
•
•
each person known by us to be a beneficial owner of more than 5% of the units;
each of the directors of our general partner;
each of the named executive officers of our general partner; and
all directors and executive officers of our general partner as a group.
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC 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
149
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 units
shown as beneficially owned by them, subject to community property laws where applicable.
Percentage of total units to be beneficially owned is based on 72,139,038 common units outstanding as of February 8,
2017.
Name of Beneficial Owner (1)
Tallgrass Energy Holdings (3) ..........................................................................
OppenheimerFunds, Inc.(4)..............................................................................
David G. Dehaemers, Jr. (5) .............................................................................
William R. Moler (6)........................................................................................
Gary J. Brauchle (7) .........................................................................................
Christopher R. Jones.......................................................................................
Gary D. Watkins .............................................................................................
Frank J. Loverro..............................................................................................
Stanley de J. Osborne .....................................................................................
Jeffrey A. Ball.................................................................................................
John T. Raymond............................................................................................
Roy N. Cook ...................................................................................................
Terrance D. Towner........................................................................................
Jeffrey R. Armstrong ......................................................................................
All directors and executive officers as a group (13 persons)..........................
*
Less than 1%.
Common Units
Beneficially Owned (2)
25,619,218
3,827,358
Percentage of
Common Units
Beneficially Owned
35.51%
5.31%
312,847
14,428
25,780
10,378
6,668
—
—
20,000
100,000
51,000
24,000
2,000
578,161
—
—
*
*
*
*
*
*
*
*
*
*
*
(1) Unless otherwise indicated, the address for all beneficial owners in this table is c/o Tallgrass Energy Partners, LP, 4200 W.
115th Street, Suite 350, Leawood, Kansas 66211, Attn: General Counsel.
(2) This column reflects the number of TEP common units held of record or owned through a bank, broker or other nominee.
The common units of TEP presented as being beneficially owned by our general partner's directors and executive officers
do not include the TEP common units held by Tallgrass Equity and Tallgrass Operations that may be attributable to such
directors and officers based on their indirect ownership of Tallgrass Equity and Tallgrass Operations.
(3) Consists of common units held of record by (i) Tallgrass Equity and (ii) Tallgrass Operations. Tallgrass Energy Holdings is
the sole member of TEGP Management, LLC, TEGP's general partner. TEGP is the managing member of Tallgrass Equity.
As such, Tallgrass Energy Holdings has the sole voting and dispositive power with respect to the common units owned by
Tallgrass Equity. Tallgrass Energy Holdings, as the general partner of Tallgrass Development, which is the sole owner of
Tallgrass Operations, also has the sole voting and dispositive power with respect to the common units owned by Tallgrass
Operations. Tallgrass Energy Holdings is controlled by its board of directors, which currently consists of the following:
David G. Dehaemers, Jr., William R. Moler, Frank J. Loverro, Stanley de J. Osborne, Jeffrey A. Ball and John T. Raymond.
Each of the members of the board of directors of Tallgrass Energy Holdings may be deemed to beneficially own the
common units owned by Tallgrass Equity and Tallgrass Operations; however, each disclaims beneficial ownership.
(4) As reported on Schedule 13G filed with the SEC on February 6, 2017. Consists of common units of record by
OppenheimerFunds, Inc. OppenheimerFunds, Inc. disclaims beneficial ownership pursuant to Rule 13d-4 of the Exchange
Act of 1934. The business address for this person is Two World Financial Center, 225 Liberty Street, New York, New York
10281.
(5) David G. Dehaemers, Jr. indirectly owns the common units through the David G. Dehaemers, Jr. Revocable Trust, dated
April 26, 2006, for which Mr. Dehaemers serves as Trustee.
(6) William R. Moler indirectly owns the common units through the William R. Moler Revocable Trust, under a trust
agreement dated August 29, 2013, for which Mr. Moler serves as Trustee.
(7) Gary J. Brauchle indirectly owns the common units through the Brauchle Revocable Trust, under trust agreement dated
April 10, 2014, for which Mr. Brauchle serves as a Trustee.
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Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information about TEP's common units that may be issued under equity compensation plans
as of December 31, 2016:
Plan Category
Equity compensation plans approved by
security holders (1)
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))
1,339,884
$
— $
1,339,884
$
24.92
—
24.92
8,290,800
—
8,290,800
(1) Amounts shown represent equity participation unit awards outstanding under the TEP LTIP as of December 31, 2016.
The outstanding awards will be settled in common units 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 TEP common units may be issued except for the
TEP LTIP.
For additional information regarding the TEP LTIP, see Note 16 – Equity-Based Compensation to our Consolidated
Financial Statements in Item 8.—Financial Statements and Supplementary Data of this Annual Report.
Item 13. Certain Relationships and Related Transactions, and Director Independence
As of February 15, 2017, Tallgrass Development owned 5,619,218 common units representing approximately 7.79% of our
outstanding limited partner common units and Tallgrass Equity owned 20,000,000 common units representing approximately
27.72% of our outstanding limited partner common units. In addition, our general partner owns 834,391 general partner units
representing an approximate 1.14% general partner interest in us and all of the incentive distribution rights.
Distributions and Payments to Our General Partner and Its Affiliates
The following information summarizes the distributions and payments made or to be made by us to our general partner and
its affiliates in connection with our formation, ongoing operation and any liquidation of us. These distributions and payments
were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.
Distributions of available cash to our general partner and its affiliates. We will generally make distributions of available
cash to common unitholders pro rata (including Tallgrass Development as the holder of an aggregate of 5,619,218 common
units) and to our general partner as follows: (1) an approximate 1.14% general partner interest with respect to TEP GP's general
partner units and (2) as distributions of available cash exceed the MQD and other higher target levels specified in our
partnership agreement, increasing percentages of distributions with respect to its IDRs, up to 48% of the distributions above the
highest target level. Assuming we have sufficient available cash to pay the full MQD on all of our outstanding units for four
quarters, our general partner and its affiliates would receive an annual distribution of approximately $1.0 million on their
general partner units and approximately $30.0 million on their common units based on their ownership as of February 15, 2017.
We have distributed available cash in excess of the MQD since the quarterly period ending September 30, 2013.
Payments to our general partner and its affiliates. Neither our general partner nor Tallgrass Energy Holdings and its
affiliates receive a management fee or other compensation for managing us. Our general partner and Tallgrass Energy Holdings
and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf pursuant to our partnership
agreement and the TEP Omnibus Agreement. Neither our partnership agreement nor the TEP Omnibus Agreement limit the
amount of expenses for which our general partner or Tallgrass Energy Holdings and its affiliates may be reimbursed. Our
partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
Withdrawal or removal of our general partner. If our general partner withdraws or is removed, its general partner interest
and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount
equal to the fair market value of those interests.
Liquidation Stage. Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating
distributions according to their particular capital account balances, as further detailed in our limited partnership agreement.
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TEP Omnibus Agreement
Upon the closing of the IPO, we entered into the TEP Omnibus Agreement with Tallgrass Development, its general partner,
Tallgrass Energy Holdings, and our general partner that governs our relationship with them regarding the following matters:
•
•
•
•
•
the provision by Tallgrass Energy Holdings to us of certain administrative services and our agreement to reimburse it
for such services;
the provision by Tallgrass Energy Holdings of such employees as may be necessary to operate and manage our
business, and our agreement to reimburse it for the expenses associated with such employees;
certain indemnification obligations;
our use of the name "Tallgrass" and related marks; and
our right of first offer to acquire certain assets, including each of the Retained Assets from Tallgrass Development, if
Tallgrass Development decides to sell such assets.
Reimbursement of General and Administrative Expenses
Pursuant to the TEP Omnibus Agreement, Tallgrass Energy Holdings performs, or causes its affiliates to perform,
centralized corporate, general and administrative services for us, 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, we reimburse it for expenses incurred in providing
these services. The reimbursements to our general partner and Tallgrass Energy Holdings and its affiliates are made prior to
cash distributions to our common unitholders. The TEP Omnibus Agreement further provides that we will reimburse Tallgrass
Energy Holdings and its affiliates for our allocable portion of the premiums on any insurance policies covering our assets. We
anticipate reimbursement to Tallgrass Energy Holdings and its affiliates will vary with the size and scale of our operations,
among other factors.
For the years ended December 31, 2016, 2015 and 2014, we reimbursed Tallgrass Energy Holdings $39.9 million, $37.5
million and $23.5 million, respectively, pursuant to the TEP Omnibus Agreement.
Indemnification
Under the terms of the TEP Omnibus Agreement, Tallgrass Development is required to indemnify us from liabilities
arising out of any federal, state and local income tax liabilities attributable to the ownership and operation of the assets
contributed to us in connection with the IPO until 60 days after the applicable statute of limitations. Tallgrass Development also
agreed to use commercially reasonable efforts to obtain indemnification from Kinder Morgan for losses suffered or incurred by
us with respect to the assets contributed to us as part of the IPO, to the extent that Kinder Morgan is obligated to indemnify
Tallgrass Development under the purchase and sale agreement pursuant to which Tallgrass Development acquired the
contributed assets and remit any proceeds received from Kinder Morgan pursuant to such indemnification obligations to us.
Kinder Morgan's indemnity obligations under the Kinder Morgan purchase agreement generally survived through
February 13, 2014, although certain specified indemnities last for longer periods of time. Under the TEP Omnibus Agreement,
we have agreed to indemnify Tallgrass Development for events and conditions associated with the operation of the contributed
assets that occur on or after the closing of the IPO.
Right of First Offer
Under the terms of the TEP Omnibus Agreement, Tallgrass Development has granted us a right of first offer, for so long as
Tallgrass Development or its affiliates, individually or as part of a group, control our general partner, on (i) the Retained Assets
and (ii) any assets that are hereafter developed, constructed or acquired by Tallgrass Development or its subsidiaries (excluding
the Partnership and its subsidiaries) for the purpose of processing natural gas in Natrona, Converse or Campbell counties in
Wyoming, which we refer to collectively as the ROFO Assets. If Tallgrass Development or any of its affiliates decide to
attempt to sell (other than to an affiliate of Tallgrass Development, excluding TEP and its subsidiaries) a ROFO Asset, Tallgrass
Development or its affiliate will notify us in advance and, prior to selling such ROFO Asset to a third party, will negotiate with
us exclusively and in good faith for a period of 45 days in order to give us an opportunity to enter into definitive documentation
for the purchase and sale of such ROFO Asset on terms that are mutually acceptable to Tallgrass Development or its affiliate
and us. If we and Tallgrass Development or its affiliate have not entered into a letter of intent or a definitive purchase and sale
agreement with respect to such ROFO Asset within such 45-day period, Tallgrass Development or its affiliate will have the
right to sell such ROFO Asset to a third party following the expiration of such 45-day period on any terms that are acceptable to
Tallgrass Development or its affiliate and such third party. Our decision to acquire or not to acquire a ROFO Asset pursuant to
this right will require the approval of the conflicts committee of the board of directors of our general partner.
