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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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46-1972941
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(State or other Jurisdiction of Incorporation or Organization)
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(IRS Employer Identification Number)
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4200 W. 115th Street, Suite 350
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Leawood, Kansas
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66211
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(Address of Principal Executive Offices)
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(Zip Code)
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Title of each class
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Name of each exchange on which registered
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Common Units Representing Limited Partner Interests
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New York Stock Exchange
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Large accelerated filer
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x
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Accelerated filer
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¨
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Non-accelerated filer
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¨
(Do not check if a smaller reporting company)
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Smaller reporting company
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¨
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Emerging growth company
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¨
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PART
I
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•
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our ability to complete and integrate acquisitions, including the acquisitions discussed in Item 1.—Business,
"Acquisitions;"
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•
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the demand for our services, including crude oil transportation, storage, gathering and terminalling services; natural gas transportation, storage, gathering and processing services; and water business services, as well as our ability to successfully contract or re-contract with our customers;
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large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;
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our ability to successfully implement our business plan;
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changes in general economic conditions;
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competitive conditions in our industry;
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•
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the effects of existing and future laws and governmental regulations;
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•
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actions taken by third-party operators, processors and transporters;
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our ability to complete internal growth projects on time and on budget;
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•
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the price and availability of debt and equity financing;
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•
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the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil, natural gas, natural gas liquids, and other hydrocarbons;
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•
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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;
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competition from the same and alternative energy sources;
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•
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energy efficiency and technology trends;
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operating hazards and other risks incidental to transporting, storing, gathering and terminalling crude oil; transporting, storing, gathering and processing natural gas; and transporting, gathering and disposing of water produced in connection with hydrocarbon exploration and production activities;
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environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
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natural disasters, weather-related delays, casualty losses and other matters beyond our control;
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interest rates;
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labor relations;
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changes in tax laws, regulations and status;
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the effects of future litigation; and
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certain factors discussed elsewhere in this Annual Report.
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Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities;
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•
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Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and
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•
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Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs.
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•
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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;
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•
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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
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•
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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.
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Year Ended December 31,
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2017
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2016
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2015
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Approximate average daily deliveries (Bcf/d)
(1)
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4.3
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3.2
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2.5
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Approximate Capacity
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Total Firm Contracted Capacity
(2)
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Approximate % of Capacity Subscribed under Firm Contracts
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Weighted Average Remaining Firm Contract Life
(3)
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West-to-east
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2.0 Bcf/d
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1.5 Bcf/d
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75
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%
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3 years
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East-to-west
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2.6 Bcf/d
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2.6 Bcf/d
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100
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%
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15 years
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(1)
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Reflects average total daily deliveries for the Rockies Express Pipeline, regardless of flow direction or distance traveled.
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(2)
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Reflects total capacity reserved under long-term firm fee contracts as of
December 31, 2017
. West-to-east firm contracted capacity excludes the 0.2 Bcf/d contracted with Ultra beginning December 1, 2019 as part of the settlement agreement discussed in
Note 17
–
Legal and Environmental Matters
.
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(3)
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Weighted by contracted capacity as of
December 31, 2017
. Weighted average remaining firm contract life of west-to-east contracts excludes the 0.2 Bcf/d contract with Ultra discussed above. After giving effect to the Ultra contract agreement reached in January 2017, the weighted average life of the west-to-east contract lives would be approximately 4 years.
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Year Ended December 31,
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2017
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2016
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2015
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Approximate average daily deliveries (Bcf/d)
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1.2
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1.1
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1.1
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Approximate Number of Miles
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Approximate Capacity
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Total Firm Contracted Capacity
(1)
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Approximate % of Capacity Subscribed under Firm Contracts
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Weighted Average Remaining Firm Contract Life
(2)
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Transportation
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5,106
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2.0 Bcf/d
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1.7 Bcf/d
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83
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%
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4 years
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Storage
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n/a
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15.974 Bcf
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(3)
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11 Bcf
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69
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%
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4 years
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(1)
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Reflects total capacity reserved under long-term firm fee contracts, including backhaul service, as of
December 31, 2017
.
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(2)
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Weighted by contracted capacity as of
December 31, 2017
.
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(3)
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The FERC certificated working gas storage capacity.
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(1)
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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.
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(2)
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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.
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(3)
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Based on the average annual reservation capacity for each such contract's remaining life. The weighted average remaining firm contract life reflects the Continental Resources, Inc. ("Continental Resources") contract extension effective January 1, 2018.
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(4)
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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.
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Approximate Capacity (MMcf/d)
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Approximate Average Volumes (MMcf/d)
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Year Ended December 31,
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2017
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2016
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2015
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Gathering
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75
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37
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(1)
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N/A
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N/A
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Processing
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190
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(2)
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109
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103
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122
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(1)
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Reflects approximate average gathering volumes subsequent to our acquisition of the Douglas Gathering System on June 5, 2017.
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(2)
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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.
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Approximate Capacity Under Contract
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Approximate Current Design Capacity (bbls/d)
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Remaining Contract Life
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Approximate Average Volumes (bbls/d)
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|||||||||
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Year Ended December 31,
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2017
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2016
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2015
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Freshwater
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68
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%
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30,863
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(1)
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3
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69,139
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13,201
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14,579
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Gathering and Disposal
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67
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%
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45,000
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(2)
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7
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31,511
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11,307
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7,951
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(1)
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Represents design capacity at our BNN Western, LLC ("Western") owned facilities. Western also has access to an additional 144,539 bbls/d under supply arrangements, which are not included in the approximate current design capacity.
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(2)
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Represents the combined daily disposal well injection capacity for the 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.
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Approximate Storage Capacity
(bbls) |
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Approximate Storage Capacity Under Contract
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Weighted Average Remaining Contract Life
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3,750,000
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93
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%
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19 years
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•
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Terminals and NatGas.
In January 2017, we acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from Tallgrass Development for total cash consideration of $140 million.
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•
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Additional Membership Interest in Rockies Express.
In March 2017, we acquired an additional 24.99% membership interests in Rockies Express from Tallgrass Development for cash consideration of $400 million.
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•
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Douglas Gathering System.
In June 2017, we acquired 100% of the membership interests in DCP Douglas, LLC (subsequently renamed as Tallgrass Midstream Gathering, LLC) for approximately $128.5 million, subject to working capital adjustments.
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•
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Additional Interests in Deeprock Development.
In July 2017, we acquired an additional 40% membership interest in Deeprock Development from Kinder Morgan Cushing, LLC for cash consideration of approximately $57.2 million, net of cash acquired. We subsequently acquired an additional 9% membership interest in Deeprock Development from Deeprock Energy Resources LLC ("DER") for total consideration valued at approximately $13.1 million, consisting of approximately $6.4 million in cash and the issuance of 128,790 common units (valued at approximately $6.7 million based on the July 20, 2017 closing price of TEP's common units).
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•
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PRB Crude System.
In August 2017, we acquired 100% of the membership interests of Outrigger Powder River Operating, LLC (subsequently renamed as Tallgrass Crude Gathering, LLC, "TCG") for approximately $36 million. As discussed in
Note 20
–
Subsequent Events
, we entered into an agreement in February 2018 with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to form Iron Horse Pipeline, a new joint venture pipeline to transport crude oil from the Powder River Basin. In addition to forming the joint venture, we also agreed to sell to Silver Creek our 100% membership interest in TCG. We expect to close the sale of TCG and the formation of the joint venture in February 2018.
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•
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Deeprock North.
In January 2018, we acquired a 38% membership interest in Deeprock North from Kinder Morgan Deeprock North Holdco, LLC for cash consideration of $19.5 million. Immediately following the acquisition, Deeprock North was merged into Deeprock Development. Subsequent to the acquisition and merger, Terminals owns approximately 60% of the combined entity.
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•
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Pawnee Terminal.
In January 2018, we entered into an agreement to acquire a
51%
membership interest in the Pawnee, Colorado crude oil terminal from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately
$31 million
, subject to working capital adjustments. We expect the transaction to close in the first quarter of 2018, subject to certain closing conditions.
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•
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BNN North Dakota.
In January 2018, we acquired a 100% membership interest in BNN North Dakota for cash consideration of approximately
$95.0 million
, subject to working capital adjustments.
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•
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Additional Interest in Pony Express.
In February 2018, we acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from Tallgrass Development for cash consideration of approximately $60 million, bringing our aggregate membership interest in Pony Express to 100%.
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•
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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;
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•
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our ability to renew or replace expiring long-term firm fee contracts with other long-term firm fee contracts;
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•
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the creditworthiness of our customers, particularly customers who are subject to firm fee contracts;
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•
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our ability to complete and integrate acquisitions;
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•
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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;
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•
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the actual and anticipated future prices, and the volatility thereof, of natural gas, crude oil and other commodities;
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•
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changes in the fees we charge for our services, including firm services and interruptible services;
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•
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our ability to identify, develop, and complete internal growth projects or expansion capital expenditures on favorable terms to improve optimization of our current assets;
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•
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regional, domestic and foreign supply and perceptions of supply of natural gas, crude oil and other hydrocarbons;
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the level of demand and perceptions of demand in end-user markets we directly or indirectly serve;
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•
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applicable laws and regulations affecting our and our customers' business, including the market for natural gas, crude oil, other hydrocarbons and water, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility;
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•
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the effect of worldwide energy conservation measures;
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•
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prevailing economic conditions;
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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;
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•
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the realized pricing impacts on revenues and expenses that are directly related to commodity prices;
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•
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the level of competition from other midstream energy companies in our geographic markets;
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•
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the level of our operating and maintenance costs;
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•
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damage to our assets and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters or acts of terrorism;
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•
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outages in our assets;
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•
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the relationship between natural gas and NGL prices and resulting effect on processing margins; and
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•
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leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise.
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•
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our ability to borrow funds and access capital markets;
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•
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the level, timing and characterization of capital expenditures we make;
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•
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the level of our general and administrative expenses, including reimbursements to our general partner and its affiliates, for services provided to us;
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•
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the cost of pursuing and completing acquisitions and capital expansion projects, if any;
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•
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our debt service requirements and other liabilities;
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•
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fluctuations in our working capital needs;
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•
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restrictions contained in our debt agreements;
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•
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the amount of cash reserves established by our general partner; and
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•
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other business risks affecting our cash levels.
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•
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the level of existing and new competition to provide competing services to our markets;
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•
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the macroeconomic factors affecting crude oil and natural gas economics for our current and potential customers;
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•
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the balance of supply and demand for natural gas, crude oil and other hydrocarbons, on a short-term, seasonal and long-term basis, in the markets we directly and indirectly serve;
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•
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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
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•
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the effects of federal, state or local laws or regulations on the contracting practices of our customers.
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•
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mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
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•
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an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities;
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•
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an inability to successfully integrate the assets or businesses we acquire;
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•
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the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
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•
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the diversion of management's and employees' attention from other business concerns;
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•
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unforeseen difficulties operating in new geographic areas or business lines; and
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•
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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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denial or delay in issuing requisite regulatory approvals and/or permits;
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•
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unplanned increases in the cost of construction materials or labor;
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•
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disruptions in transportation of modular components and/or construction materials;
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•
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severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires, releases) affecting our facilities, or those of vendors and suppliers;
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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
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•
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changes in market conditions impacting long lead-time projects;
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•
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market-related increases in a project's debt or equity financing costs; and
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nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.
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•
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adverse changes in general global economic conditions;
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•
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adverse changes in domestic laws and regulations;
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•
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technological advancements that may drive further increases in production and reduction in costs of developing crude oil and natural gas shale plays;
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•
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the price and availability of other forms of energy, including alternative energy which may benefit from government subsidies;
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•
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adoption of various energy efficiency and conservation measures;
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•
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prices for natural gas, crude oil and NGLs;
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•
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decisions of the members of the Organization of the Petroleum Exporting Countries, or OPEC, regarding price and production controls;
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•
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increased costs to explore for, develop, produce, gather, process and transport natural gas or crude oil;
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•
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weather conditions, seasonal trends and hurricane disruptions;
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the nature and extent of, and changes in, governmental regulation, for example GHG legislation, taxation and hydraulic fracturing;
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•
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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;
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capacity and transportation service into, or out of, our markets; and
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•
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petrochemical demand for NGLs.
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•
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rates, operating terms and conditions of service;
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•
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the form of tariffs governing service;
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•
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the types of services we may offer to our customers;
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•
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the certification and construction of new, or the expansion of existing, facilities;
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•
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the acquisition, extension, disposition or abandonment of facilities;
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customer creditworthiness and credit support requirements;
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•
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the maintenance of accounts and records;
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relationships among affiliated companies involved in certain aspects of the natural gas business;
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•
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depreciation and amortization policies; and
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•
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the initiation and discontinuation of services.
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•
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rates, rules and regulations of service;
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•
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the form of tariffs governing rates and service;
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•
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the maintenance of accounts and records; and
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•
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depreciation and amortization policies.
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•
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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;
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•
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inadvertent damage from construction, vehicles, farm and utility equipment;
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•
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uncontrolled releases of crude oil, natural gas and other hydrocarbons or hazardous materials, including water from hydraulic fracturing;
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leaks, migrations or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;
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•
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outages at our facilities;
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•
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ruptures, fires, leaks and explosions; and
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•
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other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and suspension of operations.
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•
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reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines;
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•
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requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote- controlled shutoff valves on new or rebuilt pipeline facilities;
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•
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requiring operators of pipelines to verify MAOP and report exceedances within five days; and
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•
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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.
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•
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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;
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•
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Requires PHMSA, in consultation with other federal agencies, to issue minimum safety standards for underground natural gas storage facilities within two years;
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•
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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;
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•
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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
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•
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Requires PHMSA to publish updates on its website every 90 days on the status of an outstanding final rule required by a statutory mandate.