152
Amendment and Termination
The TEP Omnibus Agreement can be amended by written agreement of all parties to the agreement. However, we may not
agree to any amendment or modification that would, in the determination of our general partner, be adverse in any material
respect to the holders of our common units without the prior approval of the conflicts committee. In the event of (i) a "change
in control" (as defined in the TEP Omnibus Agreement) of the partnership or (ii) the removal of Tallgrass MLP GP, LLC as our
general partner in circumstances where "cause" (as defined in our partnership agreement) does not exist and the common units
held by our general partner and its affiliates were not voted in favor of such removal, the TEP Omnibus Agreement (other than
the indemnification and reimbursement provisions therein) will be terminable by Tallgrass Development, and we will have a
90-day transition period to cease our use of the name "Tallgrass" and related marks.
Acquisitions from Tallgrass Development
On April 1, 2014, Tallgrass MLP Operations, LLC, a Delaware limited liability company and our wholly-owned subsidiary
acquired 100% of the issued and outstanding membership interests in Trailblazer from Tallgrass Operations, LLC, a Delaware
limited liability company and wholly-owned direct subsidiary of Tallgrass Development ("Tallgrass Operations"), for total
consideration valued at approximately $164 million, pursuant to that certain Contribution and Sale Agreement by and between
Tallgrass Development, Tallgrass Operations, and us.
Effective September 1, 2014, we acquired a 33.3% membership interest in Pony Express, from Tallgrass Development for
total consideration of approximately $600 million pursuant to that certain Contribution and Transfer Agreement by and between
Tallgrass Development, Pony Express, Tallgrass Operations, and us. At closing, we entered into a Second Amended and
Restated Limited Liability Company Agreement of Pony Express effective September 1, 2014 with Tallgrass Development and
Pony Express, which provided us a minimum quarterly preference payment of $16.65 million through the quarter ending
September 30, 2015 with distributions thereafter shared in accordance with the terms of the Second Amended and Restated
Limited Liability Company Agreement. In connection with the transaction, Pony Express entered into a Cash Management
Agreement effective August 27, 2014, under which cash balances were swept daily and recorded as loans from Pony Express to
Tallgrass Development. $270 million of the total consideration was subsequently swept to Tallgrass Development and was
recorded as a related party loan which accrued interest at Tallgrass Development's incremental borrowing rate. As of September
1, 2014, balances lent to Tallgrass Development under the cash management agreement were classified as related party
receivables on our consolidated balance sheet and were cash settled.
Effective March 1, 2015, we acquired an additional 33.3% membership interest in Pony Express from Tallgrass
Development for total consideration of approximately $700 million pursuant to that certain Purchase and Sale Agreement by
and between Tallgrass Development, Tallgrass Operations and us. At closing, TEP, Tallgrass Development and Pony Express
entered into a Third Amended and Restated Limited Liability Company Agreement of Pony Express effective March 1, 2015,
which provided us a minimum quarterly preference payment of $36.65 million through the quarter ending December 31, 2015
with distributions thereafter shared in accordance with the terms of the Third Amended and Restated Limited Liability
Company Agreement.
Effective January 1, 2016, we acquired an additional 31.3% membership interest in Pony Express from Tallgrass
Development for total cash consideration of approximately $475 million and the issuance of 6,518,000 TEP common units,
which TEP common units are subject to a call option granted by Tallgrass Operations in favor of us, pursuant to that certain
Contribution and Transfer Agreement by and between Tallgrass Development, Tallgrass Operations and us. In July 2016,
October 2016 and on February 1, 2017, we exercised the call option granted by Tallgrass Development covering 3,563,146,
1,251,760 and 1,703,094 common units, respectively. These common units were deemed canceled upon the exercise of the call
option and as of such exercise date were no longer issued and outstanding. As of February 15, 2017, no common units
remained subject to the call option.
On May 6, 2016, Tallgrass Development 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
Tallgrass Development'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.
Effective January 1, 2017, we acquired 100% of the issued and outstanding membership interests in Terminals and 100%
of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $140 million, pursuant to
that certain Purchase and Sale Agreement by and between Tallgrass Development, Tallgrass Operations and us.
153
Following an offer received from Tallgrass Development with respect to common units owned by Tallgrass Development
not subject to the call option, we repurchased 736,262 common units from Tallgrass Development at an aggregate price of
approximately $35.3 million, or $47.99 per common unit, on February 1, 2017, which was approved by the conflicts committee
of the board of directors of our general partner.
Competition
Under our partnership agreement, Tallgrass Development and its affiliates are expressly permitted to compete with us.
Tallgrass Development and any of its affiliates, including EMG and Kelso may acquire, construct or dispose of additional
transportation, storage, terminalling and processing or other assets in the future without any obligation to offer us the
opportunity to purchase or construct those assets.
Contracts with Affiliates
Pony Express is party to a terminal lease and operating agreement with Tallgrass Sterling Terminal, LLC ("Sterling
Terminal"), which was an indirect wholly-owned subsidiary of Tallgrass Development prior to our acquisition in January 2017.
Pursuant to such agreement, Pony Express leases approximately 1.3 million barrels of crude oil storage and Sterling Terminal
provides associated crude oil terminalling services. Pony Express pays Sterling Terminal a fixed monthly charge of $942,000
per month, plus a volumetric charge of $0.07 per barrel for each barrel delivered to the terminal in excess of 9,424,000 per
month, subject in both cases to an annual 2% escalator. The initial five-year term of the agreement expires in May 2020. Pony
Express made lease payments to Sterling Terminal of $11.5 million and $7.6 million during the years ended December 31, 2016
and 2015, respectively, pursuant to the agreement.
In May 2016, Pony Express entered into an electric service master meter agreement with Terminals, which was an indirect
wholly-owned subsidiary of Tallgrass Development prior to our acquisition in January 2017. Pursuant to such agreement,
Terminals receives electric power from Pony Express at the Sterling Terminal. Terminals pays Pony Express for its usage based
on the charges incurred by Pony Express from its third-party electric service provider. Terminals made payments to Pony
Express under the agreement of $0.4 million during the year ended December 31, 2016.
Other Transactions
Tallgrass Management, LLC, an affiliate of our general partner, has one employee who is an immediate family member of
a former executive officer of our general partner. Zach Rider, a manager of corporate development, is the son of George Rider,
the former Executive Vice President, General Counsel and Secretary of TEP GP. For the years ended December 31, 2016, 2015
and 2014, he received cash compensation of $186,246, $179,357 and $159,846, respectively, and standard employee benefits of
approximately $11,725, $9,977 and $13,747, respectively. For the year ended December 31, 2015, he was awarded 3,800
unvested EPUs with a grant date value of $38.62 per EPU on terms consistent with all eligible employees. As of July 1, 2016,
George Rider has retired and is no longer employed by Tallgrass Management, LLC.
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 any of the Partnership's subsidiaries
(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
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.
154
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) or 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,
2016
2015
(in thousands)
1,634
$
—
445
2,079
$
1,400
—
495
1,895
(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, 2016.
155
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
156
FINANCIAL STATEMENTS
ROCKIES EXPRESS
PIPELINE LLC
For the years ended December 31, 2016, 2015 and 2014
157
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, 2016 and 2015, and the related statements of income, members’ equity, and cash flows for each of the three
years in the period ended December 31, 2016.
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, 2016 and 2015, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 2016, in accordance with accounting principles generally accepted in the
United States of America.
Emphasis of Matter
As described in Note 6 to the financial statements, the Company has significant transactions with related parties. Our opinion
is not modified with respect to this matter.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 15, 2017
158
ROCKIES EXPRESS PIPELINE LLC
BALANCE SHEETS
December 31,
2016
2015
(in millions)
Current Assets:
ASSETS
Cash and cash equivalents ..................................................................................... $
Accounts receivable, net........................................................................................
Regulatory assets ...................................................................................................
Other current assets ...............................................................................................
Total Current Assets..........................................................................................
Property, plant and equipment, net.............................................................................
Deferred charges and other assets ..............................................................................
Total Noncurrent Assets....................................................................................
118.4
$
59.4
12.3
5.6
195.7
6,063.7
15.6
6,079.3
Total Assets................................................................................................................. $
6,275.0
$
Current Liabilities:
LIABILITIES AND EQUITY
Accounts payable................................................................................................... $
Accrued interest.....................................................................................................
Accrued taxes ........................................................................................................
MFN revenue sharing liability...............................................................................
Construction advances...........................................................................................
Accrued other current liabilities ............................................................................
Total Current Liabilities....................................................................................
Long-term Liabilities and Deferred Credits:
Long-term debt ......................................................................................................
Other long-term liabilities and deferred credits.....................................................
Total Long-term Liabilities and Deferred Credits ............................................
$
38.1
56.3
67.7
9.4
11.7
4.9
188.1
2,561.7
95.2
2,656.9
48.0
87.6
0.3
4.0
139.9
5,941.0
19.0
5,960.0
6,099.9
29.0
56.3
68.2
9.5
12.3
4.5
179.8
2,557.9
44.0
2,601.9
Commitments and Contingencies
Members' Equity:
Members' equity ....................................................................................................
Total Liabilities and Members' Equity ....................................................................... $
3,430.0
6,275.0
$
3,318.2
6,099.9
The accompanying notes are an integral part of these financial statements.
159
ROCKIES EXPRESS PIPELINE LLC
STATEMENTS OF INCOME
Revenues:
Transportation services........................................................................ $
Natural gas sales ..................................................................................
Total Revenues................................................................................