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•
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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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•
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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;
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•
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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;
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•
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RCRA and analogous state and local laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from our facilities;
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•
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The SDWA, which ensures the quality of the nation's public drinking water through adoption of drinking water standards and controls the waste fluids from disposal wells into below-ground formations;
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•
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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;
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•
|
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;
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•
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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;
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•
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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;
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•
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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;"
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•
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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
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•
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National Historic Preservation Act, or NHPA, and analogous state and local laws, which are intended to preserve and protect historical and archeological sites.
|
•
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incur or guarantee additional indebtedness;
|
•
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redeem or repurchase units or make distributions under certain circumstances;
|
•
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make certain investments and acquisitions;
|
•
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incur certain liens or permit them to exist;
|
•
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enter into certain types of transactions with affiliates;
|
•
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merge or consolidate with another company; and
|
•
|
transfer, sell or otherwise dispose of assets.
|
•
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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;
|
•
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we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
|
•
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our flexibility in responding to changing business and economic conditions may be limited.
|
Year
|
|
Scheduled Maturities
|
||
2018
|
|
$
|
550.0
|
|
2019
|
|
525.0
|
|
|
2020
|
|
750.0
|
|
|
Thereafter
|
|
750.0
|
|
•
|
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.
|
•
|
incurring secured indebtedness;
|
•
|
entering into mergers, consolidations and sales of assets;
|
•
|
granting liens;
|
•
|
entering into transactions with affiliates; and
|
•
|
making restricted payments.
|
•
|
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 Holdings' obligation to offer us certain assets (if Tallgrass Development Holdings decides to sell such assets to a non-affiliate) 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 TEGP Management and may owe fiduciary duties to Tallgrass Energy Holdings and the members of Tallgrass Energy Holdings. Accordingly, these officers will devote significant time to the business of Tallgrass Energy Holdings and TEGP Management.
|
•
|
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.
|
•
|
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 Energy Holdings 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 Holdings' 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.
|
•
|
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.
|
•
|
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
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
Quarter Ended
|
|
High
|
|
Low
|
|
Distribution per Common Unit
|
||||||
December 31, 2017
|
|
$
|
48.94
|
|
|
$
|
41.13
|
|
|
$
|
0.9650
|
|
September 30, 2017
|
|
52.84
|
|
|
44.37
|
|
|
0.9450
|
|
|||
June 30, 2017
|
|
54.21
|
|
|
45.53
|
|
|
0.9250
|
|
|||
March 31, 2017
|
|
55.50
|
|
|
46.91
|
|
|
0.8350
|
|
|||
December 31, 2016
|
|
48.86
|
|
|
42.59
|
|
|
0.8150
|
|
|||
September 30, 2016
|
|
49.79
|
|
|
43.19
|
|
|
0.7950
|
|
|||
June 30, 2016
|
|
50.78
|
|
|
35.62
|
|
|
0.7550
|
|
|||
March 31, 2016
|
|
42.35
|
|
|
25.82
|
|
|
0.7050
|
|
•
|
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.
|
|
Year Ended December 31,
|
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
||||||||||
|
(in thousands, except per unit amounts)
|
|||||||||||||||||||
Statement of operations data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenue
|
$
|
655,898
|
|
|
$
|
611,662
|
|
|
$
|
542,661
|
|
|
$
|
377,313
|
|
|
$
|
295,873
|
|
|
Operating income
|
$
|
274,087
|
|
|
$
|
260,614
|
|
|
$
|
207,513
|
|
|
$
|
58,970
|
|
|
$
|
39,346
|
|
|
Equity in earnings of unconsolidated investments
(1)
|
$
|
237,110
|
|
|
$
|
54,531
|
|
|
$
|
2,759
|
|
|
$
|
1,617
|
|
|
$
|
—
|
|
|
Net income
|
$
|
440,489
|
|
|
$
|
274,889
|
|
|
$
|
197,171
|
|
|
$
|
65,786
|
|
|
$
|
12,971
|
|
|
Net income attributable to partners
|
$
|
433,990
|
|
|
$
|
270,524
|
|
|
$
|
172,903
|
|
|
$
|
77,138
|
|
|
$
|
15,094
|
|
|
Net income available to common unitholders
|
$
|
286,167
|
|
|
$
|
161,064
|
|
|
$
|
114,068
|
|
|
$
|
61,774
|
|
|
$
|
6,991
|
|
(2)
|
Net income per limited partner unit - basic
|
$
|
3.93
|
|
|
$
|
2.26
|
|
|
$
|
1.95
|
|
|
$
|
1.39
|
|
|
$
|
0.17
|
|
(2)
|
Net income per limited partner unit - diluted
|
$
|
3.90
|
|
|
$
|
2.23
|
|
|
$
|
1.91
|
|
|
$
|
1.36
|
|
|
$
|
0.17
|
|
(2)
|
Balance sheet data (at end of period):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Property, plant and equipment, net
|
$
|
2,394,337
|
|
|
$
|
2,079,232
|
|
|
$
|
2,079,567
|
|
|
$
|
1,853,081
|
|
|
$
|
1,116,806
|
|
|
Unconsolidated investments
(1)
|
$
|
909,531
|
|
|
$
|
475,625
|
|
|
$
|
13,565
|
|
|
$
|
15,071
|
|
|
$
|
1,255
|
|
|
Total assets
|
$
|
3,977,353
|
|
|
$
|
3,102,213
|
|
|
$
|
2,634,049
|
|
|
$
|
2,476,599
|
|
|
$
|
1,631,879
|
|
|
Long-term debt, net
|
$
|
2,146,993
|
|
|
$
|
1,407,981
|
|
|
$
|
753,000
|
|
|
$
|
559,000
|
|
|
$
|
135,000
|
|
|
Other:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Distributions declared per common unit
|
$
|
3.6700
|
|
|
$
|
3.0700
|
|
|
$
|
2.3400
|
|
|
$
|
1.6000
|
|
|
$
|
0.7547
|
|
|
(1)
|
For more information see
Note 8
–
Investments in Unconsolidated Affiliates
.
|
(2)
|
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.
|
•
|
Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities;
|
•
|
Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and
|
•
|
Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs.
|
•
|
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.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Reconciliation of Adjusted EBITDA to Net Income
|
|
|
|
|
|
||||||
Net income attributable to partners
|
$
|
433,990
|
|
|
$
|
270,524
|
|
|
$
|
172,903
|
|
Add:
|
|
|
|
|
|
||||||
Interest expense, net of noncontrolling interest
|
83,542
|
|
|
40,688
|
|
|
15,517
|
|
|||
Depreciation and amortization expense, net of noncontrolling interest
|
92,455
|
|
|
88,122
|
|
|
77,111
|
|
|||
Distributions from unconsolidated investments
|
306,626
|
|
|
78,568
|
|
|
4,648
|
|
|||
Non-cash compensation expense
(1)
|
8,660
|
|
|
5,780
|
|
|
5,103
|
|
|||
(Gain) loss from disposal of assets, net of noncontrolling interest
|
(654
|
)
|
|
1,849
|
|
|
4,795
|
|
|||
Non-cash loss related to derivative instruments, net of noncontrolling interest
|
226
|
|
|
1,547
|
|
|
—
|
|
|||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
226
|
|
|||
Less:
|
|
|
|
|
|
||||||
Equity in earnings of unconsolidated investments
|
(237,110
|
)
|
|
(54,531
|
)
|
|
(2,759
|
)
|
|||
Gain on remeasurement of unconsolidated investment
|
(9,728
|
)
|
|
—
|
|
|
—
|
|
|||
Non-cash loss allocated to noncontrolling interest
|
—
|
|
|
—
|
|
|
(9,377
|
)
|
|||
Adjusted EBITDA
|
$
|
678,007
|
|
|
$
|
432,547
|
|
|
$
|
268,167
|
|
Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Cash Provided by Operating Activities
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
$
|
579,061
|
|
|
$
|
419,583
|
|
|
$
|
303,653
|
|
Add:
|
|
|
|
|
|
||||||
Interest expense, net of noncontrolling interest
|
83,542
|
|
|
40,688
|
|
|
15,517
|
|
|||
Other, including changes in operating working capital
|
15,404
|
|
|
(27,724
|
)
|
|
(51,003
|
)
|
|||
Adjusted EBITDA
|
$
|
678,007
|
|
|
$
|
432,547
|
|
|
$
|
268,167
|
|
Add:
|
|
|
|
|
|
||||||
Deficiency payments received, net
|
27,182
|
|
|
33,496
|
|
|
16,511
|
|
|||
Less:
|
|
|
|
|
|
||||||
Cash interest cost
|
(79,081
|
)
|
|
(37,110
|
)
|
|
(13,746
|
)
|
|||
Maintenance capital expenditures, net
|
(14,822
|
)
|
|
(11,323
|
)
|
|
(12,123
|
)
|
|||
Distributions to noncontrolling interest in excess of earnings
|
—
|
|
|
—
|
|
|
(22,479
|
)
|
|||
Cash flow attributable to predecessor operations
|
—
|
|
|
(9,063
|
)
|
|
(15,828
|
)
|
|||
Distributable Cash Flow
|
$
|
611,286
|
|
|
$
|
408,547
|
|
|
$
|
220,502
|
|
(1)
|
Represents TEP's portion of non-cash compensation expense related to Equity Participation Units, excluding amounts allocated to TD, as discussed in
Note 15
–
Equity-Based Compensation
.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Reconciliation of Adjusted EBITDA to Operating Income in the Natural Gas Transportation Segment
(1)
|
|
|
|
|
|
||||||
Operating income
|
$
|
67,434
|
|
|
$
|
56,135
|
|
|
$
|
48,133
|
|
Add:
|
|
|
|
|
|
||||||
Depreciation and amortization expense
|
19,181
|
|
|
20,976
|
|
|
22,927
|
|
|||
Distributions from unconsolidated investment
|
304,663
|
|
|
75,900
|
|
|
—
|
|
|||
Other income, net
|
1,232
|
|
|
1,723
|
|
|
2,639
|
|
|||
Less:
|
|
|
|
|
|
||||||
Non-cash (gain) loss related to derivative instruments
|
(116
|
)
|
|
116
|
|
|
—
|
|
|||
Segment Adjusted EBITDA
|
$
|
392,394
|
|
|
$
|
154,850
|
|
|
$
|
73,699
|
|
Reconciliation of Adjusted EBITDA to Operating Income in the Crude Oil Transportation Segment
(1)
|
|
|
|
|
|
||||||
Operating income
|
$
|
190,170
|
|
|
$
|
215,784
|
|
|
$
|
159,467
|
|
Add:
|
|
|
|
|
|
||||||
Depreciation and amortization expense, net of noncontrolling interest
|
57,172
|
|
|
52,464
|
|
|
39,359
|
|
|||
Less:
|
|
|
|
|
|
||||||
Adjusted EBITDA attributable to noncontrolling interests
|
(3,804
|
)
|
|
(4,288
|
)
|
|
(24,245
|
)
|
|||
Non-cash (gain) loss related to derivative instruments, net of noncontrolling interest
|
(432
|
)
|
|
431
|
|
|
—
|
|
|||
Non-cash loss allocated to noncontrolling interest
|
—
|
|
|
—
|
|
|
(9,377
|
)
|
|||
Segment Adjusted EBITDA
|
$
|
243,106
|
|
|
$
|
264,391
|
|
|
$
|
165,204
|
|
Reconciliation of Adjusted EBITDA to Operating Income (Loss) in the Gathering, Processing & Terminalling Segment
(1)
|
|
|
|
|
|
||||||
Operating income (loss)
|
$
|
33,453
|
|
|
$
|
(903
|
)
|
|
$
|
7,995
|
|
Add:
|
|
|
|
|
|
||||||
Depreciation and amortization expense, net of noncontrolling interest
|
16,102
|
|
|
14,682
|
|
|
14,825
|
|
|||
Non-cash loss (gain) related to derivative instruments
|
2,659
|
|
|
(291
|
)
|
|
—
|
|
|||
Distributions from unconsolidated investment
|
1,963
|
|
|
2,668
|
|
|
4,648
|
|
|||
Other income
|
142
|
|
|
—
|
|
|
—
|
|
|||
Less:
|
|
|
|
|
|
||||||
Adjusted EBITDA attributable to noncontrolling interests
|
(2,695
|
)
|
|
(77
|
)
|
|
(20
|
)
|
|||
(Gain) loss from disposal of assets, net of noncontrolling interest
|
(654
|
)
|
|
1,849
|
|
|
4,795
|
|
|||
Segment Adjusted EBITDA
|
$
|
50,970
|
|
|
$
|
17,928
|
|
|
$
|
32,243
|
|
Total Segment Adjusted EBITDA
|
$
|
686,470
|
|
|
$
|
437,169
|
|
|
$
|
271,146
|
|
Corporate general and administrative costs
|
(8,463
|
)
|
|
(4,622
|
)
|
|
(2,979
|
)
|
|||
Total Adjusted EBITDA
|
$
|
678,007
|
|
|
$
|
432,547
|
|
|
$
|
268,167
|
|
(1)
|
Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for the Natural Gas Transportation, Crude Oil Transportation, and Gathering, Processing & Terminalling segments. For reconciliations to the consolidated financial data, see
Note 18
–
Reportable Segments
.
|
|
Year Ended December 31,
|
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
|
(in thousands, except operating data)
|
|||||||
Natural Gas Transportation Segment:
|
|
|
|
|
|
|||
Gas transportation average firm contracted volumes (MMcf/d)
(1)
|
1,711
|
|
|
1,627
|
|
|
1,679
|
|
Crude Oil Transportation Segment:
|
|
|
|
|
|
|||
Crude oil transportation average contracted capacity (Bbls/d)
|
301,936
|
|
|
295,435
|
|
|
252,374
|
|
Crude oil transportation average throughput (Bbls/d)
(2)
|
267,734
|
|
|
285,507
|
|
|
236,256
|
|
Gathering, Processing & Terminalling Segment:
|
|
|
|
|
|
|
|
|
Natural gas processing inlet volumes (MMcf/d)
|
109
|
|
|
103
|
|
|
122
|
|
Freshwater average volumes (Bbls/d)
|
69,139
|
|
|
13,201
|
|
|
14,579
|
|
Produced water gathering and disposal average volumes (Bbls/d)
|
31,511
|
|
|
11,307
|
|
|
7,951
|
|
(1)
|
Volumes transported under firm fee contracts, excluding Rockies Express.