Operating Costs and Expenses:
Cost of natural gas sales (exclusive of depreciation and amortization
shown below).......................................................................................
Cost of transportation services (exclusive of depreciation and
amortization shown below) .................................................................
Operations and maintenance................................................................
Depreciation and amortization ............................................................
General and administrative..................................................................
Taxes, other than income taxes............................................................
Total Operating Costs and Expenses ..............................................
Operating Income .....................................................................................
Years Ended December 31,
2016
2015
(in millions)
2014
715.1
$
779.0
$
—
715.1
—
26.5
24.8
204.3
39.9
71.9
367.4
347.7
2.1
781.1
2.3
30.2
21.2
199.4
26.7
73.9
353.7
427.4
703.6
36.7
740.3
32.3
29.8
19.4
195.1
21.5
70.8
368.9
371.4
Other (Expense) Income:
Interest expense, net ............................................................................
Gain on litigation settlement ...............................................................
Other income, net ................................................................................
Total Other Expense, net.................................................................
Net Income to Members ........................................................................... $
(158.6)
61.7
27.7
(69.2)
278.5
$
(170.1)
—
6.6
(163.5)
263.9
$
(185.3)
—
3.3
(182.0)
189.4
The accompanying notes are an integral part of these financial statements.
160
ROCKIES EXPRESS PIPELINE LLC
STATEMENTS OF MEMBERS' EQUITY
Members' Equity:
Balance at December 31, 2013 .................. $
Net Income to Members ..........................
Contributions from Members ..................
Distributions to Members ........................
Balance at December 31, 2014 .................. $
Net Income to Members ..........................
Contributions from Members ..................
Distributions to Members ........................
Balance at December 31, 2015 .................. $
Net Income to Members........................
Contributions from Members................
Distributions to Members......................
Transfer of equity interest (see Note 1).
Balance at December 31, 2016 .................. $
Rockies
Express
Holdings,
LLC
Total
TEP REX
Holdings,
LLC
(in millions)
Sempra REX
Holdings,
LLC
P66 REX
LLC
2,826.8
$
1,413.2
$
— $
706.8
$
189.4
165.7
(361.7)
2,820.2
$
263.9
733.1
(499.0)
3,318.2
$
278.5
304.9
(471.6)
—
$
$
94.6
83.1
(180.9)
1,410.0
131.9
366.5
(249.4)
1,659.0
139.3
152.5
(235.8)
—
—
—
—
— $
—
—
—
— $
42.6
50.0
(75.9)
840.8
$
$
47.4
41.3
(90.4)
705.1
66.0
183.3
(124.8)
829.6
27.0
26.2
(42.0)
(840.8)
3,430.0
$
1,715.0
$
857.5
$
— $
706.8
47.4
41.3
(90.4)
705.1
66.0
183.3
(124.8)
829.6
69.6
76.2
(117.9)
—
857.5
The accompanying notes are an integral part of these financial statements.
161
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 from
operating activities:
Years Ended December 31,
2016
2015
(in millions)
2014
278.5
$
263.9
$
189.4
Depreciation and amortization........................................................
209.6
204.8
201.1
Changes in components of working capital:
Accounts receivable........................................................................
Current regulatory assets and liabilities, net...................................
Other current assets and liabilities..................................................
Accounts payable............................................................................
Accrued taxes..................................................................................
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:
Distributions to Members ....................................................................
Contributions from Members ..............................................................
Repayment of debt...............................................................................
Payments for deferred financing costs ................................................
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 Disclosure of Cash Flow Information:
28.2
(12.5)
(0.7)
12.2
(0.6)
52.9
(22.5)
545.1
(305.7)
(2.3)
(308.0)
(471.6)
304.9
—
—
(166.7)
70.4
48.0
118.4
Cash paid during the period for interest (net of capitalized interest) .. $
155.6
Schedule of Noncash Investing and Financing Activities:
$
$
(23.8)
(10.2)
(0.9)
3.7
3.7
32.2
(3.0)
470.4
(281.9)
(1.9)
(283.8)
(499.0)
733.1
(450.0)
(0.7)
(216.6)
(30.0)
78.0
48.0
170.7
Increase in accrual for payment of property, plant and equipment ..... $
— $
8.4
$
$
$
6.3
(15.2)
0.6
0.8
(3.1)
—
(6.9)
373.0
(158.6)
(2.0)
(160.6)
(361.7)
165.7
—
—
(196.0)
16.4
61.6
78.0
181.3
—
The accompanying notes are an integral part of these financial statements.
162
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, 2016 are as follows:
•
•
•
50% - Rockies Express Holdings, LLC ("REX Holdings"), an indirect wholly owned subsidiary of Tallgrass
Development, LP ("TD");
25% - TEP REX Holdings, LLC ("TEP REX"), an indirect wholly owned subsidiary of Tallgrass Energy Partners, LP
("TEP"); and
25% - P66REX LLC, formerly known as COPREX LLC, a wholly owned subsidiary of Phillips 66.
On March 29, 2016, REX Holdings signed a Purchase Agreement with Sempra REX Holdings, LLC ("Sempra") to acquire
Sempra's 25% membership interest in Rockies Express for cash consideration of $440 million, subject to adjustment under the
Purchase Agreement. A subsidiary of Phillips 66, which owns a 25% membership interest in Rockies Express, waived its right
to purchase its proportionate share of Sempra's 25% membership interest. In exchange, TD and Sempra agreed to amend the
Rockies Express limited liability company agreement to (i) increase the percentage with respect to matters that require
approval, consent, or presence of the members of Rockies Express from 75% to 80%, and (ii) with respect to certain
fundamental decisions, increase the required vote from 85% to 90% of the membership interests (the "REX Amendment").
On May 6, 2016, TEP REX and REX Holdings entered into an Assignment and Assumption Agreement pursuant to which
REX Holdings assigned to TEP REX all of its rights under the Purchase Agreement and, in exchange, TEP REX assumed all of
the rights and obligations of REX Holdings under the Purchase Agreement. Subsequently on May 6, 2016, TEP REX 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. The REX Amendment became effective immediately prior to closing of the sale of the 25% membership interest.
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.
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.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are carried at their estimated collectible amounts. Rockies Express makes periodic reviews and
evaluations of 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 $2.0 million and $1.0 million at December 31, 2016 and 2015, respectively.
163
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 $12.3 million and $0.3 million at December 31, 2016 and 2015, respectively, and regulatory liabilities of
approximately $10,000 and $0.5 million at December 31, 2016 and 2015, respectively. Regulatory assets and liabilities at
December 31, 2016 and 2015 were primarily attributable to the fuel tracker discussed in "Fuel Recovery Mechanism" above.
For additional details see Note 9 – 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. We also capitalize 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;
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;
164
•
•
•
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
Depreciation is computed based on the straight-line method over the estimated useful lives of property, plant and
equipment. The annual composite rate of depreciation for the years ended December 31, 2016, 2015, and 2014 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, 2016, 2015, and 2014,
Rockies Express recognized AFUDC associated with the estimated cost of capital from equity funds of approximately $24.8
million, $6.5 million, and $3.3 million, respectively, recorded as "Other income, net" on the accompanying statements of
income.
Revenue Recognition
Rockies Express provides various types of natural gas transportation services to its customers in which the natural gas
remains the property of these customers at all times. In many cases (generally described as "firm service"), the customer pays a
two-part rate that includes (i) a fixed-fee reserving the right to transport natural gas in Rockies Express' facilities and (ii) a per-
unit rate for volumes actually transported. The fixed-fee component of the overall rate is recognized as revenue in the period
the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers' agreed
upon delivery point. In other cases (generally described as "interruptible service"), there is no fixed-fee associated with the
services because the customer accepts the possibility that service may be interrupted at the discretion of Rockies Express in
order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the
same manner utilized for the per-unit rate for volumes transported under firm service agreements.
In addition to its "firm" and "interruptible" transportation services, Rockies Express also provides a natural gas park and
loan service to assist customers in managing a short-term gas surplus or deficit and a pooling and wheeling service to assist
customers in the aggregation of gas supply from physical point(s) within a specified hub to a central pooling point and the re-
delivery of gas supply to physical points within the same hub. Revenues are recognized as services are provided, in accordance
with the terms negotiated under these contracts.
Rockies Express recognizes revenue from natural gas sales when the natural gas is sold at a fixed or determinable price,
delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.
Debt Issuance Costs
Debt issuance costs are amortized to interest expense over the life of the debt using the straight-line-method, which
approximates the effective interest rate method. Debt issuance costs associated with long-term debt are classified with the
corresponding debt on the accompanying balance sheets. Debt issuance costs associated with revolving credit facilities or lines
of credit are classified as deferred charges and other assets on the accompanying balance sheets.
Deferred Charges and Deferred Credits
Rockies Express has $4.5 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, 2016, 2015, and 2014 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.
165
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, 2016 and 2015.
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.
New Accounting Pronouncements
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.
Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in
Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,
ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting
Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance
Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope
Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606,
Revenue from Contracts with Customers.
The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 are effective for public
entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period.
Early application is permitted for annual reporting periods beginning after December 15, 2016.
Rockies Express is currently evaluating the impact of our pending adoption of the revised guidance. The status of its
implementation is as follows:
•
•
Rockies Express management has formed an implementation team that meets to discuss implementation challenges,
technical interpretations, industry-specific treatment of certain revenue contract types, and project status.
Rockies Express management is currently reviewing contracts for each revenue stream identified. Through this
process, management is determining and documenting expected changes in revenue recognition upon adoption of the
revised guidance.
166
•
•
Rockies Express management plans to evaluate the potential information technology and internal control changes that
will be required for adoption based on the findings from its contract review process.
Rockies Express management plans to provide internal training and awareness related to the revised guidance to the
key stakeholders throughout its organization.
Rockies Express will continue to conduct its contract review process throughout 2017 and, as a result, areas of impact may
be identified. Rockies Express is in the process of quantifying the impact of adoption but cannot reasonably estimate such
amount at this time. Rockies Express expects to adopt the new standard on January 1, 2018 using the modified retrospective
approach. 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. Consolidated revenues presented
in the comparative financial statements for periods prior to January 1, 2018 would not be revised.
ASU No. 2016-02, "Leases (Topic 842)"
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update
to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by
recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.
The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes
primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.
The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December
15, 2018, and for interim periods within that reporting period. Early application is permitted. Rockies Express is currently
evaluating the impact of ASU 2016-02.
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,
2016
2015
(in millions)
7,085.8
$
9.9
503.2
(1,535.2)
6,063.7
$
7,062.6
9.2
202.0
(1,332.8)
5,941.0
Depreciation expense was approximately $204.3 million, $199.4 million and $195.1 million for the years ended
December 31, 2016, 2015 and 2014, respectively. Capitalized interest was $9.3 million, $2.8 million, and $1.0 million for the
years ended December 31, 2016, 2015 and 2014, respectively.
4. Financing
Debt
Total outstanding debt as of December 31, 2016 and 2015 consisted of the following:
6.85% senior notes due July 15, 2018..................................................... $
6.00% senior notes due January 15, 2019 ...............................................
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 debt issuance costs .................
Total long-term debt................................................................................ $
167
December 31,
2016
2015
(in millions)
550.0
525.0
750.0
250.0
500.0
(13.3)
2,561.7
$
$
550.0
525.0
750.0
250.0
500.0
(17.1)
2,557.9
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.
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, 2016, we were 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, 2016 are summarized as
follows (in millions):
Year
2017 .................................................................................................................................................
2018 .................................................................................................................................................
2019 .................................................................................................................................................
2020 .................................................................................................................................................
2021 .................................................................................................................................................
Thereafter ........................................................................................................................................
Total scheduled maturities...............................................................................................................
Unamortized debt discount and debt issuance costs........................................................................
Total debt.........................................................................................................................................
Rockies Express Revolving Credit Facility
Scheduled Maturities
$
$
—
550.0
525.0
750.0
—
750.0
2,575.0
(13.3)
2,561.7
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, 2016, 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 is initially 1.00%, and for loans bearing interest based on the
reserve adjusted Eurodollar rate, the applicable margin is initially 2.00%. After the first full fiscal quarter, the applicable margin
will range 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 should
Rockies Express receive an investment grade credit rating from one or more of the ratings agencies in the future. 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.
The revolving credit facility generally requires Rockies Express to comply with various affirmative and negative
covenants, including a limit on the leverage ratio (as defined in the credit agreement) of Rockies Express and restrictions on:
•
•
•
incurring secured indebtedness;
entering into mergers, consolidations and sales of assets;
granting liens;
168
•
entering into transactions with affiliates; and
• making restricted payments.
As of December 31, 2016, we were in compliance with the covenants required under the revolving credit facility.
Repayment of 3.90% Senior Notes
The board of directors of Rockies Express approved repayment of the $450 million 3.90% senior notes due April 15, 2015
("2015 Notes") which was financed through capital contributions by the Members of Rockies Express in proportion to their
respective ownership interests. The capital contribution was made by each Member of Rockies Express in accordance with
Section 4.3.1 of Rockies Express' Second Amended and Restated Limited Liability Company Agreement, as amended, and was
used to repay the 2015 Notes on April 15, 2015.
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 accompanying balance sheets as of December 31, 2016 and 2015, 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, 2016 ................. $
December 31, 2015 ................. $
— $
— $
(in millions)
2,684.9
2,412.6
$
$
— $
— $
2,684.9
2,412.6
$
$
2,561.7
2,557.9
The long-term debt is carried at amortized cost, net of debt issuance costs. The estimated fair value of Rockies Express'
outstanding private placement debt 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, 2016.
5. Members' Equity
During the years ended December 31, 2016, 2015, and 2014, Rockies Express made distributions to Members of $471.6
million, $499.0 million, and $361.7 million, respectively.
During the years ended December 31, 2016, 2015, and 2014, Rockies Express received contributions from Members of
$304.9 million, $733.1 million, and $165.7 million, respectively. Contributions from Members during the year ended
December 31, 2016 were primarily used to fund the construction and other costs of the Zone 3 Capacity Enhancement project,
as discussed in Note 9 – Regulatory Matters. Contributions from Members during the year ended December 31, 2015 were
used to repay the 2015 Notes, as discussed in Note 4 – Financing, fund the construction and other costs of the Zone 3 East-to-
West Project facilities and the Zone 3 Capacity Enhancement project and remaining costs associated with the Seneca Lateral
Project facilities, and to increase cash on hand for working capital needs. Contributions from Members during the year ended
December 31, 2014 were used to fund the construction and other costs of the Seneca Lateral Project facilities as well as to
increase cash on hand for working capital needs.
Additional contributions and distributions were made subsequent to December 31, 2016. For details see Note 11 –
Subsequent Events.
6. Related Party Transactions
Rockies Express has an operating agreement with Tallgrass NatGas Operator, LLC ("NatGas"), a subsidiary of TD, 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. Effective January 1, 2017, NatGas was acquired by TEP. Rockies Express' practice is to settle
receivable and payable balances that exist with affiliates in the following month.
169
Totals of significant transactions with affiliated companies are as follows:
Revenues: Transportation services (1)...................................... $
Charges from TD:
Compensation, benefits and other charges....................... $
General and administrative charges from affiliate........... $
Oversight Fees:
Tallgrass NatGas Operator, LLC...................................... $
Years Ended December 31,
2016
2015
(in millions)
2014
14.4
$
10.8
$
20.6
9.4
6.2
$
$
$
18.5
8.6
6.3
$
$
$
13.5
17.1
5.9
5.7
(1) Transportation services revenue for the years ended December 31, 2016, 2015, and 2014 is primarily from Sempra
Energy prior to the May 6, 2016 sale of Sempra Energy's ownership to TEP REX Holdings, LLC as described in Note
1 – Description of Business.
Balances with affiliated companies included in the accompanying balance sheets are as follows:
December 31,
2016
2015
(in millions)
Receivables from affiliated companies:
Sempra Energy ................................................................................... $
Total receivables from affiliated companies.................................. $
Payables to affiliated companies:
TD....................................................................................................... $
TEP.....................................................................................................
Total payables to affiliated companies .......................................... $
Gas imbalances with affiliated shippers are as follows:
— $
— $
4.5
0.6
5.1
$
Affiliate gas balance receivables............................................................. $
Affiliate gas balance payables................................................................. $
December 31,
2016
2015
(in millions)
— $
0.2
$
1.2
1.2
2.8
—
2.8
0.2
0.1
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7. Commitments and Contingent Liabilities
Leases
Total rental expense under operating leases was $29.2 million, $29.2 million, and $29.3 million for the years ended
December 31, 2016, 2015, and 2014, respectively. Future minimum commitments related to these leases as of December 31,
2016 are as follows (in millions):
Year
2017 .................................................................................................................................................
2018 .................................................................................................................................................
2019 .................................................................................................................................................
2020 .................................................................................................................................................
2021 .................................................................................................................................................
Thereafter ........................................................................................................................................
Total.................................................................................................................................................
$
$
Future Minimum
Lease Payments
29.2
29.2
29.2
29.2
29.2
174.9
320.9
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 $54.5 million of Rockies Express' capital expenditure budget for 2017 had been committed for purchases
of property, plant and equipment at December 31, 2016.
8. Major Customers
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. During 2015, three non-affiliated shippers accounted
for $187.6 million (24%), $163.0 million (21%), and $104.6 million (13%), respectively of Rockies Express' total revenues.
During 2014, four non-affiliated shippers accounted for $186.5 million (25%), $165.2 million (22%), $110.2 million (15%),
and $101.4 million (14%), respectively of Rockies Express' total revenues. We attempt to mitigate credit risk by seeking
collateral or financial guarantees and letters of credit from customers
9. Regulatory Matters
There are currently no proceedings challenging the currently effective transportation rates of Rockies Express. Regulators,
as well as shippers on Rockies Express, do have rights, under circumstances prescribed by applicable law, to challenge the rates
Rockies Express charges. Rockies Express can provide no assurance that current rates will remain unchallenged. Any
successful challenge could have a material, adverse effect on Rockies Express' future earnings.
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 September 2014, the FERC accepted amended contracts with three 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. Prior to December
2015, only one shipper with current MFN rights was still a party to the proceeding.
171
2015 Annual FERC Fuel Tracking Filings - Docket No. RP15-584-000
On February 27, 2015, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2015
in Docket No. RP15-584-000. This filing incorporated the revised fuel and lost and unaccounted-for and power cost tracker
mechanisms filed in Docket No. RP14-1003. The FERC issued an order accepting the filing on March 26, 2015 and on April 9,
2015, accepted an errata to the February 27, 2015 filing reflecting a corrected rate for the Cheyenne Booster rate (PCT
Reimbursement Charge).
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. As directed by the FERC, Rockies Express filed revised
rates for NGA service on the Seneca Lateral, and the Seneca Lateral commenced NGA service on June 1, 2016.
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 proposed facilities will increase 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 0.8 Bcf/d on January 6, 2017.
2016 Annual and Interim FERC Fuel Tracking Filings - 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. The filing reflected a corrected rate for a previous
inadvertent error made in the allocation of Overthrust, Echo Springs, and Wamsutter fuel between non-expansion and
expansion volumes during the period from July 2014 through July 2016.
Electric Power Charge Clarification - 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 (i.e. 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.
10. 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, have recorded no reserve for legal claims as of December 31, 2016 and
2015.
172
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, at which time Rockies Express recognized a gain on the litigation settlement.
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's bankruptcy estate. The settlement agreement includes Ultra's agreement to: (i) make a cash
payment to Rockies Express of $150 million in accordance with the plan of reorganization, but no later than October 30, 2017;
and (ii) enter 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. The settlement is part of
Ultra's Chapter 11 reorganization plan, which must be submitted to the U.S. Bankruptcy Court for approval.
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 entered into a binding settlement agreement to resolve the claims
brought by Michels in exchange for a $10 million cash payment by Rockies Express. The cash payment will be paid promptly
after entering into the definitive agreement with respect to the settlement.
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.
11. Subsequent Events
Subsequent events, which are events or transactions that occurred after December 31, 2016 through the issuance of the
accompanying financial statements, have been evaluated through February 15, 2017.
Members' Equity
Rockies Express paid distributions of $43.8 million to its Members and received contributions from Members of $11.8
million in January 2017.