|
(2)
|
Approximate average daily throughput for the year ended December 31, 2015 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.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands, except operating data)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Crude oil transportation services
|
$
|
345,733
|
|
|
$
|
374,949
|
|
|
$
|
300,436
|
|
Natural gas transportation services
|
122,364
|
|
|
119,962
|
|
|
119,895
|
|
|||
Sales of natural gas, NGLs, and crude oil
|
108,503
|
|
|
77,123
|
|
|
82,133
|
|
|||
Processing and other revenues
|
79,298
|
|
|
39,628
|
|
|
40,197
|
|
|||
Total Revenues
|
655,898
|
|
|
611,662
|
|
|
542,661
|
|
|||
Operating Costs and Expenses:
|
|
|
|
|
|
||||||
Cost of sales
|
91,213
|
|
|
71,650
|
|
|
75,285
|
|
|||
Cost of transportation services
|
46,200
|
|
|
47,669
|
|
|
46,840
|
|
|||
Operations and maintenance
|
62,069
|
|
|
55,070
|
|
|
50,823
|
|
|||
Depreciation and amortization
|
90,800
|
|
|
86,247
|
|
|
84,258
|
|
|||
General and administrative
|
63,296
|
|
|
55,102
|
|
|
51,351
|
|
|||
Taxes, other than income taxes
|
28,832
|
|
|
25,400
|
|
|
21,796
|
|
|||
Contract termination
|
—
|
|
|
8,061
|
|
|
—
|
|
|||
(Gain) loss on disposal of assets
|
(599
|
)
|
|
1,849
|
|
|
4,795
|
|
|||
Total Operating Costs and Expenses
|
381,811
|
|
|
351,048
|
|
|
335,148
|
|
|||
Operating Income
|
274,087
|
|
|
260,614
|
|
|
207,513
|
|
|||
Other Income (Expense):
|
|
|
|
|
|
||||||
Interest expense, net
|
(83,542
|
)
|
|
(40,688
|
)
|
|
(15,514
|
)
|
|||
Unrealized gain (loss) on derivative instrument
|
1,885
|
|
|
(1,291
|
)
|
|
—
|
|
|||
Equity in earnings of unconsolidated investments
|
237,110
|
|
|
54,531
|
|
|
2,759
|
|
|||
Gain on remeasurement of unconsolidated investment
|
9,728
|
|
|
—
|
|
|
—
|
|
|||
Other income, net
|
1,221
|
|
|
1,723
|
|
|
2,413
|
|
|||
Total Other Income (Expense)
|
166,402
|
|
|
14,275
|
|
|
(10,342
|
)
|
|||
Net income
|
440,489
|
|
|
274,889
|
|
|
197,171
|
|
|||
Net income attributable to noncontrolling interests
|
(6,499
|
)
|
|
(4,365
|
)
|
|
(24,268
|
)
|
|||
Net income attributable to partners
|
$
|
433,990
|
|
|
$
|
270,524
|
|
|
$
|
172,903
|
|
Other Financial Data:
|
|
|
|
|
|
||||||
Adjusted EBITDA
(1)
|
$
|
678,007
|
|
|
$
|
432,547
|
|
|
$
|
268,167
|
|
(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.
|
Segment Financial Data – Natural Gas Transportation
(1)
|
Year Ended December 31,
|
||||||||||
2017
|
|
2016
|
|
2015
|
|||||||
|
(in thousands)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Natural gas transportation services
|
$
|
129,058
|
|
|
$
|
125,603
|
|
|
$
|
125,279
|
|
Sales of natural gas, NGLs, and crude oil
|
3,412
|
|
|
3,241
|
|
|
6,346
|
|
|||
Processing and other revenues
|
8,551
|
|
|
6,253
|
|
|
6,363
|
|
|||
Total revenues
|
141,021
|
|
|
135,097
|
|
|
137,988
|
|
|||
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales
|
2,767
|
|
|
3,804
|
|
|
6,342
|
|
|||
Cost of transportation services
|
2,852
|
|
|
5,051
|
|
|
10,927
|
|
|||
Operations and maintenance
|
28,910
|
|
|
28,458
|
|
|
27,767
|
|
|||
Depreciation and amortization
|
19,180
|
|
|
20,976
|
|
|
22,927
|
|
|||
General and administrative
|
15,385
|
|
|
16,335
|
|
|
17,052
|
|
|||
Taxes, other than income taxes
|
4,493
|
|
|
4,338
|
|
|
4,840
|
|
|||
Total operating costs and expenses
|
73,587
|
|
|
78,962
|
|
|
89,855
|
|
|||
Operating income
|
$
|
67,434
|
|
|
$
|
56,135
|
|
|
$
|
48,133
|
|
(1)
|
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see
Note 18
–
Reportable Segments
.
|
|
Year Ended December 31,
|
||||||||||
Segment Financial Data – Crude Oil Transportation
(1)
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Crude oil transportation services
|
$
|
353,395
|
|
|
$
|
374,949
|
|
|
$
|
300,436
|
|
Sales of natural gas, NGLs, and crude oil
|
11,179
|
|
|
5,554
|
|
|
3,791
|
|
|||
Total revenues
|
364,574
|
|
|
380,503
|
|
|
304,227
|
|
|||
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales
|
9,680
|
|
|
4,728
|
|
|
4,257
|
|
|||
Cost of transportation services
|
57,284
|
|
|
55,519
|
|
|
47,367
|
|
|||
Operations and maintenance
|
11,838
|
|
|
13,075
|
|
|
8,795
|
|
|||
Depreciation and amortization
|
52,364
|
|
|
51,362
|
|
|
47,168
|
|
|||
General and administrative
|
20,906
|
|
|
20,650
|
|
|
20,620
|
|
|||
Taxes, other than income taxes
|
22,332
|
|
|
19,385
|
|
|
16,553
|
|
|||
Total operating costs and expenses
|
174,404
|
|
|
164,719
|
|
|
144,760
|
|
|||
Operating income
|
$
|
190,170
|
|
|
$
|
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 18
–
Reportable Segments
.
|
(1)
|
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see
Note 18
–
Reportable Segments
.
|
•
|
cash generated from our operations;
|
•
|
borrowing capacity available under our revolving credit facility; and
|
•
|
future issuances of additional partnership units and/or debt securities.
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Cash on hand
|
$
|
1,809
|
|
|
$
|
1,873
|
|
|
|
|
|
||||
Total capacity under the revolving credit facility
|
1,750,000
|
|
|
1,750,000
|
|
||
Less: Outstanding borrowings under the revolving credit facility
(1)
|
(661,000
|
)
|
|
(1,015,000
|
)
|
||
Less: Letters of credit issued under the revolving credit facility
|
(94
|
)
|
|
—
|
|
||
Available capacity under the revolving credit facility
|
1,088,906
|
|
|
735,000
|
|
||
Total liquidity
|
$
|
1,090,715
|
|
|
$
|
736,873
|
|
(1)
|
As of February 12, 2018, outstanding borrowings under our revolving credit facility were approximately
$0.9 billion
.
|
•
|
an increase
in accounts payable of
$74.8 million
primarily due to crude oil purchases at Stanchion, as well as increased expansion capital accruals at Pony Express and Terminals, and increased settlement volumes at TMID as a result of the Douglas Gathering acquisition;
|
•
|
an increase
in deferred revenue of
$27.7 million
primarily from deficiency payments collected by Pony Express;
|
•
|
an increase
in accrued liabilities of
$19.0 million
primarily due to an increase in interest accrued at December 31, 2017 compared to December 31, 2016 due to increased borrowings and higher interest rates on the 2024 and 2028 Notes issued during 2017 compared to borrowings under the revolving credit facility; and
|
•
|
a decrease
in derivative assets at fair value of
$11.0 million
as we exercised the remainder of the call option granted by TD.
|
•
|
an increase
in accounts receivable of
$60.4 million
primarily due to crude oil sales at Stanchion; and
|
•
|
an increase
in inventories of
$8.5 million
primarily due to crude oil purchases at Stanchion.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Net cash provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
$
|
579,061
|
|
|
$
|
419,583
|
|
|
$
|
303,653
|
|
Investing activities
|
$
|
(898,541
|
)
|
|
$
|
(595,539
|
)
|
|
$
|
(899,432
|
)
|
Financing activities
|
$
|
319,416
|
|
|
$
|
176,218
|
|
|
$
|
596,523
|
|
•
|
cash outflows of
$400.0 million
for the acquisition of an additional 24.99% membership interest in Rockies Express;
|
•
|
capital expenditures of
$145.1 million
, primarily due to spending on an additional freshwater connection at Water Solutions, a connection to a refinery complex on the Pony Express System, a 55-mile extension on the Pony Express system, and remediation digs on the Pony Express System as discussed in
Note 17
–
Legal and Environmental Matters
;
|
•
|
cash outflows of
$140.0 million
for the acquisition of Terminals and NatGas;
|
•
|
cash outflows of
$128.5 million
for the acquisition of the Douglas Gathering System;
|
•
|
cash outflows of
$57.2 million
for the acquisition of an additional 40% membership interest in Deeprock Development;
|
•
|
contributions to unconsolidated investments in the amount of
$45.9 million
, primarily to fund remaining costs associated with the Zone 3 Capacity Enhancement project at Rockies Express; and
|
•
|
cash outflows of
$36.0 million
for the acquisition of the PRB Crude System.
|
•
|
cash outflows of
$436.0 million
for the acquisition of a 25% membership interest in Rockies Express;
|
•
|
capital expenditures of
$84.5 million
, primarily due to post in-service spending on Pony Express System projects, the Pipeline Integrity Management Program at Trailblazer, and costs associated with construction of the Buckingham Terminal;
|
•
|
cash outflows of
$49.1 million
for a portion of the acquisition of an additional 31.3% membership interest in Pony Express, the remainder of which is classified as a financing activity as discussed below; and
|
•
|
contributions to unconsolidated investments in the amount of
$50.1 million
, primarily to fund costs associated with the Zone 3 Capacity Enhancement project at Rockies Express.
|
•
|
proceeds from the issuance of
$1.1 billion
in aggregate principal amount of 2024 and 2028 Notes; and
|
•
|
net cash proceeds of
$112.4 million
from the issuance of
2,341,061
common units under our Equity Distribution Agreements.
|
•
|
distributions to unitholders of
$392.9 million
;
|
•
|
net repayments under the revolving credit facility of
$354.0 million
;
|
•
|
$72.4 million
for the exercise of the remainder of the call option granted by TD covering
1,703,094
common units;
|
•
|
$35.3 million
for the
736,262
common units repurchased from TD; and
|
•
|
deferred financing costs of
$22.3 million
from the issuance of the 2024 and 2028 Notes and the amendment to TEP's revolving credit facility.
|
•
|
proceeds from the issuance of
$400.0 million
in aggregate principal amount of 2024 Notes;
|
•
|
net cash proceeds of
$337.7 million
from the issuance of 7,696,708 common units under the Equity Distribution Agreements;
|
•
|
net borrowings under the revolving credit facility of
$262.0 million
;
|
•
|
net cash proceeds of
$90.0 million
from the issuance of 2,416,987 common units representing limited partnership interests in a private placement transaction; and
|
•
|
contributions from TD of $17.9 million, which consisted of contributions from TD to TEP in order to indemnify TEP for any out of pocket costs incurred between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, as discussed further in
Note 17
–
Legal and Environmental Matters
.
|
•
|
$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.
|
•
|
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;
|
•
|
capital expenditures of
$120.7 million
, primarily due to construction of the Pony Express System, including the lateral in Northeast Colorado, and costs associated with construction of the Sterling Terminal; and
|
•
|
the cash outflow of
$75.0 million
for the acquisition of Western.
|
•
|
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; and
|
•
|
distributions to noncontrolling interests of $25.1 million, primarily driven by distributions to TD from Pony Express.
|
•
|
maintenance capital expenditures, which are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements; and
|
•
|
expansion capital expenditures, which are cash expenditures we expect will increase our operating income or operating capacity over the long-term. Expansion capital expenditures include acquisitions or capital improvements (such as additions to or improvements on the capital assets owned, or acquisition or construction of new capital assets).
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Maintenance capital expenditures
|
$
|
14,822
|
|
|
$
|
11,323
|
|
|
$
|
12,123
|
|
Expansion capital expenditures
|
135,604
|
|
|
44,348
|
|
|
72,190
|
|
|||
Total capital expenditures incurred
|
$
|
150,426
|
|
|
$
|
55,671
|
|
|
$
|
84,313
|
|
|
|
Payments Due By Period
|
||||||||||||||||||
Contractual Obligations
|
|
Total
|
|
Less Than 1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than 5 Years
|
||||||||||
|
|
(in thousands)
|
||||||||||||||||||
Debt obligations
(1)
|
|
$
|
2,161,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
661,000
|
|
|
$
|
1,500,000
|
|
Interest on debt obligations
(2)
|
|
802,025
|
|
|
107,629
|
|
|
215,327
|
|
|
200,631
|
|
|
278,438
|
|
|||||
Operating lease and service contract obligations
(3)
|
|
2,383
|
|
|
506
|
|
|
945
|
|
|
464
|
|
|
468
|
|
|||||
Land site lease and right-of-way
(4)
|
|
7,923
|
|
|
720
|
|
|
1,820
|
|
|
1,457
|
|
|
3,926
|
|
|||||
Other purchase commitments
(5)
|
|
23,594
|
|
|
19,345
|
|
|
4,161
|
|
|
40
|
|
|
48
|
|
|||||
Total
|
|
$
|
2,996,925
|
|
|
$
|
128,200
|
|
|
$
|
222,253
|
|
|
$
|
863,592
|
|
|
$
|
1,782,880
|
|
(1)
|
Debt obligations at
December 31, 2017
consisted of borrowings under the revolving credit facility and the 2024 and 2028 Notes. For additional information, see
Note 10
–
Long-term Debt
.
|
(2)
|
Interest on debt obligations is estimated using current borrowings and interest rates as of
December 31, 2017
. For additional information, see
Note 10
–
Long-term Debt
.
|
(3)
|
Operating leases and service contracts consist of leases for office space and equipment. For additional information, see
Note 12
–
Commitments & Contingent Liabilities
.
|
(4)
|
Land site lease and right-of-way contracts consist of payments to landowners, primarily in our Crude Oil Transportation and Natural Gas Transportation segments. For additional information, see
Note 12
–
Commitments & Contingent Liabilities
.
|
(5)
|
Other purchase commitments primarily relate to planned non-reimbursable capital expenditures and operating and maintenance expenditures.
|
Description
|
|
Judgments and Uncertainties
|
|
Effect if Actual Results Differ from Assumptions
|
Impairment of Goodwill
|
||||
We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.
|
|
We 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.
|
|
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 2017 using the methodology described herein, and determined there was no impairment.
|
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.
|
|
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.
|
|
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 commodity forward price curves on our derivative instruments at December 31, 2017.
|
|
Natural Gas Transportation
|
|
Crude Oil Transportation
|
|
Gathering, Processing & Terminalling
|
|
Corporate & Other
|
|
Consolidated
|
|||||
Firm fee
|
55
|
%
|
|
35
|
%
|
|
5
|
%
|
|
—
|
%
|
|
95
|
%
|
Volumetric fee
|
<1%
|
|
|
1
|
%
|
|
2
|
%
|
|
—
|
%
|
|
3
|
%
|
Commodity exposed
|
<1%
|
|
|
<1%
|
|
|
1
|
%
|
|
—
|
%
|
|
1
|
%
|
Other
|
2
|
%
|
|
—
|
%
|
|
—
|
%
|
|
(1
|
)%
|
|
1
|
%
|
Total
|
57
|
%
|
|
36
|
%
|
|
8
|
%
|
|
(1
|
)%
|
|
100
|
%
|
|
Fair Value
|
|
Effect of 10% Price Increase
|
|
Effect of 10% Price Decrease
|
||||||
|
(in thousands)
|
||||||||||
Crude oil derivative contracts
(1)
|
$
|
(2,368
|
)
|
|
$
|
(2,151
|
)
|
|
$
|
2,151
|
|
(1)
|
Represents the forward sale of
356,000
barrels of crude oil by our Gathering, Processing & Terminalling segment which will settle throughout the first quarter of 2018.