173
(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
3.1
3.2
3.3
3.4
3.5
3.6
3.7
4.1
4.2
10.1
10.2†
10.3†
10.4†*
10.5
10.6
Certificate of Limited Partnership of Tallgrass Energy Partners, LP, dated as of February 6, 2013
(incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (File No.
333-187595) filed on March 28, 2013).
Certificate of Amendment to Certificate of Limited Partnership of Tallgrass Energy Partners, LP, dated as of
February 7, 2013 (incorporated by reference to Exhibit 3.2 to the Partnership’s Registration Statement on
Form S-1 (File No. 333-187595) filed on March 28, 2013).
Amended and Restated Agreement of Limited Partnership of Tallgrass Energy Partners, LP, dated May 17,
2013 (incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on Form 8-K filed on May
17, 2013).
Certificate of Formation of Tallgrass MLP GP, LLC, dated as of February 6, 2013 (incorporated by reference
to Exhibit 3.4 to the Partnership’s Registration Statement on Form S-1 (File No. 333-187595) filed on March
28, 2013).
Second Amended and Restated Limited Liability Company Agreement of Tallgrass MLP GP, LLC, dated May
17, 2013 (incorporated by reference to Exhibit 3.4 to the Partnership’s Current Report on Form 8-K filed on
May 17, 2013).
Amendment No. 1, dated February 19, 2015, to Second Amended and Restated Limited Liability Company
Agreement of Tallgrass MLP GP, LLC, dated May 17, 2013 (incorporated by reference to Exhibit 3.8 to the
Partnership’s Annual Report on Form 10-K/A filed on June 6, 2015).
Third Amended and Restated Limited Liability Company Agreement of Tallgrass Pony Express Pipeline,
LLC, dated as of March 1, 2015, by and among Tallgrass Pony Express Pipeline, LLC, Tallgrass Operations,
LLC, and Tallgrass PXP Holdings, LLC (incorporated by reference to Exhibit 10.2 to the Partnership’s
Current Report on Form 8-K filed on March 2, 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 the Partnership’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 the Partnership’s Current Report on Form 8-K filed on September 1, 2016).
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 the Partnership’s Current Report on Form 8-K filed on May 17, 2013).
Tallgrass MLP GP, LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the
Partnership’s Current Report on Form 8-K filed on May 17, 2013).
Form of Employee Equity Participation Unit Agreement (incorporated by reference to Exhibit 4.5 to the
Partnership’s Registration Statement on Form S-8 filed on June 28, 2013).
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.
Revolving Credit Agreement, dated May 17, 2013, by and among Tallgrass Energy Partners, LP, Barclays
Bank PLC, as administrative agent, and a syndicate of lenders named therein (incorporated by reference to
Exhibit 10.3 to the Partnership’s Current Report on Form 8-K filed on May 17, 2013).
Amendment No. 1, dated June 25, 2014, to the Revolving Credit Agreement, dated May 17, 2013, by and
among Tallgrass Energy Partners, LP, Barclays Bank PLC, as administrative agent, and a syndicate of lenders
named therein (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K
filed on June 30, 2014).
174
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
12.1*
21.1*
23.1*
23.2*
31.1*
31.2*
32.1*
Amendment No. 2 to Credit Agreement, dated as of November 24, 2015, by and among Tallgrass Energy
Partners, LP, Barclays Bank PLC, as administrative agent, and a syndicate of lenders named therein
(incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on
November 30, 2015).
Amendment No. 3 to Credit Agreement, dated January 11, 2016, by and among Tallgrass Energy Partners, LP,
Barclays Bank PLC, as administrative agent, and a syndicate of lenders named therein (incorporated by
reference to Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K filed on February 17, 2016).
Amendment No. 4 to Credit Agreement, dated as of April 27, 2016, by and among Tallgrass Energy Partners,
LP, Barclays Bank PLC, as administrative agent, and a syndicate of lenders named therein (incorporated by
reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed on April 28, 2016).
Purchase and Sale Agreement, dated as of March 1, 2015, 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 March 2, 2015).
Contribution and Transfer Agreement, dated January 1, 2016, by and among Tallgrass Energy Partners, LP,
Tallgrass Operations, LLC, and for certain limited purposes, Tallgrass Development, LP (incorporated by
reference to Exhibit 10.14 to the Partnership’s Annual Report on Form 10-K filed on February 17, 2016).
Transfer, Purchase and Sale Agreement, dated as of December 16, 2015, by and between Whiting Oil and Gas
Corporation, BNN Western, LLC and BNN Redtail, LLC (incorporated by reference to Exhibit 10.1 to the
Partnership’s Current Report on Form 8-K filed on December 16, 2015).
Membership Interest Purchase Agreement, dated as of March 29, 2016, by and between Sempra REX
Holdings, LLC and TEP REX Holdings, LLC (as successor by assignment to Rockies Express Holdings,
LLC) (incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q filed on
August 3, 2016).
Assignment and Assumption Agreement, dated as of May 6, 2016, by and among Rockies Express Holdings,
LLC, TEP REX Holdings, LLC and, for the limited purposes set forth therein, Tallgrass Development, LP
(incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q filed on
August 3, 2016).
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).
Ratio of Earnings to Fixed Charges
List of Subsidiaries of Tallgrass Energy Partners, LP.
Consent of PricewaterhouseCoopers LLP on Consolidated Financial Statements of Tallgrass Energy Partners,
LP and the effectiveness of Tallgrass Energy Partners, 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.
175
32.2*
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).
Item 16. Form 10-K Summary
Not applicable.
176
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 Partners, LP
By: Tallgrass MLP GP, LLC, its general partner
By:
/s/ David G. Dehaemers, Jr.
David G. Dehaemers, Jr.
President and Chief Executive Officer of Tallgrass MLP
GP, LLC (the general partner of Tallgrass Energy
Partners, LP)
Date: February 15, 2017
177
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 15, 2017
(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/ Terrance D. Towner
Terrance D. Towner
/s/ Roy N. Cook
Roy N. Cook
/s/ Jeffrey R. Armstrong
Jeffrey R. Armstrong
Executive Vice President and Chief Financial Officer
February 15, 2017
(Principal Financial Officer)
Vice President and Chief Accounting Officer
February 15, 2017
(Principal Accounting Officer)
February 15, 2017
February 15, 2017
February 15, 2017
February 15, 2017
February 15, 2017
February 15, 2017
February 15, 2017
February 15, 2017
Director
Director
Director
Director
Director
Director
Director
Director
178
SECOND AMENDED AND RESTATED EMPLOYMENT AGREEMENT
Exhibit 10.4
This Second Amended and Restated Employment Agreement (this “Agreement”) is entered into on November 2, 2016,
by and among Tallgrass Management, LLC, a Delaware limited liability company (the “Company”), Tallgrass Energy
Holdings, LLC, a Delaware limited liability company formerly known as Tallgrass Development GP, LLC (“Holdings”),
Tallgrass Equity, LLC, a Delaware limited liability company formerly known as Tallgrass GP Holdings, LLC (“Tallgrass
Equity”), Tallgrass MLP GP, LLC, a Delaware limited liability company (“MLP GP”), TEGP Management, LLC, a Delaware
limited liability company (“TEGP Management,” and together with Holdings, Tallgrass Equity, and MLP GP, the “Partnership
Entities”) and David G. Dehaemers, Jr., an individual (“Dehaemers”).
RECITALS
WHEREAS, the Company, Holdings, Tallgrass Equity, MLP GP and Dehaemers are parties to that certain Amended and
Restated Employment Agreement, dated May 17, 2013 (the “Prior Agreement”); and
WHEREAS, the Company is a subsidiary of Holdings, which is the general partner of Tallgrass Development, LP, a
Delaware limited liability company (“Development”), and the sole member of TEGP Management, the general partner of
Tallgrass Energy GP, LP, a Delaware limited partnership (“TEGP Partnership”); and
WHEREAS, TEGP Management and TEGP Partnership were formed by Holdings for the purposes of effecting an initial
public offering of Class A Shares representing limited partner interests of TEGP Partnership that closed in May 2015 (the
“Offering”); and
WHEREAS, in connection with the reorganization transactions necessary for purposes of effecting the Offering, (i)
Tallgrass Equity distributed its membership interest in Holdings to the then-current members of Tallgrass Equity, pro rata, and
(ii) Tallgrass Equity’s members amended and restated Tallgrass Equity’s limited liability company agreement making TEGP
Partnership the managing member; and
WHEREAS, Tallgrass Equity owns 100% of MLP GP, and MLP GP is the general partner of Tallgrass Energy Partners,
LP (the “MLP”); and
WHEREAS, the Company, the Partnership Entities and Dehaemers wish to amend and restate the Prior Agreement to
reflect, among other items, the entity name changes and structure changes above and it is the parties’ intention and agreement
for Dehaemers to be employed by the Company and to serve as the President and Chief Executive Officer of the Company and
each of the Partnership Entities pursuant to this Agreement; and
WHEREAS, pursuant to Section 11 of the Prior Agreement, amendment of the Prior Agreement requires a writing signed
by the parties thereto.
NOW, THEREFORE, the Prior Agreement is amended and restated in its entirety as follows:
1.
2.
Employment. The Company agrees to continue to employ Dehaemers and Dehaemers agrees to continue to be
employed by the Company as President and Chief Executive Officer upon the terms and conditions of this
Agreement until such employment is terminated as provided in Section 7. So long as Dehaemers is employed by
the Company as its President and Chief Executive Officer, each of the Partnership Entities agrees that Dehaemers
will also serve as and be appointed President and Chief Executive Officer of each of the Partnership Entities.
Compensation. For all services rendered by Dehaemers to the Company, the Partnership Entities and each of the
downstream affiliates of the Partnership Entities (the Partnership Entities and such downstream affiliates, the
“Constituent Companies”), the Company will pay Dehaemers a base monthly salary of $25,000 ($300,000 if
annualized), which will accrue and be payable monthly in arrears in accordance with the Company’s general
payroll practices. All payments made and benefits provided by the Company to Dehaemers under this Agreement
are subject to any applicable withholding and other applicable taxes.
3.
Additional Benefits; Expenses; Liability Insurance.
(a)
Dehaemers will be eligible for additional benefits, by way of insurance, hospitalization and vacations
normally provided to senior executives of the Company, pursuant to the terms of those plans, programs and
policies of the Company in effect during his employment by the Company, and such additional benefits, if
any, as determined by the Board of Managers of Holdings.