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
ASSETS
|
|
||||||
Current Assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
1,809
|
|
|
$
|
1,873
|
|
Accounts receivable, net
|
119,955
|
|
|
59,536
|
|
||
Gas imbalances
|
1,990
|
|
|
1,597
|
|
||
Inventories
|
21,609
|
|
|
13,093
|
|
||
Derivative assets
|
—
|
|
|
10,967
|
|
||
Prepayments and other current assets
|
11,175
|
|
|
7,628
|
|
||
Total Current Assets
|
156,538
|
|
|
94,694
|
|
||
Property, plant and equipment, net
|
2,394,337
|
|
|
2,079,232
|
|
||
Goodwill
|
404,838
|
|
|
343,288
|
|
||
Intangible assets, net
|
97,731
|
|
|
93,522
|
|
||
Unconsolidated investments
|
909,531
|
|
|
475,625
|
|
||
Deferred financing costs, net
|
11,684
|
|
|
4,815
|
|
||
Deferred charges and other assets
|
2,694
|
|
|
11,037
|
|
||
Total Assets
|
$
|
3,977,353
|
|
|
$
|
3,102,213
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
98,882
|
|
|
$
|
24,122
|
|
Accounts payable to related parties
|
5,461
|
|
|
5,935
|
|
||
Gas imbalances
|
1,663
|
|
|
1,239
|
|
||
Derivative liabilities
|
2,368
|
|
|
556
|
|
||
Accrued taxes
|
19,272
|
|
|
16,996
|
|
||
Accrued liabilities
|
35,659
|
|
|
16,702
|
|
||
Deferred revenue
|
88,471
|
|
|
60,757
|
|
||
Other current liabilities
|
7,171
|
|
|
6,446
|
|
||
Total Current Liabilities
|
258,947
|
|
|
132,753
|
|
||
Long-term debt, net
|
2,146,993
|
|
|
1,407,981
|
|
||
Other long-term liabilities and deferred credits
|
18,965
|
|
|
7,063
|
|
||
Total Long-term Liabilities
|
2,165,958
|
|
|
1,415,044
|
|
||
Commitments and Contingencies
|
|
|
|
||||
Equity:
|
|
|
|
||||
Predecessor Equity
|
—
|
|
|
82,295
|
|
||
Limited partners (73,199,753 and 72,485,954 common units issued and outstanding at December 31, 2017 and 2016, respectively)
|
2,109,316
|
|
|
2,070,495
|
|
||
General partner (834,391 units issued and outstanding at December 31, 2017 and 2016)
|
(625,537
|
)
|
|
(632,339
|
)
|
||
Total Partners' Equity
|
1,483,779
|
|
|
1,520,451
|
|
||
Noncontrolling interests
|
68,669
|
|
|
33,965
|
|
||
Total Equity
|
1,552,448
|
|
|
1,554,416
|
|
||
Total Liabilities and Equity
|
$
|
3,977,353
|
|
|
$
|
3,102,213
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands, except per unit amounts)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Crude oil transportation services
|
$
|
345,733
|
|
|
$
|
374,949
|
|
|
$
|
300,436
|
|
Natural gas transportation services
|
122,364
|
|
|
119,962
|
|
|
119,895
|
|
|||
Sales of natural gas, NGLs, and crude oil
|
108,503
|
|
|
77,123
|
|
|
82,133
|
|
|||
Processing and other revenues
|
79,298
|
|
|
39,628
|
|
|
40,197
|
|
|||
Total Revenues
|
655,898
|
|
|
611,662
|
|
|
542,661
|
|
|||
Operating Costs and Expenses:
|
|
|
|
|
|
||||||
Cost of sales
|
91,213
|
|
|
71,650
|
|
|
75,285
|
|
|||
Cost of transportation services
|
46,200
|
|
|
47,669
|
|
|
46,840
|
|
|||
Operations and maintenance
|
62,069
|
|
|
55,070
|
|
|
50,823
|
|
|||
Depreciation and amortization
|
90,800
|
|
|
86,247
|
|
|
84,258
|
|
|||
General and administrative
|
63,296
|
|
|
55,102
|
|
|
51,351
|
|
|||
Taxes, other than income taxes
|
28,832
|
|
|
25,400
|
|
|
21,796
|
|
|||
Contract termination
|
—
|
|
|
8,061
|
|
|
—
|
|
|||
(Gain) loss on disposal of assets
|
(599
|
)
|
|
1,849
|
|
|
4,795
|
|
|||
Total Operating Costs and Expenses
|
381,811
|
|
|
351,048
|
|
|
335,148
|
|
|||
Operating Income
|
274,087
|
|
|
260,614
|
|
|
207,513
|
|
|||
Other Income (Expense):
|
|
|
|
|
|
||||||
Interest expense, net
|
(83,542
|
)
|
|
(40,688
|
)
|
|
(15,514
|
)
|
|||
Unrealized gain (loss) on derivative instrument
|
1,885
|
|
|
(1,291
|
)
|
|
—
|
|
|||
Equity in earnings of unconsolidated investments
|
237,110
|
|
|
54,531
|
|
|
2,759
|
|
|||
Gain on remeasurement of unconsolidated investment
|
9,728
|
|
|
—
|
|
|
—
|
|
|||
Other income, net
|
1,221
|
|
|
1,723
|
|
|
2,413
|
|
|||
Total Other Income (Expense)
|
166,402
|
|
|
14,275
|
|
|
(10,342
|
)
|
|||
Net income
|
440,489
|
|
|
274,889
|
|
|
197,171
|
|
|||
Net income attributable to noncontrolling interests
|
(6,499
|
)
|
|
(4,365
|
)
|
|
(24,268
|
)
|
|||
Net income attributable to partners
|
$
|
433,990
|
|
|
$
|
270,524
|
|
|
$
|
172,903
|
|
Allocation of income to the limited partners:
|
|
|
|
|
|
||||||
Net income attributable to partners
|
$
|
433,990
|
|
|
$
|
270,524
|
|
|
$
|
172,903
|
|
Predecessor operations interest in net income
|
—
|
|
|
(6,995
|
)
|
|
(12,357
|
)
|
|||
General partner interest in net income
|
(147,823
|
)
|
|
(102,465
|
)
|
|
(46,478
|
)
|
|||
Net income available to common unitholders
|
286,167
|
|
|
161,064
|
|
|
114,068
|
|
|||
Basic net income per common unit
|
$
|
3.93
|
|
|
$
|
2.26
|
|
|
$
|
1.95
|
|
Diluted net income per common unit
|
$
|
3.90
|
|
|
$
|
2.23
|
|
|
$
|
1.91
|
|
Basic average number of common units outstanding
|
72,876
|
|
|
71,150
|
|
|
58,597
|
|
|||
Diluted average number of common units outstanding
|
73,458
|
|
|
72,107
|
|
|
59,575
|
|
|
Predecessor Equity
|
|
Limited Partners
|
|
General Partner
|
|
|
|
|
|
|
|||||||||||||||||||||||||
|
|
Common
|
|
Subordinated
|
|
|
|
|
|
Total Partners' Equity
|
|
Noncontrolling Interests
|
|
Total Equity
|
||||||||||||||||||||||
|
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
|
|
|||||||||||||||||||||
|
(in thousands)
|
|||||||||||||||||||||||||||||||||||
Balance at January 1, 2015
|
$
|
19,402
|
|
|
32,834
|
|
|
$
|
800,333
|
|
|
16,200
|
|
|
$
|
274,133
|
|
|
835
|
|
|
$
|
(35,743
|
)
|
|
$
|
1,058,125
|
|
|
$
|
756,428
|
|
|
$
|
1,814,553
|
|
Net income
|
12,357
|
|
|
—
|
|
|
108,888
|
|
|
—
|
|
|
5,180
|
|
|
—
|
|
|
46,478
|
|
|
172,903
|
|
|
24,268
|
|
|
197,171
|
|
|||||||
Issuance of units to public, net of offering costs
|
—
|
|
|
11,266
|
|
|
554,084
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
554,084
|
|
|
—
|
|
|
554,084
|
|
|||||||
Distributions to unitholders
|
—
|
|
|
—
|
|
|
(118,729
|
)
|
|
—
|
|
|
(7,857
|
)
|
|
—
|
|
|
(35,248
|
)
|
|
(161,834
|
)
|
|
—
|
|
|
(161,834
|
)
|
|||||||
Noncash compensation expense
|
—
|
|
|
—
|
|
|
9,337
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,337
|
|
|
—
|
|
|
9,337
|
|
|||||||
Common units issued under LTIP, net of units tendered by employees to satisfy tax withholding obligations
|
—
|
|
|
344
|
|
|
(6,603
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,603
|
)
|
|
—
|
|
|
(6,603
|
)
|
|||||||
Contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
110,127
|
|
|
110,127
|
|
|||||||
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(69,474
|
)
|
|
(69,474
|
)
|
|||||||
Acquisition of additional 33.3% membership interest in Pony Express
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(324,328
|
)
|
|
(324,328
|
)
|
|
(375,672
|
)
|
|
(700,000
|
)
|
|||||||
Acquisition of noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(600
|
)
|
|
(600
|
)
|
|||||||
Conversion of subordinated units
|
—
|
|
|
16,200
|
|
|
271,456
|
|
|
(16,200
|
)
|
|
(271,456
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Contributions from Predecessor Entities, net
|
39,805
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
39,805
|
|
|
—
|
|
|
39,805
|
|
|||||||
Balance at December 31, 2015
|
$
|
71,564
|
|
|
60,644
|
|
|
$
|
1,618,766
|
|
|
—
|
|
|
$
|
—
|
|
|
835
|
|
|
$
|
(348,841
|
)
|
|
$
|
1,341,489
|
|
|
$
|
445,077
|
|
|
$
|
1,786,566
|
|
Net income
|
6,995
|
|
|
—
|
|
|
161,064
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
102,465
|
|
|
270,524
|
|
|
4,365
|
|
|
274,889
|
|
|||||||
Issuance of units to public, net of offering costs
|
—
|
|
|
7,697
|
|
|
337,671
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
337,671
|
|
|
—
|
|
|
337,671
|
|
|||||||
Issuance of units in a private placement, net of offering costs
|
—
|
|
|
2,417
|
|
|
90,009
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
90,009
|
|
|
—
|
|
|
90,009
|
|
|||||||
Distributions to unitholders
|
—
|
|
|
—
|
|
|
(202,996
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(89,838
|
)
|
|
(292,834
|
)
|
|
—
|
|
|
(292,834
|
)
|
|||||||
Noncash compensation expense
|
—
|
|
|
—
|
|
|
7,879
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,879
|
|
|
—
|
|
|
7,879
|
|
|||||||
Contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,304
|
|
|
9,304
|
|
|||||||
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,534
|
)
|
|
(6,534
|
)
|
|||||||
Acquisition of additional 31.3% membership interest in Pony Express
|
—
|
|
|
6,518
|
|
|
268,607
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(279,967
|
)
|
|
(11,360
|
)
|
|
(417,679
|
)
|
|
(429,039
|
)
|
|||||||
Partial exercise of call option
|
—
|
|
|
(4,815
|
)
|
|
(204,634
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(33,993
|
)
|
|
(238,627
|
)
|
|
—
|
|
|
(238,627
|
)
|
|||||||
Contributions from TD
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,894
|
|
|
17,894
|
|
|
—
|
|
|
17,894
|
|
|||||||
Acquisition of noncontrolling interests
|
—
|
|
|
—
|
|
|
(5,373
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(59
|
)
|
|
(5,432
|
)
|
|
(568
|
)
|
|
(6,000
|
)
|
|||||||
Common units issued under LTIP, net of units tendered by employees to satisfy tax withholding obligations
|
—
|
|
|
25
|
|
|
(498
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(498
|
)
|
|
—
|
|
|
(498
|
)
|
|||||||
Contributions from Predecessor Entities, net
|
3,736
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,736
|
|
|
—
|
|
|
3,736
|
|
|||||||
Balance at December 31, 2016
|
$
|
82,295
|
|
|
72,486
|
|
|
$
|
2,070,495
|
|
|
—
|
|
|
$
|
—
|
|
|
835
|
|
|
$
|
(632,339
|
)
|
|
$
|
1,520,451
|
|
|
$
|
33,965
|
|
|
$
|
1,554,416
|
|
|
Predecessor Equity
|
|
Limited Partners
|
|
General Partner
|
|
|
|
|
|
|
|||||||||||||||||||||||||
|
|
Common
|
|
Subordinated
|
|
|
|
|
|
Total Partners' Equity
|
|
Noncontrolling Interests
|
|
Total Equity
|
||||||||||||||||||||||
|
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
|
|
|||||||||||||||||||||
|
(in thousands)
|
|||||||||||||||||||||||||||||||||||
Acquisition of Terminals and NatGas
|
(82,295
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(57,705
|
)
|
|
(140,000
|
)
|
|
—
|
|
|
(140,000
|
)
|
|||||||
Net income
|
—
|
|
|
—
|
|
|
286,167
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
147,823
|
|
|
433,990
|
|
|
6,499
|
|
|
440,489
|
|
|||||||
Issuance of units to public, net of offering costs
|
—
|
|
|
2,341
|
|
|
112,420
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
112,420
|
|
|
—
|
|
|
112,420
|
|
|||||||
Distributions to unitholders
|
—
|
|
|
—
|
|
|
(256,124
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(136,737
|
)
|
|
(392,861
|
)
|
|
—
|
|
|
(392,861
|
)
|
|||||||
Noncash compensation expense
|
—
|
|
|
—
|
|
|
10,390
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,390
|
|
|
—
|
|
|
10,390
|
|
|||||||
Common units issued under LTIP, net of units tendered by employees to satisfy tax withholding obligations
|
—
|
|
|
683
|
|
|
(12,933
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12,933
|
)
|
|
—
|
|
|
(12,933
|
)
|
|||||||
Partial exercise of call option
|
—
|
|
|
(1,703
|
)
|
|
(72,381
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12,561
|
)
|
|
(84,942
|
)
|
|
—
|
|
|
(84,942
|
)
|
|||||||
Repurchase of common units from TD
|
—
|
|
|
(736
|
)
|
|
(35,335
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(35,335
|
)
|
|
—
|
|
|
(35,335
|
)
|
|||||||
Acquisition of additional 24.99% membership interest in Rockies Express
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
63,681
|
|
|
63,681
|
|
|
—
|
|
|
63,681
|
|
|||||||
Acquisition of additional 40% membership interest in Deeprock Development
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45,869
|
|
|
45,869
|
|
|||||||
Acquisition of noncontrolling interests
|
—
|
|
|
129
|
|
|
6,617
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,617
|
|
|
(13,057
|
)
|
|
(6,440
|
)
|
|||||||
Contributions from TD
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,301
|
|
|
2,301
|
|
|
—
|
|
|
2,301
|
|
|||||||
Contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,589
|
|
|
1,589
|
|
|||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,196
|
)
|
|
(6,196
|
)
|
|||||||
Balance at December 31, 2017
|
$
|
—
|
|
|
73,200
|
|
|
$
|
2,109,316
|
|
|
—
|
|
|
$
|
—
|
|
|
835
|
|
|
$
|
(625,537
|
)
|
|
$
|
1,483,779
|
|
|
$
|
68,669
|
|
|
$
|
1,552,448
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Cash Flows from Operating Activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
440,489
|
|
|
$
|
274,889
|
|
|
$
|
197,171
|
|
Adjustments to reconcile net income to net cash flows provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
98,064
|
|
|
93,605
|
|
|
88,949
|
|
|||
Equity in earnings of unconsolidated investments
|
(237,110
|
)
|
|
(54,531
|
)
|
|
(2,759
|
)
|
|||
Distributions from unconsolidated investments
|
237,192
|
|
|
54,449
|
|
|
3,096
|
|
|||
Gain on remeasurement of unconsolidated investment
|
(9,728
|
)
|
|
—
|
|
|
—
|
|
|||
Other noncash items, net
|
8,988
|
|
|
9,519
|
|
|
10,124
|
|
|||
Changes in components of working capital:
|
|
|
|
|
|
||||||
Accounts receivable and other
|
(57,937
|
)
|
|
2,818
|
|
|
(15,936
|
)
|
|||
Accounts payable and accrued liabilities
|
85,071
|
|
|
10,502
|
|
|
10,211
|
|
|||
Deferred revenue
|
27,283
|
|
|
33,815
|
|
|
20,612
|
|
|||
Other current assets and liabilities
|
(10,542
|
)
|
|
(5,578
|
)
|
|
(6,143
|
)
|
|||
Other operating, net
|
(2,709
|
)
|
|
95
|
|
|
(1,672
|
)
|
|||
Net Cash Provided by Operating Activities
|
579,061
|
|
|
419,583
|
|
|
303,653
|
|
|||
Cash Flows from Investing Activities:
|
|
|
|
|
|
||||||
Acquisition of Rockies Express membership interest
|
(400,000
|
)
|
|
(436,022
|
)
|
|
—
|
|
|||
Capital expenditures
|
(145,144
|
)
|
|
(84,491
|
)
|
|
(120,718
|
)
|
|||
Acquisition of Terminals and NatGas
|
(140,000
|
)
|
|
—
|
|
|
—
|
|
|||
Acquisition of Douglas Gathering System
|
(128,526
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions from unconsolidated investment in excess of cumulative earnings
|
69,434
|
|
|
24,120
|
|
|
1,552
|
|
|||
Acquisition of Deeprock Development
|
(57,202
|
)
|
|
—
|
|
|
—
|
|
|||
Contributions to unconsolidated investments
|
(45,948
|
)
|
|
(50,076
|
)
|
|
(383
|
)
|
|||
Acquisition of PRB Crude System
|
(36,030
|
)
|
|
—
|
|
|
—
|
|
|||
Acquisition of Pony Express membership interest
|
—
|
|
|
(49,118
|
)
|
|
(700,000
|
)
|
|||
Acquisition of Western
|
—
|
|
|
—
|
|
|
(75,000
|
)
|
|||
Other investing, net
|
(15,125
|
)
|
|
48
|
|
|
(4,883
|
)
|
|||
Net Cash Used in Investing Activities
|
(898,541
|
)
|
|
(595,539
|
)
|
|
(899,432
|
)
|
|||
Cash Flows from Financing Activities:
|
|
|
|
|
|
||||||
Proceeds from issuance of long-term debt
|
1,103,750
|
|
|
400,000
|
|
|
—
|
|
|||
Distributions to unitholders
|
(392,861
|
)
|
|
(292,834
|
)
|
|
(161,834
|
)
|
|||
(Repayments) borrowings under revolving credit facility, net
|
(354,000
|
)
|
|
262,000
|
|
|
194,000
|
|
|||
Proceeds from public offering, net of offering costs
|
112,420
|
|
|
337,671
|
|
|
554,084
|
|
|||
Partial exercise of call option
|
(72,381
|
)
|
|
(204,634
|
)
|
|
—
|
|
|||
Repurchase of common units from TD
|
(35,335
|
)
|
|
—
|
|
|
—
|
|
|||
Payments for deferred financing costs
|
(22,250
|
)
|
|
(10,251
|
)
|
|
(1,522
|
)
|
|||
Acquisition of Pony Express membership interest
|
—
|
|
|
(425,882
|
)
|
|
—
|
|
|||
Proceeds from private placement, net of offering costs
|
—
|
|
|
90,009
|
|
|
—
|
|
|||
Other financing, net
|
(19,927
|
)
|
|
20,139
|
|
|
11,795
|
|
|||
Net Cash Provided by Financing Activities
|
319,416
|
|
|
176,218
|
|
|
596,523
|
|
|||
Net Change in Cash and Cash Equivalents
|
(64
|
)
|
|
262
|
|
|
744
|
|
Cash and Cash Equivalents, beginning of period
|
1,873
|
|
|
1,611
|
|
|
867
|
|
|||
Cash and Cash Equivalents, end of period
|
$
|
1,809
|
|
|
$
|
1,873
|
|
|
$
|
1,611
|
|
Supplemental Disclosures:
|
|
|
|
|
|
||||||
Cash payments for interest, net
|
$
|
(67,360
|
)
|
|
$
|
(29,754
|
)
|
|
$
|
(14,021
|
)
|
Schedule of Noncash Investing and Financing Activities:
|
|
|
|
|
|
||||||
Increase in accrual for payment of property, plant and equipment
|
$
|
8,975
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Common units issued as partial consideration to acquire additional 9% membership interest in Deeprock Development
|
$
|
6,617
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Property, plant and equipment acquired via the cash management agreement with TD
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
138,936
|
|
Contributions from noncontrolling interests settled via the cash management agreement with TD
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
68,277
|
|
Distributions to noncontrolling interests settled via the cash management agreement with TD
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(69,017
|
)
|
•
|
Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities;
|
•
|
Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and
|
•
|
Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs.
|
Unit holder
|
|
Limited Partner Common Units
|
|
General Partner Units
|
|
Percentage of Outstanding Limited Partner Common Units
|
|
Percentage of Outstanding Common and General Partner Units
|
||||
Public Unitholders
|
|
47,580,535
|
|
|
—
|
|
|
65.00
|
%
|
|
64.27
|
%
|
Tallgrass Equity, LLC
|
|
20,000,000
|
|
|
—
|
|
|
27.32
|
%
|
|
27.01
|
%
|
Tallgrass Development, LP
(1)
|
|
5,619,218
|
|
|
—
|
|
|
7.68
|
%
|
|
7.59
|
%
|
Tallgrass MLP GP, LLC
(2)
|
|
—
|
|
|
834,391
|
|
|
—
|
%
|
|
1.13
|
%
|
Total
|
|
73,199,753
|
|
|
834,391
|
|
|
100.00
|
%
|
|
100.00
|
%
|
(1)
|
Effective February 7, 2018, Tallgrass Equity, LLC
("Tallgrass Equity") acquired the
5,619,218
common units held by TD in connection with the merger of TD into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity ("Tallgrass Development Holdings").
|
(2)
|
Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.
|
•
|
a significant decrease in the market value of a long-lived asset or asset group;
|
•
|
a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;
|
•
|
a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;
|
•
|
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;
|
•
|
a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and
|
•
|
a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
|
|
Range of Depreciation Rates
|
Crude oil pipelines
|
2.8%
|
Natural gas pipelines
|
0.7 - 5.0%
|
Gathering & processing assets
|
2.2 - 5.0%
|
Water business assets
|
2.3 - 20.0%
|
Terminal assets
|
1.8 - 2.8%
|
Replacement Gas Facilities
(1)
|
10.0%
|
General & other
|
2.5 - 25.0%
|
(1)
|
Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System after having sold approximately
433
miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013.
|
•
|
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).
|
•
|
Gathering & Processing.
We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas will be accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees previously recognized in revenue will be reported as a reduction to cost of sales under ASC 606.
|
•
|
Pipeline Loss Allowance.
We have determined that pipeline loss allowance, or PLA, collected under certain crude oil transportation arrangements is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue stream to TEP. Under ASC 606, PLA barrels retained from customers will be subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value.
|
•
|
Management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status.
|
•
|
Management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts.
|
•
|
Management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process.
|
•
|
Management plans to provide internal training and awareness related to the revised guidance to the key stakeholders throughout its organization.
|
Accounts receivable
|
$
|
117
|
|
|
Property, plant and equipment
|
29,306
|
|
|
|
Intangible asset
|
6,694
|
|
(1)
|
|
Accounts payable and accrued liabilities
|
(87
|
)
|
|
|
Net identifiable assets acquired
|
$
|
36,030
|
|
|
(1)
|
The
$6.7 million
intangible asset acquired represents a major customer contract. This intangible asset is amortized on a straight-line basis over a period of
8 years
, the remaining term of the contract at the time of acquisition.