(b)
The Company will reimburse Dehaemers for all ordinary and necessary out-of-pocket expenses incurred
and paid by Dehaemers in the course of the performance of his duties pursuant to this Agreement and
4.
5.
consistent with the Company’s policies in effect from time to time with respect to travel, entertainment and
other business expenses, and subject to the Company’s requirements with respect to the manner of approval
and reporting of these expenses.
(c)
So long as Dehaemers is employed under this Agreement and thereafter so long as Dehaemers is subject to
any possible claim, the Company and the Partnership Entities will purchase and maintain in effect for the
benefit of Dehaemers one or more valid and enforceable policies of directors and officers liability
insurance providing, in all respects, coverage at least as beneficial to Dehaemers as that provided pursuant
to the insurance policies in place on the date hereof.
Duties. So long as Dehaemers is employed under this Agreement, Dehaemers will (a) devote his best efforts and
his entire business time (other than as a result of illness or disability) to further the interests of the Company and
the Constituent Companies, (b) carry out the reasonable and lawful instructions of the Board of Managers of
Holdings (other than as a result of illness or disability) with respect to those matters reserved to the Board of
Managers of Holdings pursuant to Section 8.1 of the Second Amended and Restated Limited Liability Company
Agreement of Holdings, dated May 11, 2015 (as amended, restated or otherwise modified from time to time, the
“Holdings LLC Agreement”), (c) truthfully and accurately maintain and preserve the records of the Company and
the Constituent Companies and make all reports reasonably required by the Board of Managers of Holdings, and
(d) fully account for all monies and other property of the Company or any of the Constituent Companies that he
may from time to time have in his custody and deliver the same to the Company or its designee to the extent
reasonably directed to do so; provided that, so long as it does not materially interfere with his duties, nothing
herein will preclude Dehaemers from accepting appointment to or continuing to serve on any board of directors
(or similar governing body) or as trustee of any business (not competing with any of the Constituent Companies)
or any charitable organization, from engaging in charitable and community activities, from delivering lectures and
fulfilling speaking engagements, or from directing and managing his personal investments and those of his family.
Covenant Not to Compete. Dehaemers acknowledges that, during his employment with the Company, he, at the
expense of the Company and the Constituent Companies, will establish favorable relations with the customers to,
and regulators of, the Company and the Constituent Companies and will receive and have access to the
intellectual property and confidential information of the Company and the Constituent Companies. Therefore, in
consideration of these relationships, his employment with the Company, and to further protect the intellectual
property and confidential information of the Company and the Constituent Companies, Dehaemers agrees that,
during the term of his employment by the Company and for a period of one year from and after the voluntary or
involuntary termination of employment for any or no reason, he will not, directly or indirectly, without the
express written consent of the Board of Managers of Holdings except when and as requested to do in and about
the performance of his duties under this Agreement:
(a)
own, manage, operate, control or participate in the ownership, management, operation or control of, or
have any interest, financial or otherwise, in or act as an officer, director, partner, principal, member,
manager, shareholder, employee, agent, representative, consultant or independent contractor of, or in any
way assist any person or entity in the conduct of, any business located in or doing business in the area
where a Constituent Company is engaged or becomes engaged in any business competitive to any business
engaged in by a Constituent Company during the term of his employment by the Company, including, but
not limited to, any business that is engaged in the interstate transportation via pipeline of natural gas,
petroleum or petroleum byproducts; provided, however, that notwithstanding the foregoing, Dehaemers
may own up to 5% of the outstanding equity securities in any corporation or entity that is listed upon a
national stock exchange or actively traded in the over-the-counter market; provided, further, that
notwithstanding the foregoing, Dehaemers may own, directly or indirectly, an ownership interest in the
general partner of Plains All American Pipeline, L.P. or their affiliates or successors; provided, further, that
notwithstanding the foregoing, Dehaemers may place or invest money with one or more private equity
firms (or related investment funds or vehicles) that compete (or own or invest in companies that compete)
with a Constituent Company so long as Dehaemers does not control or otherwise direct the activities of the
private equity firm (or related investment funds or vehicles) or control or otherwise direct the investment in
the competing portfolio company; or
(b)
entice, induce or in any manner influence any person who has an employee or independent contractor
relationship with the Company or any Constituent Company and with whom Dehaemers had contact,
directly or indirectly, during the term of his employment to change or end such relationship for the purpose
of engaging in a business in competition with any business engaged in by the Company or any Constituent
Company during the term of his employment by the Company or hire any such person.
6.
Specific Performance. Recognizing that irreparable damage will result to the Company and the Constituent
Companies in the event of the breach of any of the foregoing covenants and assurances by Dehaemers contained
in Section 5, and that the Company’s remedies at law for any such breach or threatened breach will be inadequate,
the Company, in addition to such other remedies that may be available to it, will be entitled to an injunction,
including a mandatory injunction, to be issued by any court of competent jurisdiction ordering compliance with
this Agreement or enjoining and restraining Dehaemers, and each and every person and entity acting in concert or
participation with him, from the continuation of the breach. The Company will not be required to obtain a bond
in an amount greater than $1,000. The covenants and obligations of Dehaemers set forth in Section 5 are in
addition to and not in lieu of or exclusive of any other obligations and duties of Dehaemers to the Company,
whether express or implied in fact or in law.
7.
Termination.
(a)
(b)
(c)
Dehaemers’s employment by the Company will terminate immediately (unless otherwise determined by the
Board of Managers of Holdings) upon the occurrence of any of the following: (1) the death, mental or
physical incapacity or inability to perform the essential functions of his job for a consecutive period of 90
days or a non-consecutive period of 120 days during any 12-month period, as reasonably determined by the
Board of Managers of Holdings after consultation with an independent physician selected by the Company
(such periods to be extended if appropriate as a reasonable accommodation for a disability); or (2) the
winding up and final distribution of the assets of each of Development, the MLP and TEGP Partnership.
Dehaemers’s employment by the Company will terminate on the date specified in a notice of termination
(which may not be less than 30 days after the date of the notice) from a majority of the members of the
Board of Managers of Holdings (excluding Dehaemers or any of his designees), which may be sent at the
discretion of a majority of the members of the Board of Managers of Holdings (excluding Dehaemers or
any of his designees), as a result of the occurrence of any of the following: (1) Dehaemers and his
Permitted Transferees (as defined in the Holdings LLC Agreement) cease to control Tallgrass KC, LLC; or
(2) Dehaemers and his Permitted Transferees cease to have direct or indirect beneficial ownership of at
least 12.5% of the total Common GP Interests (as such term is defined in the Holdings LLC Agreement).
The Company may terminate Dehaemers’s employment for Cause or without Cause. “Cause” means: (1)
his conviction of, or plea of nolo contendere to, any crime or offense constituting a felony under applicable
law, other than any motor vehicle violations for which no custodial penalty is imposed; (2) his commission
of fraud or embezzlement against the Company or any Constituent Company; (3) gross neglect by
Dehaemers of, or gross or willful misconduct by Dehaemers in connection with the performance of, his
duties to the Company that, if curable, is not cured within 30 days after a written notice of such gross
neglect, or gross or willful misconduct, specifically identifying the gross neglect or misconduct, is
delivered by a majority of the members of the Board of Managers of Holdings (excluding Dehaemers or
any of his designees) to Dehaemers; (4) Dehaemers willfully fails or refuses to carry out the reasonable and
lawful instructions of the Board of Managers of Holdings (other than as a result of illness or disability)
with respect to those matters reserved to the Board of Managers of Holdings pursuant to Section 8.1 of the
Holdings LLC Agreement, and, in each case, such failure or refusal has continued for a period of 30
calendar days following written notice from the majority of the members of the Board of Managers of
Holdings (excluding Dehaemers or any of his designees); (5) his failure to perform the duties and
responsibilities of his office as his primary business activity, provided that, so long as it does not materially
interfere with his duties on behalf of the Company, nothing herein will preclude Dehaemers from accepting
appointment to or continuing to serve on any board of directors (or similar governing body) or as trustee of
any business corporation (not competing with any Constituent Company) or any charitable organization,
from engaging in charitable and community activities, from delivering lectures and fulfilling speaking
engagements, or from directing and managing his personal investments and those of his family; (6) a
judicial determination that he has breached his fiduciary duties with respect to the Company or any
Constituent Company; or (7) his willful and material breach of his obligations in the Holdings LLC
Agreement (in his capacity as an officer and not in his capacity as a Member), his obligations in the Second
Amended and Restated Limited Liability Company Agreement of Tallgrass Equity, dated as of May 12,
2015, as amended, restated or otherwise modified from time to time (in his capacity as an officer and not in
his capacity as a Member), his obligations in the Second Amended and Restated Limited Liability
Company Agreement of MLP GP, dated as of May 17, 2013, as amended, restated or otherwise modified
from time to time (in his capacity as an officer and not in his capacity as a Member), or his obligations in
the Amended and Restated Limited Liability Company Agreement of TEGP Management, dated May 12,
2015, as amended, restated or otherwise modified from time to time (in his capacity as an officer and not in
his capacity as a Member) (such agreements, collectively, the “Organizational Documents”), including
willfully causing any Partnership Entity to take any material action prohibited by the Organizational
Documents, that Dehaemers failed to cure, if curable, within 30 days following written notice thereof,
specifically identifying such willful and material breach, having been delivered to Dehaemers by a majority
of the members of the Board of Managers of Holdings (excluding Dehaemers or any of his designees).
(d)
Dehaemers may terminate his employment with the Company with good reason or without good reason. A
“Resignation for Good Reason” means his resignation for good reason (as defined below) if (x) he provides
written notice to the Company describing in reasonable detail the event and stating that his employment
will terminate upon a specified date in such notice (“Good Reason Termination Date”), which date is not
earlier than 30 days after the date such notice is provided to the Company (“Notice Delivery Date”) and not
later than 90 days after the Notice Delivery Date and (y) the Company does not remedy the event prior to
the Good Reason Termination Date. For purposes of this Agreement, Dehaemers has “good reason” if
there occurs without his prior written consent:
(1)
(2)
(3)
(4)
a material diminution of his duties and responsibilities to the Company or any Constituent
Company to a level inconsistent with those of a chief executive officer;
a material reduction in his cash compensation or a material reduction in the aggregate welfare
benefits provided to him (not including any reduction related to a broader compensation or benefit
reduction that is not limited to him specifically);
a willful or intentional breach of this Agreement by the Company; or
a willful or intentional breach of a material provision of any of the Organizational Documents by
any Partnership Entity or the Primary Investors (as defined in the Holdings LLC Agreement) that
has a material and adverse effect on Dehaemers.