|
Accounts receivable
|
$
|
968
|
|
Other current assets
|
598
|
|
|
Property, plant and equipment
|
70,148
|
|
|
Accounts payable
|
(712
|
)
|
|
Deferred revenue
|
(6,546
|
)
|
|
Net identifiable assets acquired
|
64,456
|
|
|
Goodwill
|
61,550
|
|
|
Net assets acquired (excluding cash)
|
$
|
126,006
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Revenue
|
$
|
667,391
|
|
|
$
|
632,528
|
|
|
$
|
544,497
|
|
Net income attributable to partners
|
$
|
427,522
|
|
|
$
|
275,506
|
|
|
$
|
173,542
|
|
|
December 31, 2016
|
||||||||||||||
|
TEP (As previously reported)
|
|
Consolidate Terminals
|
|
Consolidate NatGas
|
|
TEP (As currently reported)
|
||||||||
|
(in thousands)
|
||||||||||||||
ASSETS
|
|
|
|
|
|
||||||||||
Current Assets:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
1,873
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,873
|
|
Accounts receivable, net
|
59,469
|
|
|
38
|
|
|
29
|
|
|
59,536
|
|
||||
Gas imbalances
|
1,597
|
|
|
—
|
|
|
—
|
|
|
1,597
|
|
||||
Inventories
|
12,805
|
|
|
288
|
|
|
—
|
|
|
13,093
|
|
||||
Derivative assets
|
10,967
|
|
|
—
|
|
|
—
|
|
|
10,967
|
|
||||
Prepayments and other current assets
|
6,820
|
|
|
808
|
|
|
—
|
|
|
7,628
|
|
||||
Total Current Assets
|
93,531
|
|
|
1,134
|
|
|
29
|
|
|
94,694
|
|
||||
Property, plant and equipment, net
|
2,012,263
|
|
|
66,969
|
|
|
—
|
|
|
2,079,232
|
|
||||
Goodwill
|
343,288
|
|
|
—
|
|
|
—
|
|
|
343,288
|
|
||||
Intangible assets, net
|
93,522
|
|
|
—
|
|
|
—
|
|
|
93,522
|
|
||||
Unconsolidated investments
|
461,915
|
|
|
13,710
|
|
|
—
|
|
|
475,625
|
|
||||
Deferred financing costs, net
|
4,815
|
|
|
—
|
|
|
—
|
|
|
4,815
|
|
||||
Deferred charges and other assets
|
9,637
|
|
|
1,400
|
|
|
—
|
|
|
11,037
|
|
||||
Total Assets
|
$
|
3,018,971
|
|
|
$
|
83,213
|
|
|
$
|
29
|
|
|
$
|
3,102,213
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
||||||||
Current Liabilities:
|
|
|
|
|
|
|
|
||||||||
Accounts payable
|
$
|
24,076
|
|
|
$
|
46
|
|
|
$
|
—
|
|
|
$
|
24,122
|
|
Accounts payable to related parties
|
5,879
|
|
|
56
|
|
|
—
|
|
|
5,935
|
|
||||
Gas imbalances
|
1,239
|
|
|
—
|
|
|
—
|
|
|
1,239
|
|
||||
Derivative liabilities
|
556
|
|
|
—
|
|
|
—
|
|
|
556
|
|
||||
Accrued taxes
|
16,328
|
|
|
668
|
|
|
—
|
|
|
16,996
|
|
||||
Accrued liabilities
|
16,525
|
|
|
177
|
|
|
—
|
|
|
16,702
|
|
||||
Deferred revenue
|
60,757
|
|
|
—
|
|
|
—
|
|
|
60,757
|
|
||||
Other current liabilities
|
6,446
|
|
|
—
|
|
|
—
|
|
|
6,446
|
|
||||
Total Current Liabilities
|
131,806
|
|
|
947
|
|
|
—
|
|
|
132,753
|
|
||||
Long-term debt, net
|
1,407,981
|
|
|
—
|
|
|
—
|
|
|
1,407,981
|
|
||||
Other long-term liabilities and deferred credits
|
7,063
|
|
|
—
|
|
|
—
|
|
|
7,063
|
|
||||
Total Long-term Liabilities
|
1,415,044
|
|
|
—
|
|
|
—
|
|
|
1,415,044
|
|
||||
Equity:
|
|
|
|
|
|
|
|
||||||||
Net Equity
|
1,472,121
|
|
|
82,266
|
|
|
29
|
|
|
1,554,416
|
|
||||
Total Equity
|
1,472,121
|
|
|
82,266
|
|
|
29
|
|
|
1,554,416
|
|
||||
Total Liabilities and Equity
|
$
|
3,018,971
|
|
|
$
|
83,213
|
|
|
$
|
29
|
|
|
$
|
3,102,213
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||
|
TEP (As previously reported)
|
|
Consolidate Terminals
|
|
Consolidate NatGas
|
|
Elimination
|
|
TEP (As currently reported)
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil transportation services
|
$
|
374,949
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
374,949
|
|
Natural gas transportation services
|
119,962
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
119,962
|
|
|||||
Sales of natural gas, NGLs, and crude oil
|
77,394
|
|
|
99
|
|
|
—
|
|
|
(370
|
)
|
(1)
|
77,123
|
|
|||||
Processing and other revenues
|
32,817
|
|
|
12,043
|
|
|
6,228
|
|
|
(11,460
|
)
|
(2)
|
39,628
|
|
|||||
Total Revenues
|
605,122
|
|
|
12,142
|
|
|
6,228
|
|
|
(11,830
|
)
|
|
611,662
|
|
|||||
Operating Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of sales
|
71,920
|
|
|
100
|
|
|
—
|
|
|
(370
|
)
|
(1)
|
71,650
|
|
|||||
Cost of transportation services
|
58,341
|
|
|
788
|
|
|
—
|
|
|
(11,460
|
)
|
(2)
|
47,669
|
|
|||||
Operations and maintenance
|
53,386
|
|
|
1,684
|
|
|
—
|
|
|
—
|
|
|
55,070
|
|
|||||
Depreciation and amortization
|
84,896
|
|
|
1,351
|
|
|
—
|
|
|
—
|
|
|
86,247
|
|
|||||
General and administrative
|
53,633
|
|
|
1,469
|
|
|
—
|
|
|
—
|
|
|
55,102
|
|
|||||
Taxes, other than income taxes
|
24,727
|
|
|
673
|
|
|
—
|
|
|
—
|
|
|
25,400
|
|
|||||
Contract termination
|
—
|
|
|
8,061
|
|
(3)
|
—
|
|
|
—
|
|
|
8,061
|
|
|||||
Loss on disposal of assets
|
1,849
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,849
|
|
|||||
Total Operating Costs and Expenses
|
348,752
|
|
|
14,126
|
|
|
—
|
|
|
(11,830
|
)
|
|
351,048
|
|
|||||
Operating Income (Expense)
|
256,370
|
|
|
(1,984
|
)
|
|
6,228
|
|
|
—
|
|
|
260,614
|
|
|||||
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
(40,688
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(40,688
|
)
|
|||||
Unrealized loss on derivative instrument
|
(1,291
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,291
|
)
|
|||||
Equity in earnings of unconsolidated investments
|
51,780
|
|
|
2,751
|
|
|
—
|
|
|
—
|
|
|
54,531
|
|
|||||
Other income, net
|
1,723
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,723
|
|
|||||
Total Other Income
|
11,524
|
|
|
2,751
|
|
|
—
|
|
|
—
|
|
|
14,275
|
|
|||||
Net income
|
267,894
|
|
|
767
|
|
|
6,228
|
|
|
—
|
|
|
274,889
|
|
|||||
Net income attributable to noncontrolling interests
|
(4,365
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,365
|
)
|
|||||
Net income attributable to partners
|
$
|
263,529
|
|
|
$
|
767
|
|
|
$
|
6,228
|
|
|
$
|
—
|
|
|
$
|
270,524
|
|
|
Year Ended December 31, 2015
|
||||||||||||||||||
|
TEP (As previously reported)
|
|
Consolidate Terminals
|
|
Consolidate NatGas
|
|
Elimination
|
|
TEP (As currently reported)
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil transportation services
|
$
|
300,436
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
300,436
|
|
Natural gas transportation services
|
119,895
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
119,895
|
|
|||||
Sales of natural gas, NGLs, and crude oil
|
82,133
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
82,133
|
|
|||||
Processing and other revenues
|
33,733
|
|
|
7,689
|
|
|
6,332
|
|
|
(7,557
|
)
|
(2)
|
40,197
|
|
|||||
Total Revenues
|
536,197
|
|
|
7,689
|
|
|
6,332
|
|
|
(7,557
|
)
|
|
542,661
|
|
|||||
Operating Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of sales
|
75,285
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
75,285
|
|
|||||
Cost of transportation services
|
53,597
|
|
|
800
|
|
|
—
|
|
|
(7,557
|
)
|
(2)
|
46,840
|
|
|||||
Operations and maintenance
|
49,138
|
|
|
1,685
|
|
|
—
|
|
|
—
|
|
|
50,823
|
|
|||||
Depreciation and amortization
|
83,476
|
|
|
782
|
|
|
—
|
|
|
—
|
|
|
84,258
|
|
|||||
General and administrative
|
50,195
|
|
|
1,156
|
|
|
—
|
|
|
—
|
|
|
51,351
|
|
|||||
Taxes, other than income taxes
|
21,796
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,796
|
|
|||||
Loss on disposal of assets
|
4,795
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,795
|
|
|||||
Total Operating Costs and Expenses
|
338,282
|
|
|
4,423
|
|
|
—
|
|
|
(7,557
|
)
|
|
335,148
|
|
|||||
Operating Income
|
197,915
|
|
|
3,266
|
|
|
6,332
|
|
|
—
|
|
|
207,513
|
|
|||||
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
(15,514
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15,514
|
)
|
|||||
Equity in earnings of unconsolidated investments
|
—
|
|
|
2,759
|
|
|
—
|
|
|
—
|
|
|
2,759
|
|
|||||
Other income, net
|
2,413
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,413
|
|
|||||
Total Other (Expense) Income
|
(13,101
|
)
|
|
2,759
|
|
|
—
|
|
|
—
|
|
|
(10,342
|
)
|
|||||
Net income
|
184,814
|
|
|
6,025
|
|
|
6,332
|
|
|
—
|
|
|
197,171
|
|
|||||
Net income attributable to noncontrolling interests
|
(24,268
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(24,268
|
)
|
|||||
Net income attributable to partners
|
$
|
160,546
|
|
|
$
|
6,025
|
|
|
$
|
6,332
|
|
|
$
|
—
|
|
|
$
|
172,903
|
|
(1)
|
Represents the elimination of revenue and cost of sales associated with the purchase of crude oil from Pony Express by Terminals.
|
(2)
|
Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal facilities by Pony Express.
|
(3)
|
Represents a one-time charge related to the termination of an operating agreement at the Sterling Terminal.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Processing and other revenues
(1)
|
$
|
8,516
|
|
|
$
|
6,228
|
|
|
$
|
6,331
|
|
Cost of transportation services
(2)
|
$
|
10,476
|
|
|
$
|
18,585
|
|
|
$
|
18,288
|
|
Charges to TEP:
(3)
|
|
|
|
|
|
||||||
Property, plant and equipment, net
|
$
|
2,679
|
|
|
$
|
3,084
|
|
|
$
|
4,342
|
|
Other deferred charges
|
$
|
25
|
|
|
$
|
44
|
|
|
$
|
7
|
|
Operations and maintenance
|
$
|
29,881
|
|
|
$
|
25,431
|
|
|
$
|
23,658
|
|
General and administrative
|
$
|
41,032
|
|
|
$
|
39,574
|
|
|
$
|
33,820
|
|
(1)
|
Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline.
|
(2)
|
Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017, as discussed in
Note 3
–
Acquisitions
.
|
(3)
|
Charges to TEP include directly charged wages and salaries, other compensation and benefits, and shared services.
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Receivable from related parties:
|
|
|
|
||||
Rockies Express Pipeline LLC
|
$
|
1,340
|
|
|
$
|
590
|
|
Total receivable from related parties
|
$
|
1,340
|
|
|
$
|
590
|
|
Accounts payable to related parties:
|
|
|
|
||||
Tallgrass Operations, LLC
|
$
|
5,381
|
|
|
$
|
5,854
|
|
Tallgrass Equity, LLC
|
80
|
|
|
68
|
|
||
Deeprock Development, LLC
|
—
|
|
|
13
|
|
||
Total accounts payable to related parties
|
$
|
5,461
|
|
|
$
|
5,935
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Affiliate gas imbalance receivables
|
$
|
18
|
|
|
$
|
177
|
|
Affiliate gas imbalance payables
|
$
|
442
|
|
|
$
|
—
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Crude oil
|
$
|
12,792
|
|
|
$
|
5,462
|
|
Materials and supplies
|
5,891
|
|
|
6,383
|
|
||
Natural gas liquids
|
942
|
|
|
265
|
|
||
Gas in underground storage
|
1,984
|
|
|
983
|
|
||
Total inventory
|
$
|
21,609
|
|
|
$
|
13,093
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Crude oil pipelines
|
$
|
1,220,379
|
|
|
$
|
1,202,125
|
|
Gathering, processing and terminalling assets
(1)
|
675,092
|
|
|
397,701
|
|
||
Natural gas pipelines
|
581,400
|
|
|
572,150
|
|
||
General and other
|
98,680
|
|
|
82,510
|
|
||
Construction work in progress
|
97,978
|
|
|
20,606
|
|
||
Accumulated depreciation and amortization
|
(279,192
|
)
|
|
(195,860
|
)
|
||
Total property, plant and equipment, net
(2)
|
$
|
2,394,337
|
|
|
$
|
2,079,232
|
|
(1)
|
Includes approximately
$138.2 million
of assets associated with the Douglas Gathering System acquired in June 2017, approximately
$68.4 million
of assets associated with the acquisition of the aggregate additional
49%
membership interest in Deeprock Development in July 2017, and approximately
$29.3 million
of assets associated with the PRB Crude System acquired in August 2017.
|
(2)
|
Property, plant and equipment, net includes approximately
$431.6 million
of assets at our regulated natural gas pipelines at
December 31, 2017
.
|
Year
|
|
Total
|
||
2018
|
|
$
|
4,575
|
|
2019
|
|
4,590
|
|
|
2020
|
|
3,978
|
|
|
2021
|
|
3,773
|
|
|
2022
|
|
3,773
|
|
|
Thereafter
|
|
11,127
|
|
|
Total
|
|
$
|
31,816
|
|
|
Year Ended December 31, 2017
|
|
Year Ended December 31, 2016
|
||||||||||||||||||||
|
Natural Gas Transportation
|
|
Gathering, Processing & Terminalling
|
|
Total
|
|
Natural Gas Transportation
|
|
Gathering, Processing & Terminalling
|
|
Total
|
||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
Balance at beginning of period
|
$
|
255,558
|
|
|
$
|
87,730
|
|
|
$
|
343,288
|
|
|
$
|
255,558
|
|
|
$
|
87,730
|
|
|
$
|
343,288
|
|
Goodwill acquired
|
—
|
|
|
61,550
|
|
(1)
|
61,550
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Balance at end of period
|
$
|
255,558
|
|
|
$
|
149,280
|
|
|
$
|
404,838
|
|
|
$
|
255,558
|
|
|
$
|
87,730
|
|
|
$
|
343,288
|
|
(1)
|
The
$61.6 million
of goodwill was recorded in connection with the acquisition of a controlling interest in Deeprock Development on July 20, 2017 as discussed further in
Note 3
–
Acquisitions
.
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Pony Express oil conversion use rights
|
$
|
105,973
|
|
|
$
|
105,973
|
|
Customer contracts
|
8,064
|
|
|
—
|
|
||
Accumulated amortization
|
(16,306
|
)
|
|
(12,451
|
)
|
||
Intangible assets, net
|
$
|
97,731
|
|
|
$
|
93,522
|
|
Year
|
|
Total
|
||
2018
|
|
$
|
4,581
|
|
2019
|
|
4,048
|
|
|
2020
|
|
3,868
|
|
|
2021
|
|
3,868
|
|
|
2022
|
|
3,868
|
|
|
Thereafter
|
|
77,498
|
|
|
Total
|
|
$
|
97,731
|
|
|
Basis Difference
|
|
Amortization Period
|
||
|
(in thousands)
|
|
|
||
Long-term debt
|
$
|
29,458
|
|
|
2 - 25 years
|
Property, plant and equipment
|
(788,631
|
)
|
|
35 years
|
|
Total basis difference
|
$
|
(759,173
|
)
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Current assets
|
$
|
122,362
|
|
|
$
|
199,958
|
|
Noncurrent assets
|
$
|
5,974,926
|
|
|
$
|
6,148,203
|
|
Current liabilities
|
$
|
714,037
|
|
|
$
|
197,305
|
|
Noncurrent liabilities
|
$
|
2,049,189
|
|
|
$
|
2,656,836
|
|
Members' equity
|
$
|
3,334,062
|
|
|
$
|
3,494,020
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Revenue
|
$
|
860,115
|
|
|
$
|
440,838
|
|
|
$
|
18,646
|
|
Operating income
|
$
|
480,337
|
|
|
$
|
203,801
|
|
|
$
|
13,794
|
|
Net income to Members
|
$
|
465,592
|
|
|
$
|
184,314
|
|
|
$
|
13,794
|
|
(1)
|
As discussed below, 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, 2017
, there were no natural gas derivative contracts outstanding. 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.
|
(3)
|
As of
December 31, 2017
, the fair value shown for crude oil derivative contracts represents the forward sale of
356,000
barrels which will settle throughout the first quarter of 2018. As of
December 31, 2016
, the fair value shown for crude oil derivative contracts represents the sale of
125,000
barrels of crude oil which settled throughout 2017.
|
|
|
|
Asset Fair Value Measurements Using
|
||||||||||||
|
Total
|
|
Quoted prices in
active markets for identical assets (Level 1) |
|
Significant
other observable inputs (Level 2) |
|
Significant
unobservable inputs (Level 3) |
||||||||
|
(in thousands)
|
||||||||||||||
As of December 31, 2016:
|
|
|
|
|
|
|
|
||||||||
Call option derivative
|
$
|
10,676
|
|
|
$
|
—
|
|
|
$
|
10,676
|
|
|
$
|
—
|
|
Natural gas derivative contracts
|
$
|
291
|
|
|
$
|
—
|
|
|
$
|
291
|
|
|
$
|
—
|
|
|
|
|
Liability Fair Value Measurements Using
|
||||||||||||
|
Total
|
|
Quoted prices in
active markets for identical assets (Level 1) |
|
Significant
other observable inputs (Level 2) |
|
Significant
unobservable inputs (Level 3) |
||||||||
|
(in thousands)
|
||||||||||||||
As of December 31, 2017:
|
|
|
|
|
|
|
|
||||||||
Crude oil derivative contracts
|
$
|
2,368
|
|
|
$
|
—
|
|
|
$
|
2,368
|
|
|
$
|
—
|
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
||||||||
Crude oil derivative contracts
|
$
|
440
|
|
|
$
|
—
|
|
|
$
|
440
|
|
|
$
|
—
|
|
Natural gas derivative contracts
|
$
|
116
|
|
|
$
|
—
|
|
|
$
|
116
|
|
|
$
|
—
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Revolving credit facility
|
$
|
661,000
|
|
|
$
|
1,015,000
|
|
5.50% senior notes due September 15, 2024
|
750,000
|
|
|
400,000
|
|
||
5.50% senior notes due January 15, 2028
|
750,000
|
|
|
—
|
|
||
Less: Deferred financing costs, net
(1)
|
(17,737
|
)
|
|
(7,019
|
)
|
||
Plus: Unamortized premium on 2028 Notes
|
3,730
|
|
|
—
|
|
||
Total long-term debt, net
|
$
|
2,146,993
|
|
|
$
|
1,407,981
|
|
(1)
|
Deferred financing costs, net as presented above relate solely to the 2024 and 2028 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our consolidated balance sheets.
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Total capacity under the revolving credit facility
|
$
|
1,750,000
|
|
|
$
|
1,750,000
|
|
Less: Outstanding borrowings under the revolving credit facility
|
(661,000
|
)
|
|
(1,015,000
|
)
|
||
Less: Letters of credit issued under the revolving credit facility
|
(94
|
)
|
|
—
|
|
||
Available capacity under the revolving credit facility
|
$
|
1,088,906
|
|
|
$
|
735,000
|
|
|
Fair Value
|
|
|
||||||||||||||||
|
Quoted prices
in active markets for identical assets (Level 1) |
|
Significant
other observable inputs (Level 2) |
|
Significant
unobservable inputs (Level 3) |
|
Total
|
|
Carrying
Amount |
||||||||||
|
(in thousands)
|
||||||||||||||||||
As of December 31, 2017:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revolving credit facility
|
$
|
—
|
|
|
$
|
661,000
|
|
|
$
|
—
|
|
|
$
|
661,000
|
|
|
$
|
661,000
|
|
2024 Notes
|
$
|
—
|
|
|
$
|
771,645
|
|
|
$
|
—
|
|
|
$
|
771,645
|
|
|
$
|
739,824
|
|
2028 Notes
|
$
|
—
|
|
|
$
|
758,168
|
|
|
$
|
—
|
|
|
$
|
758,168
|
|
|
$
|
746,169
|
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revolving credit facility
|
$
|
—
|
|
|
$
|
1,015,000
|
|
|
$
|
—
|
|
|
$
|
1,015,000
|
|
|
$
|
1,015,000
|
|
2024 Notes
|
$
|
—
|
|
|
$
|
398,000
|
|
|
$
|
—
|
|
|
$
|
398,000
|
|
|
$
|
392,981
|
|
|
|
|
|
Distributions
|
|
Distribution per Limited Partner Common Unit
|
||||||||||||||||
|
|
|
|
Limited Partner
Common Units |
|
General Partner
|
|
|
|
|||||||||||||
Three Months Ended
|
|
Date Paid
|
|
Incentive Distribution Rights
|
|
General Partner Units
|
|
Total
|
|
|||||||||||||
|
|
|
|
(in thousands, except per unit amounts)
|
||||||||||||||||||
December 31, 2017
|
|
February 14, 2018
(1)
|
|
$
|
70,638
|
|
|
$
|
39,125
|
|
|
$
|
1,251
|
|
|
$
|
111,014
|
|
|
$
|
0.9650
|
|
September 30, 2017
|
|
November 14, 2017
|
|
69,174
|
|
|
37,744
|
|
|
1,219
|
|
|
108,137
|
|
|
0.9450
|
|
|||||
June 30, 2017
|
|
August 14, 2017
|
|
67,671
|
|
|
36,342
|
|
|
1,186
|
|
|
105,199
|
|
|
0.9250
|
|
|||||
March 31, 2017
|
|
May 15, 2017
|
|
60,486
|
|
|
29,840
|
|
|
1,040
|
|
|
91,366
|
|
|
0.8350
|
|
|||||
December 31, 2016
|
|
February 14, 2017
|
|
58,793
|
|
|
28,358
|
|
|
1,008
|
|
|
88,159
|
|
|
0.8150
|
|
|||||
September 30, 2016
|
|
November 14, 2016
|
|
57,332
|
|
|
26,987
|
|
|
976
|
|
|
85,295
|
|
|
0.7950
|
|
|||||
June 30, 2016
|
|
August 12, 2016
|
|
54,442
|
|
|
24,262
|
|
|
911
|
|
|
79,615
|
|
|
0.7550
|
|
|||||
March 31, 2016
|
|
May 13, 2016
|
|
48,238
|
|
|
19,816
|
|
|
830
|
|
|
68,884
|
|
|
0.7050
|
|
|||||
December 31, 2015
|
|
February 12, 2016
|
|
42,984
|
|
|
15,332
|
|
|
724
|
|
|
59,040
|
|
|
0.6400
|
|
|||||
September 30, 2015
|
|
November 13, 2015
|
|
36,347
|
|
|
11,567
|
|
|
660
|
|
|
48,574
|
|
|
0.6000
|
|
|||||
June 30, 2015
|
|
August 14, 2015
|
|
35,135
|
|
|
10,418
|
|
|
627
|
|
|
46,180
|
|
|
0.5800
|
|
|||||
March 31, 2015
|
|
May 14, 2015
|
|
31,322
|
|
|
6,934
|
|
|
530
|
|
|
38,786
|
|
|
0.5200
|
|
(1)
|
The distribution announced on January 8, 2018 for the fourth quarter of 2017 will be paid on February 14, 2018 to unitholders of record at the close of business on January 31, 2018.
|
•
|
We have distributed available cash from operating surplus to all 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;
|
•
|
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.
|
•
|
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.
|
•
|
TEP was deemed to have made a noncash capital distribution of
$57.7 million
to the general partner, which represents the excess purchase price over the carrying value of the Terminals and NatGas net assets acquired January 1, 2017;
|
•
|
TEP was deemed to have made a noncash capital distribution of
$12.6 million
to the general partner, which represents the derecognition of a portion of the derivative asset associated with the partial exercise of the call option;
|
•
|
TEP was deemed to have received a noncash capital contribution of
$63.7 million
from the general partner, which represents the excess carrying value of the additional
24.99%
membership interest in Rockies Express acquired March 31, 2017 over the fair value of the consideration paid;
|
•
|
TEP received contributions from TD of
$2.3 million
primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in
Note 17
–
Legal and Environmental Matters
; and
|
•
|
TEP recognized contributions from and distributions to noncontrolling interests of
$1.6 million
, and
$6.2 million
, respectively, which primarily consisted of activity associated with TD's
2%
noncontrolling interest in Pony Express.
|
•
|
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;
|
•
|
TEP received contributions of
$17.9 million
from TD to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed above; and
|
•
|
TEP 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.
|
•
|
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; and
|
•
|
TEP 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.
|
Year
|
|
Total
|
||
2018
|
|
$
|
1,226
|
|
2019
|
|
1,351
|
|
|
2020
|
|
1,414
|
|
|
2021
|
|
1,093
|
|
|
2022
|
|
828
|
|
|
Thereafter
|
|
4,394
|
|
|
Total
|
|
$
|
10,306
|
|
Year
|
|
Total
|
||
2018
|
|
$
|
2,084
|
|
2019
|
|
2,091
|
|
|
2020
|
|
2,070
|
|
|
2021
|
|
20
|
|
|
2022
|
|
20
|
|
|
Thereafter
|
|
48
|
|
|
Total
|
|
$
|
6,333
|
|
|
Year Ended December 31, 2017
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
||||||
|
(in thousands, except per unit amounts)
|
||||||||||
Net income
|
$
|
440,489
|
|
|
$
|
274,889
|
|
|
$
|
197,171
|
|
Net income attributable to noncontrolling interests
|
(6,499
|
)
|
|
(4,365
|
)
|
|
(24,268
|
)
|
|||
Net income attributable to partners
|
433,990
|
|
|
270,524
|
|
|
172,903
|
|
|||
Predecessor operations interest in net income
|
—
|
|
|
(6,995
|
)
|
|
(12,357
|
)
|
|||
General partner interest in net income
|
(147,823
|
)
|
|
(102,465
|
)
|
|
(46,478
|
)
|
|||
Net income available to common unitholders
|
$
|
286,167
|
|
|
$
|
161,064
|
|
|
$
|
114,068
|
|
Basic net income per common unit
|
$
|
3.93
|
|
|
$
|
2.26
|
|
|
$
|
1.95
|
|
Diluted net income per common unit
|
$
|
3.90
|
|
|
$
|
2.23
|
|
|
$
|
1.91
|
|
Basic average number of common units outstanding
|
72,876
|
|
|
71,150
|
|
|
58,597
|
|
|||
Equity Participation Unit equivalent units
|
582
|
|
|
957
|
|
|
978
|
|
|||
Diluted average number of common units outstanding
|
73,458
|
|
|
72,107
|
|
|
59,575
|
|
|
|
Percentage of
Segment Revenue
|
Natural Gas Transportation
|
|
56%
|
Crude Oil Transportation
|
|
91%
|
Gathering, Processing & Terminalling
|
|
75%
|
|
Equity Participation Units
|
|
Weighted Average
Grant Date Fair Value |
|||
|
|
|
|
|||
Outstanding at January 1, 2015
|
1,525,750
|
|
|
$
|
18.75
|
|
Granted
|
338,591
|
|
|
40.01
|
|
|
Vested
(1)
|
(480,555
|
)
|
|
(19.39
|
)
|
|
Forfeited
|
(58,825
|
)
|
|
(16.98
|
)
|
|
Outstanding at December 31, 2015
|
1,324,961
|
|
|
24.11
|
|
|
Granted
|
94,750
|
|
|
35.12
|
|
|
Vested
(1)
|
(35,998
|
)
|
|
(23.74
|
)
|
|
Forfeited
|
(43,829
|
)
|
|
(20.08
|
)
|
|
Outstanding at December 31, 2016
|
1,339,884
|
|
|
24.92
|
|
|
Granted
|
621,400
|
|
|
38.58
|
|
|
Vested
(1)
|
(941,858
|
)
|
|
(19.70
|
)
|
|
Forfeited
|
(30,033
|
)
|
|
(39.08
|
)
|
|
Outstanding at December 31, 2017
|
989,393
|
|
|
$
|
38.58
|
|
(1)
|
During the
years ended December 31, 2017
,
2016
, and
2015
, approximately
683,304
,
24,933
, and
344,383
common units (net of tax withholding of approximately
258,554
,
11,065
, and
136,172
common units) were issued in connection with the settlement of vested awards, respectively.