(e)
If (1) Dehaemers’s employment with the Company is terminated pursuant to Sections 7(a) or 7(b), (2) the
Company terminates his employment for Cause or (3) Dehaemers terminates his employment other than as
a result of a Resignation for Good Reason, the Company will pay or provide to him:
(i)
(ii)
such unpaid salary as Dehaemers has earned up to the date of his termination; and
the other benefits and other amounts due him under Section 3 or as otherwise required by
applicable law, as he has earned up to the date of his termination.
(f)
If (1) the Company terminates Dehaemers’s employment without Cause or (2) Dehaemers terminates his
employment as a result of a Resignation for Good Reason, the Company will pay or provide to him:
(i)
(ii)
(iii)
such unpaid salary as Dehaemers has earned up to the date of his termination;
an amount equal to $900,000, payable as a lump sum within 60 days after the termination of
employment; and
such other benefits and other amounts due him under Section 3 or as otherwise required by
applicable law, as he has earned up to the date of his termination.
(g)
(h)
Except as provided in Section 7(i), any payment under this Section 7(f) must be made within 60 days after
the termination of his employment; provided, however, if the termination of his employment is not a
“separation from service” as described in Treas. Reg. § 1 .409A- 1(h) (a “Section 409A Separation”), such
payment will be delayed until his Section 409A Separation.
As a condition to receiving the termination payments and benefits provided in this Section 7, Dehaemers
will execute and deliver to the Company a release, in a form reasonably satisfactory to the Company,
releasing all claims arising out of his employment (other than enforcement of this Agreement, his rights
under any of the Company’s incentive compensation and employee benefit plans and programs to which
Dehaemers is entitled under this Agreement, and any claim for any tort for personal injury not arising out
of or related to this termination).
So long as Dehaemers is an employee of the Company and thereafter (including after the termination of his
employment), he will not make any disparaging comment in any format, whether written, electronic or
oral, to any client, customer, account, supplier, service provider, agency, regulator, employee, the media, or
any other person or entity regarding the Company or any Constituent Company or any of their clients,
customers, accounts, suppliers, service providers, employees, agents, regulators, officers or directors or
otherwise relating to the business of the Company or any Constituent Company.
(i)
(j)
If Dehaemers is a “Specified Employee” (as defined under Section 409A of the Internal Revenue Code of
1986, as amended (“Code”)) as of the date of his termination of employment, as determined by the
Company, and any equity security of the Company or any Constituent Company is publicly traded on an
established securities market or otherwise, the payment of any amount under this Agreement on account of
his Section 409A Separation that is deferred compensation subject to the provisions of Code Section 409A
and not otherwise excluded from Code Section 409A, will not be paid until the later of the first business
day that is six months after the date after his Section 409A Separation or the date the payment is otherwise
payable under this Agreement (the “Delay Period”). Upon the expiration of the Delay Period, all payments
and benefits delayed will be paid or reimbursed to Dehaemers in a lump sum, without interest, and any
remaining payments due under this Agreement will be paid or provided in accordance with the normal
payment dates specified herein.
All reimbursement and in-kind benefits provided pursuant to this Agreement will be made in accordance
with Treas. Reg. § 1 .409A-3(i)(1)(iv) such that any reimbursement or in-kind benefits will be deemed
payable at a specified time or on a fixed schedule relative to a permissible payment event. Specifically, (1)
the amounts reimbursed and in-kind benefits provided under this Agreement, other than with respect to
medical benefits, during Dehaemers’s taxable year may not affect the amount reimbursed or in-kind benefit
provided in any other taxable year, (2) the reimbursement of an eligible expense will be made on or before
the last day of his taxable year following the taxable year in which the expense was incurred, and (3) the
right to reimbursement or an in-kind benefit is not subject to liquidation or exchange for another benefit.
8.
9.
Cooperation Regarding Litigation. So long as Dehaemers is an employee of the Company and thereafter for a
period of five years (including after the termination of his employment), Dehaemers will reasonably cooperate
with the Company and any Constituent Company by making himself available to testify on behalf of the
Company or any Constituent Company, in any action, suit, or proceeding (whether civil, criminal, administrative
or investigative) and reasonably assist the Company or any Constituent Company in any such action, suit, or
proceeding, by providing information and meeting and consulting with the Board of Managers of Holdings or its
representatives or counsel, or representatives or counsel to the Company or any Constituent Company, as
requested. The Company will promptly reimburse Dehaemers for all reasonable expenses incurred by Dehaemers
in connection with his provision of testimony or assistance.
No Conflict. Dehaemers represents and warrants to the Company and each Partnership Entity that neither the
execution nor delivery of this Agreement, nor the performance of his obligations under this Agreement will
conflict with, or result in a breach of, any term, condition, or provision of, or constitute a default under, any
obligation, contract, agreement, covenant or instrument to which he is a party or under which he is bound,
including, without limitation, the breach by Dehaemers of a fiduciary duty to any former employers.
10. Waiver of Breach. Failure of the Company or any Partnership Entity to demand strict compliance with any of the
terms, covenants or conditions hereof will not be deemed a waiver of the term, covenant or condition, nor will any
waiver or relinquishment by the Company or any Partnership Entity of any right or power under this Agreement at
any one time or more times be deemed a waiver or relinquishment of the right or power at any other time or times.
11.
12.
Entire Agreement; Amendment. This Agreement cancels and supersedes all previous agreements other than the
Confidentiality Agreement and Assignment of Inventions, by and between Dehaemers and the Company, entered
into in connection with his employment by the Company (the “Confidentiality Agreement”) relating to the subject
matter of this Agreement, written or oral, between the parties, including, without limitation, the Prior Agreement.
This Agreement and the Confidentiality Agreement contain the entire understanding of the parties with respect to
the subject matter hereof and may not be amended, modified or supplemented in any manner whatsoever except
as otherwise provided herein or in writing signed by each of the parties.
Potential Unenforceability of any Provision. If a final judicial determination is made that any provision of this
Agreement is an unenforceable restriction against Dehaemers, the provisions of this Agreement will be rendered
void only to the extent that a judicial determination finds the provisions unenforceable, and the unenforceable
provisions will automatically be reconstituted and become a part of this Agreement, effective as of the date of this
Agreement, to the maximum extent in favor of the Company and the Partnership Entities that is lawfully
enforceable. A judicial determination that any provision of this Agreement is unenforceable will not render the
entire Agreement unenforceable, but rather this Agreement will continue in full force and effect absent any
unenforceable provision to the maximum extent permitted by law.
13.
Headings. The headings of the sections of this Agreement have been inserted for convenience of reference only
and do not restrict or otherwise modify any of the terms or provisions of this Agreement.
14.
15.
Governing Law. This Agreement is governed by the laws of the State of Kansas applicable to agreements made
and to be performed entirely within the State, including all matters of enforcement, validity and performance.
Notice. Any notice, request, consent or communication under this Agreement is effective only if it is in writing
any (a) personally delivered or (b) sent by a nationally recognized overnight delivery service, with delivery
confirmed, addressed as follows:
If to the Company:
Tallgrass Management, LLC
4200 W. 115th Street, Suite 350
Leawood, Kansas 66211
Attn: General Counsel
If to Holdings:
Tallgrass Energy Holdings, LLC
4200 W. 115th Street, Suite 350
Leawood, Kansas 66211
Attn: General Counsel
If to Tallgrass Equity:
Tallgrass Equity, LLC
4200 W. 115th Street, Suite 350
Leawood, Kansas 66211
Attn: General Counsel
If to MLP GP:
Tallgrass MLP GP, LLC
4200 W. 115th Street, Suite 350
Leawood, Kansas 66211
Attn: General Counsel
If to TEGP Management:
TEGP Management, LLC
4200 W. 115th Street, Suite 350
Leawood, Kansas 66211
Attn: General Counsel
If to Dehaemers:
David G. Dehaemers, Jr.
c/o Tallgrass Energy Partners, LP
4200 W. 115th Street, Suite 350
Leawood, Kansas 66211
or such other persons or to such other addresses as may be furnished in writing by any party to the other party, and
will be deemed to have been given only upon its delivery in accordance with this Section 15.
16.
17.
Assignment. This Agreement is personal and not assignable by Dehaemers. This Agreement may be assigned by
the Company or any Partnership Entity without notice to or consent of any other party of this Agreement;
provided that, such assignment must be to a Constituent Company. Except as described in the preceding sentence,
this Agreement is not assignable by any party hereto without the consent of all the parties to this Agreement.
Survival of Obligations. All obligations of Dehaemers that by their nature involve performance, in any particular,
after the expiration or termination of this Agreement, or that cannot be ascertained to have been fully performed
until after the expiration or termination of this Agreement, will survive the expiration or termination of this
Agreement.
18.
19.
20.
21.
22.
Counterparts. This Agreement may be executed in any number of counterparts, each of which will be deemed to
be an original and all of which constitute one agreement that is binding upon each of the parties, notwithstanding
that all parties are not signatories to the same counterpart.
Consent to Jurisdiction and Venue. The parties hereby submit to the exclusive jurisdiction of the District Court
for Johnson County, Kansas or the United States District Court for the District of Kansas in any action or
proceeding arising out of or relating to this Agreement, including any appeal and any action for enforcement or
recognition of any judgment relating thereto, and the parties hereby irrevocably agree that all claims in respect of
such action or proceeding may not be heard or determined in any court or before any panel other than the District
Court for Johnson County, Kansas or the United States District Court for the District of Kansas. A final judgment
in any such action or proceeding will be conclusive and may be enforced in any other jurisdictions by suit on the
judgment or in any manner provided by law. The parties hereby irrevocably waive, to the fullest extent they may
legally and effectively do so, any objection they may have to the laying of venue of any suit, action or proceeding
arising out of or relating to this Agreement or the transactions contemplated hereby in the District Court for
Johnson County, Kansas or the United States District Court for the District of Kansas. The parties hereby
irrevocably waive, to the fullest extent they may legally and effectively do so, the defense of an inconvenient
forum to the maintenance of any suit, action or proceeding in any such court. The parties irrevocably consent to
service of process in any suit, action or proceeding in any manner provided by law.
Expenses. If either party brings any legal action or other proceeding to enforce or interpret any of the rights,
obligations or provisions of this Agreement, or because of a dispute, breach or default in connection with any of
the provisions of this Agreement, the prevailing party is entitled to recover from the non-prevailing party
reasonable attorneys’ fees and all other costs in such action or proceeding in addition to, but without duplication,
any other relief to which the prevailing party may be entitled.
No Mitigation; No Offset. If Dehaemers’s employment is terminated, he will be under no obligation to seek other
employment and amounts due him under this Agreement will not be offset by any remuneration attributable to any
subsequent employment that he may obtain.
Deferred Compensation. This Agreement is intended to meet the requirements of Section 409A of the Code and
will be administered in a manner that is intended to meet those requirements and will be construed and interpreted
in accordance with such intent. To the extent that an award or payment, or the settlement or deferral thereof, is
subject to Section 409A of the Code, except as Dehaemers and the Board of Managers of Holdings otherwise
determine in writing, the award will be granted, paid, settled or deferred in a manner that will meet the
requirements of Section 409A of the Code, including regulations or other guidance issued with respect thereto,
such that the grant, payment, settlement or deferral will not be subject to the excise tax applicable under Section
409A of the Code. Any provision of this Agreement that would cause the award or the payment, settlement or
deferral thereof to fail to satisfy Section 409A of the Code will be amended to comply with Section 409A of the
Code on a timely basis, which may be made on a retroactive basis, in accordance with regulations and other
guidance issued under Section 409A of the Code.
[Signature page follows.]
The parties have executed this Employment Agreement on the date set forth in the introductory clause.
TALLGRASS MANAGEMENT, LLC
/s/ William R. Moler________________
By:
Name: William R. Moler
Title:
Executive Vice President and
Chief Operating Officer
TALLGRASS ENERGY HOLDINGS, LLC
/s/ William R. Moler________________
By:
Name: William R. Moler
Title:
Executive Vice President and
Chief Operating Officer
TALLGRASS EQUITY, LLC
/s/ William R. Moler________________
By:
Name: William R. Moler
Title:
Executive Vice President and
Chief Operating Officer
TALLGRASS MLP GP, LLC
/s/ William R. Moler________________
By:
Name: William R. Moler
Title:
Executive Vice President and
Chief Operating Officer
TEGP MANAGEMENT, LLC
/s/ William R. Moler________________
By:
Name: William R. Moler
Title:
Executive Vice President and
Chief Operating Officer
/s/ David G. Dehaemers, Jr.
David G. Dehaemers, Jr.
Signature Page to Employment Agreement
Exhibit 12.1
TEP Pre-
Predecessor
Period from
January 1,
2012 to
November
12, 2012
$
51,775
69
—
—
—
The table below sets forth the calculation of Ratios of Earnings to Fixed Charges for the periods indicated.
RATIO OF EARNINGS TO FIXED CHARGES
(in thousands, except ratio data)
Year Ended December 31,
TEP (1)
Earnings from continuing operations
before fixed charges:
2016
2015
2014
2013
Period from
November 12,
2012 to
December 31,
2012
Pre-tax income from continuing operations
before earnings from unconsolidated
affiliates (2) ................................................... $ 216,114
51,306
Fixed charges...............................................
Amortization of capitalized interest ............
Distributed earnings from unconsolidated
affiliates .......................................................
less: Capitalized interest ..............................
Earnings from continuing operations
before fixed charges..................................... $ 318,794
51,780
65
(471)
Fixed charges:
Interest expense, net of capitalized interest.
Capitalized interest ......................................
Estimate of interest within rental expense
(33.3%) ........................................................
Amortization of debt costs...........................
3,614
Total fixed charges....................................... $ 51,306
10,032
37,189
471
$ 184,814
$ 58,612
$ 7,624
$
25,437
11,626
13,360
66
35
—
—
(811)
717
(1,025)
—
(242)
(2,618)
3,450
—
—
—
$ 209,506
$ 69,965
$ 20,742
$
832
$
51,844
14,226
811
8,615
1,785
7,648
1,025
1,574
1,379
11,264
242
109
1,745
3,040
—
14
396
$ 25,437
$ 11,626
$ 13,360
$
3,450
$
—
—
69
—
69
Ratio of earnings to fixed charges ...............
6.21
8.24
6.02
1.55
—
(3)
751.36
(1) TEP closed the acquisition of Trailblazer on April 1, 2014 and the acquisition of a controlling 33.3% membership interest
in Pony Express effective September 1, 2014. As the acquisitions of Trailblazer and the initial 33.3% of Pony Express were
considered transactions between entities under common control, and changes in reporting entity, financial information
presented subsequent to November 13, 2012 and prior to the respective acquisition dates has been recast to include
Trailblazer and the initial 33.3% of Pony Express. TEP closed the acquisition of an additional 33.3% membership interest
in Pony Express effective March 1, 2015, which represents a transaction between entities under common control and an
acquisition of noncontrolling interests. As a result, financial information for periods prior to March 1, 2015 have not been
recast to reflect the additional 33.3% membership interest.
(2) For purposes of determining the ratio of earnings to fixed charges, earnings are defined as pretax income or loss from
continuing operations before earnings from unconsolidated affiliates, plus fixed charges, plus distributed earnings from
unconsolidated affiliates, less capitalized interest. Fixed charges consist of interest expensed, capitalized interest,
amortization of deferred loan costs, and an estimate of the interest within rental expense.
(3) As a result of the net loss for the period from November 12, 2012 to December 31, 2012, the ratio of earnings to fixed
charges was less than 1:1. TEP would have needed to generate additional earnings of $2.6 million to achieve an earnings to
fixed charges ratio of 1:1 for the period from November 12, 2012 to December 31, 2012.
1
Tallgrass Energy Partners, LP
Subsidiaries
Exhibit 21.1
Jurisdiction of Organization
Company
Tallgrass MLP Operations, LLC .......................................................................................... Delaware
Tallgrass Energy Finance Corp. ........................................................................................... Delaware
Tallgrass Interstate Gas Transmission, LLC......................................................................... Colorado
Tallgrass Midstream, LLC.................................................................................................... Delaware
Tallgrass Energy Investments, LLC..................................................................................... Delaware
Trailblazer Pipeline Company LLC ..................................................................................... Delaware
Tallgrass PXP Holdings, LLC.............................................................................................. Delaware
Tallgrass Pony Express Pipeline, LLC................................................................................. Delaware
Tallgrass Colorado Pipeline, Inc. ......................................................................................... Colorado
TEP REX Holdings, LLC..................................................................................................... Delaware
Tallgrass NatGas Operator, LLC.......................................................................................... Delaware
Tallgrass Terminals, LLC..................................................................................................... Delaware
Tallgrass Sterling Terminal, LLC......................................................................................... Delaware
BNN Water Solutions, LLC ................................................................................................. Delaware
BNN Redtail, LLC ............................................................................................................... Delaware
Alpha Reclaim Technology, LLC......................................................................................... Texas
BNN Western, LLC.............................................................................................................. Delaware
BNN South Texas, LLC ....................................................................................................... Delaware
BNN West Texas, LLC......................................................................................................... Delaware
BNN Recycle, 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/A (No. 333-210976), S-3
(No. 333-205781) and S-8 (No. 333-189417) of Tallgrass Energy Partners, LP, of our report dated February 15, 2017, relating
to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form
Exhibit 23.1
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 15, 2017
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3/A (No. 333-210976), S-3
(No. 333-205781) and S-8 (No. 333-189417) of Tallgrass Energy Partners, LP, of our report dated February 15, 2017, relating
to the financial statements of Rockies Express Pipeline LLC, which appears in this Form
LP.
of Tallgrass Energy Partners,
Exhibit 23.2
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 15, 2017
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 Partners, 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 MLP
GP, LLC (the general partner of Tallgrass Energy
Partners, LP)
Date: February 15, 2017
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 Partners, 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 MLP GP, LLC (the general partner of
Tallgrass Energy Partners, LP)
Date: February 15, 2017
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 Partners, LP (the “Partnership”) on Form 10-K for the year
ended December 31, 2016, 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 MLP 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 MLP GP,
LLC (the general partner of Tallgrass Energy Partners, LP)
Date: February 15, 2017
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 Partners, LP (the “Partnership”) on Form 10-K for the year
ended December 31, 2016, 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 MLP 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 of
Tallgrass MLP GP, LLC (the general partner of
Tallgrass Energy Partners, LP)
Date: February 15, 2017
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.
ENERGY PARTNERS
CORPOR ATE INFORMATION
BOARD OF DIRECTORS
David G. Dehaemers, Jr.
William R. Moler
Jeffrey R. Armstrong
Jeffrey A. Ball
Roy N. Cook
Frank J. Loverro
Stanley de J. Osborne
John T. Raymond
Terrance D. Towner
EXECUTIVE MANAGEMENT
David G. Dehaemers, Jr.
President and Chief Executive Officer
W. R. (Bill) Moler
Executive Vice President &
Chief Operating Officer
Gary J. Brauchle
Executive Vice President &
Chief Financial Officer
Christopher R. Jones
Vice President, General Counsel
& Secretary
PUBLIC HEADQUARTERS
4200 W. 115th Street
Suite 350
Leawood, KS 66211
(913) 928-6012
TALLGRASS ENERGY
4200 W. 115th Street
Suite 350
Leawood, KS 66211
(913) 928-6012
370 Van Gordon Street
Lakewood, CO 80228
(303) 763-2950
INVESTOR RELATIONS
(913) 928-6012
investor.relations@tallgrassenergylp.com
MEDIA RELATIONS
(913) 928-6014
media.relations@tallgrassenergylp.com
TRANSFER AGENT
American Stock Transfer and Trust
TICKER SYMBOL
NYSE:TEP
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2 0 1 6 A N N U A L R E P O R T
4200 W. 115th Street, Suite 350, Leawood, KS 66211 • (913) 928-6012 • www.tallgrassenergy.com
ENERGY PARTNERS