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||||||||||||||||||||||||||
Revenue:
|
Total
Revenue |
|
Inter-
Segment |
|
External
Revenue |
|
Total
Revenue |
|
Inter-
Segment |
|
External
Revenue |
|
Total
Revenue |
|
Inter-
Segment |
|
External
Revenue |
||||||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||||||||||
Natural Gas Transportation
|
$
|
141,021
|
|
|
$
|
(6,694
|
)
|
|
$
|
134,327
|
|
|
$
|
135,097
|
|
|
$
|
(5,641
|
)
|
|
$
|
129,456
|
|
|
$
|
137,988
|
|
|
$
|
(5,384
|
)
|
|
$
|
132,604
|
|
Crude Oil Transportation
|
364,574
|
|
|
(10,676
|
)
|
|
353,898
|
|
|
380,503
|
|
|
(370
|
)
|
|
380,133
|
|
|
304,227
|
|
|
—
|
|
|
304,227
|
|
|||||||||
Gathering, Processing & Terminalling
|
186,211
|
|
|
(18,538
|
)
|
|
167,673
|
|
|
113,533
|
|
|
(11,460
|
)
|
|
102,073
|
|
|
113,387
|
|
|
(7,557
|
)
|
|
105,830
|
|
|||||||||
Corporate and Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Total revenue
|
$
|
691,806
|
|
|
$
|
(35,908
|
)
|
|
$
|
655,898
|
|
|
$
|
629,133
|
|
|
$
|
(17,471
|
)
|
|
$
|
611,662
|
|
|
$
|
555,602
|
|
|
$
|
(12,941
|
)
|
|
$
|
542,661
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||||||||||||||||||||||||||
Adjusted EBITDA:
|
Total
Adjusted EBITDA |
|
Inter-
Segment |
|
External
Adjusted EBITDA |
|
Total
Adjusted EBITDA |
|
Inter-
Segment |
|
External
Adjusted EBITDA |
|
Total
Adjusted EBITDA |
|
Inter-
Segment |
|
External
Adjusted EBITDA |
||||||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||||||||||
Natural Gas Transportation
|
$
|
392,394
|
|
|
$
|
(7,709
|
)
|
|
$
|
384,685
|
|
|
$
|
154,850
|
|
|
$
|
(5,641
|
)
|
|
$
|
149,209
|
|
|
$
|
73,699
|
|
|
$
|
(5,384
|
)
|
|
$
|
68,315
|
|
Crude Oil Transportation
|
243,106
|
|
|
17,263
|
|
|
260,369
|
|
|
264,391
|
|
|
16,843
|
|
|
281,234
|
|
|
165,204
|
|
|
12,941
|
|
|
178,145
|
|
|||||||||
Gathering, Processing & Terminalling
|
50,970
|
|
|
(9,554
|
)
|
|
41,416
|
|
|
17,928
|
|
|
(11,202
|
)
|
|
6,726
|
|
|
32,243
|
|
|
(7,557
|
)
|
|
24,686
|
|
|||||||||
Corporate and Other
|
(8,463
|
)
|
|
—
|
|
|
(8,463
|
)
|
|
(4,622
|
)
|
|
—
|
|
|
(4,622
|
)
|
|
(2,979
|
)
|
|
—
|
|
|
(2,979
|
)
|
|||||||||
Reconciliation to Net Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Equity in earnings of unconsolidated investments
|
|
|
|
|
237,110
|
|
|
|
|
|
|
54,531
|
|
|
|
|
|
|
2,759
|
|
|||||||||||||||
Gain on remeasurement of unconsolidated investment
|
|
|
|
|
9,728
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|||||||||||||||
Non-cash loss allocated to noncontrolling interest
|
|
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
9,377
|
|
|||||||||||||||
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Interest expense, net of noncontrolling interest
|
|
|
|
|
(83,542
|
)
|
|
|
|
|
|
(40,688
|
)
|
|
|
|
|
|
(15,517
|
)
|
|||||||||||||||
Depreciation and amortization expense, net of noncontrolling interest
|
|
|
|
|
(92,455
|
)
|
|
|
|
|
|
(88,122
|
)
|
|
|
|
|
|
(77,111
|
)
|
|||||||||||||||
Distributions from unconsolidated investments
|
|
|
|
|
(306,626
|
)
|
|
|
|
|
|
(78,568
|
)
|
|
|
|
|
|
(4,648
|
)
|
Non-cash loss related to derivative instruments, net of noncontrolling interests
|
|
|
|
|
(226
|
)
|
|
|
|
|
|
(1,547
|
)
|
|
|
|
|
|
—
|
|
|||||||||||||||
Non-cash compensation expense
|
|
|
|
|
(8,660
|
)
|
|
|
|
|
|
(5,780
|
)
|
|
|
|
|
|
(5,103
|
)
|
|||||||||||||||
Gain (loss) on disposal of assets, net of noncontrolling interests
|
|
|
|
|
654
|
|
|
|
|
|
|
(1,849
|
)
|
|
|
|
|
|
(4,795
|
)
|
|||||||||||||||
Loss on extinguishment of debt
|
|
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
(226
|
)
|
|||||||||||||||
Net income attributable to partners
|
|
|
|
|
$
|
433,990
|
|
|
|
|
|
|
$
|
270,524
|
|
|
|
|
|
|
$
|
172,903
|
|
|
Year Ended December 31,
|
||||||||||
Capital Expenditures:
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Natural Gas Transportation
|
$
|
16,705
|
|
|
$
|
28,475
|
|
|
$
|
10,478
|
|
Crude Oil Transportation
|
57,022
|
|
|
29,893
|
|
|
38,802
|
|
|||
Gathering, Processing & Terminalling
|
71,417
|
|
|
26,123
|
|
|
71,438
|
|
|||
Corporate and Other
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total capital expenditures
|
$
|
145,144
|
|
|
$
|
84,491
|
|
|
$
|
120,718
|
|
Unconsolidated Investments:
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Natural Gas Transportation
|
$
|
895,873
|
|
|
$
|
461,915
|
|
Crude Oil Transportation
|
—
|
|
|
—
|
|
||
Gathering, Processing & Terminalling
|
13,658
|
|
|
13,710
|
|
||
Corporate and Other
|
—
|
|
|
—
|
|
||
Total unconsolidated investments
|
$
|
909,531
|
|
|
$
|
475,625
|
|
Assets:
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Natural Gas Transportation
|
$
|
1,606,666
|
|
|
$
|
1,176,147
|
|
Crude Oil Transportation
|
1,407,758
|
|
|
1,410,695
|
|
||
Gathering, Processing & Terminalling
|
943,340
|
|
|
495,170
|
|
||
Corporate and Other
|
19,589
|
|
|
20,201
|
|
||
Total assets
|
$
|
3,977,353
|
|
|
$
|
3,102,213
|
|
|
Quarter Ended 2017
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
(in thousands, except per unit amounts)
|
||||||||||||||
Total revenues
|
$
|
144,400
|
|
|
$
|
160,863
|
|
|
$
|
175,869
|
|
|
$
|
174,766
|
|
Operating income
|
$
|
63,780
|
|
|
$
|
67,504
|
|
|
$
|
74,567
|
|
|
$
|
68,236
|
|
Net income
|
$
|
71,784
|
|
|
$
|
90,829
|
|
|
$
|
185,503
|
|
|
$
|
92,373
|
|
Net income attributable to partners
|
$
|
70,905
|
|
|
$
|
89,880
|
|
|
$
|
184,090
|
|
|
$
|
89,115
|
|
Net income available to common unitholders
|
$
|
40,322
|
|
|
$
|
52,579
|
|
|
$
|
144,281
|
|
|
$
|
48,985
|
|
Basic net income per limited partner unit
|
$
|
0.56
|
|
|
$
|
0.72
|
|
|
$
|
1.97
|
|
|
$
|
0.67
|
|
Diluted net income per limited partner unit
|
$
|
0.55
|
|
|
$
|
0.72
|
|
|
$
|
1.96
|
|
|
$
|
0.67
|
|
|
Quarter Ended 2016
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
(in thousands, except per unit amounts)
|
||||||||||||||
Total revenues
|
$
|
147,168
|
|
|
$
|
149,015
|
|
|
$
|
153,268
|
|
|
$
|
162,211
|
|
Operating income
|
$
|
63,966
|
|
|
$
|
55,307
|
|
|
$
|
67,511
|
|
|
$
|
73,830
|
|
Net income
|
$
|
48,796
|
|
|
$
|
89,270
|
|
|
$
|
65,429
|
|
|
$
|
71,394
|
|
Net income attributable to partners
|
$
|
47,755
|
|
|
$
|
88,160
|
|
|
$
|
64,345
|
|
|
$
|
70,264
|
|
Net income available to common unitholders
|
$
|
23,717
|
|
|
$
|
66,728
|
|
|
$
|
33,060
|
|
|
$
|
37,559
|
|
Basic net income per limited partner unit
|
$
|
0.35
|
|
|
$
|
0.93
|
|
|
$
|
0.45
|
|
|
$
|
0.52
|
|
Diluted net income per limited partner unit
|
$
|
0.35
|
|
|
$
|
0.92
|
|
|
$
|
0.45
|
|
|
$
|
0.51
|
|
Name
|
|
Age
|
|
Position with our General Partner
|
David G. Dehaemers, Jr.
|
|
57
|
|
President, Chief Executive Officer and Director
|
William R. Moler
|
|
52
|
|
Executive Vice President, Chief Operating Officer and Director
|
Gary J. Brauchle
|
|
44
|
|
Executive Vice President and Chief Financial Officer
|
Christopher R. Jones
|
|
41
|
|
Vice President, General Counsel and Secretary
|
Gary D. Watkins
|
|
45
|
|
Vice President and Chief Accounting Officer
|
Frank J. Loverro
|
|
48
|
|
Director
|
Stanley de J. Osborne
|
|
47
|
|
Director
|
Jeffrey A. Ball
|
|
43
|
|
Director
|
John T. Raymond
|
|
47
|
|
Director
|
Terrance D. Towner
|
|
59
|
|
Director
|
Roy N. Cook
|
|
60
|
|
Director
|
Jeffrey R. Armstrong
|
|
48
|
|
Director
|
•
|
Adjusted EBITDA of $620 - $680 million for the year ended
December 31, 2017
;
|
•
|
Distributable Cash Flow of $570 - $630 million for the year ended
December 31, 2017
;
|
•
|
Distribution coverage of 1.30x - 1.50x for the year ended
December 31, 2017
; and
|
•
|
Growth of approximately 20% in our annualized distribution rate for the calendar year
2017
.
|
•
|
Our Adjusted EBITDA for the year ended
December 31, 2017
was approximately
$678.0 million
;
|
•
|
Our Distributable Cash Flow for the year ended
December 31, 2017
was approximately
$611.3 million
;
|
•
|
Our distribution coverage for the year ended
December 31, 2017
was 1.47x; and
|
•
|
We grew our annualized distribution rate during calendar year
2017
by 18.4%.
|
•
|
The acquisitions from Tallgrass Development of a 24.99% membership interest in Rockies Express in March 2017 and 100% of the membership interests in Terminals and NatGas in January 2017;
|
•
|
Third-party acquisitions of the Douglas Gathering System in June 2017, the additional 40% membership interests Deeprock Development in July 2017, and the PRB Crude System in August 2017;
|
•
|
The contract extension with Continental Resources, Inc. through October 31, 2024 for transportation on the Pony Express System;
|
•
|
The commencement of new expansion projects, including the Platteville Extension Project on the Pony Express System and the Cheyenne Connector Pipeline; and
|
•
|
The amendment and restatement of our 1.75 billion revolving credit facility and senior note offerings of 2024 Notes and 2028 Notes in an aggregate of $1.1 billion.
|
|
Year
|
|
Salary
(1)
|
|
Bonus
(2)
|
|
Equity Awards
(3)
|
|
All Other Compensation
(4)
|
|
Total
|
||||||||||
David G. Dehaemers, Jr.
|
2017
|
|
$
|
300,000
|
|
|
$
|
1,000,739
|
|
|
$
|
—
|
|
|
$
|
28,152
|
|
|
$
|
1,328,891
|
|
President, Chief Executive
|
2016
|
|
$
|
300,000
|
|
|
$
|
651,467
|
|
|
$
|
—
|
|
|
$
|
27,544
|
|
|
$
|
979,011
|
|
Officer and Director
|
2015
|
|
$
|
300,000
|
|
|
$
|
601,000
|
|
|
$
|
—
|
|
|
$
|
27,796
|
|
|
$
|
928,796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
William R. Moler
|
2017
|
|
$
|
300,000
|
|
|
$
|
400,943
|
|
|
$
|
—
|
|
|
$
|
28,152
|
|
|
$
|
729,095
|
|
Executive Vice President, Chief
|
2016
|
|
$
|
300,000
|
|
|
$
|
576,468
|
|
|
$
|
—
|
|
|
$
|
24,544
|
|
|
$
|
901,012
|
|
Operating Officer and Director
|
2015
|
|
$
|
300,000
|
|
|
$
|
551,000
|
|
|
$
|
—
|
|
|
$
|
27,796
|
|
|
$
|
878,796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Gary J. Brauchle
|
2017
|
|
$
|
299,712
|
|
|
$
|
750,942
|
|
|
$
|
—
|
|
|
$
|
27,955
|
|
|
$
|
1,078,609
|
|
Executive Vice President and
|
2016
|
|
$
|
294,904
|
|
|
$
|
576,144
|
|
|
$
|
—
|
|
|
$
|
27,537
|
|
|
$
|
898,585
|
|
Chief Financial Officer
|
2015
|
|
$
|
275,000
|
|
|
$
|
551,000
|
|
|
$
|
—
|
|
|
$
|
27,665
|
|
|
$
|
853,665
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Christopher R. Jones
(5)
|
2017
|
|
$
|
271,569
|
|
|
$
|
750,942
|
|
|
$
|
3,545,100
|
|
|
$
|
27,686
|
|
|
$
|
4,595,297
|
|
Vice President, General Counsel
|
2016
|
|
$
|
240,068
|
|
|
$
|
426,467
|
|
|
$
|
69,836
|
|
|
$
|
24,486
|
|
|
$
|
760,857
|
|
and Secretary
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Gary D. Watkins
|
2017
|
|
$
|
224,922
|
|
|
$
|
248,435
|
|
|
$
|
1,378,650
|
|
|
$
|
23,356
|
|
|
$
|
1,875,363
|
|
Vice President and
|
2016
|
|
$
|
222,975
|
|
|
$
|
201,470
|
|
|
$
|
69,836
|
|
|
$
|
23,081
|
|
|
$
|
517,362
|
|
Chief Accounting Officer
|
2015
|
|
$
|
212,322
|
|
|
$
|
201,000
|
|
|
$
|
1,226,264
|
|
|
$
|
22,152
|
|
|
$
|
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.
|
(2)
|
Represents discretionary bonuses paid in
2018
,
2017
and
2016
based on performance in
2017
,
2016
and
2015
, respectively, as well as a bonus of $500 after tax that was paid to all employees in 2017, 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.
|
(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 2017 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, or EPSs, 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 EPUs and EPSs are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TEP's common units or 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 15
–
Equity-Based Compensation
. These amounts do not correspond to the actual value that will be recognized by the executive.
|
(4)
|
The amounts in the column include the following: contributions under the 401(k) savings plan (includes $27,000 for Mr. Dehaemers, $27,000 for Mr. Moler, $26,804 for Mr. Brauchle, $26,640 for Mr. Jones, and $22,492 for Mr. Watkins for the year ended December 31, 2017, $26,500 for Mr. Dehaemers, $26,500 for Mr. Moler, $26,500 for Mr. Brauchle, $23,629 for Mr. Jones, and $22,297 for Mr. Watkins for the year ended December 31, 2016, and $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 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.
|
|
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
|
|
8/2/17
|
|
|
90,000
|
|
(2)
|
$
|
3,545,100
|
|
and Secretary
|
TEGP Equity Participation Shares
|
|
—
|
|
|
—
|
|
(3)
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||
Gary D. Watkins
|
|
|
|
|
|
|
|
||||
Vice President and
|
TEP Equity Participation Units
|
|
8/2/17
|
|
|
35,000
|
|
(2)
|
$
|
1,378,650
|
|
Chief Accounting Officer
|
TEGP Equity Participation Shares
|
|
—
|
|
|
—
|
|
(3)
|
$
|
—
|
|
(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 15
–
Equity-Based Compensation
. 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 the earliest date on or after April 1, 2021, on which the average compounded annual distribution growth rate for our regular quarterly distributions, based upon the regular quarterly distribution paid by us on, or immediately prior to, such date is at least 5% over an annualized distribution rate of $3.34 per common unit, as determined by the board of directors of our general partner. If such date has not occurred by August 2, 2024, such equity participation units will expire and terminate and no vesting will occur.
|
(3)
|
There were no equity participation shares granted under the TEGP LTIP during the year ended December 31, 2017.
|
|
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
|
97,800
|
|
(3)
|
$
|
4,484,130
|
|
|
—
|
|
|
$
|
—
|
|
Gary D. Watkins
|
43,400
|
|
(4)
|
$
|
1,989,890
|
|
|
—
|
|
|
$
|
—
|
|
(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
$45.85
per TEP common unit at December 29, 2017.
|
(3)
|
Mr. Jones holds 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 as long as he meets the required continuing service obligations. The remaining 90,000 EPUs will vest on the earliest date on or after April 1, 2021, on which the average compounded annual distribution growth rate for our regular quarterly distributions, based upon the regular quarterly distribution
|
(4)
|
Mr. Watkins holds 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 as long as he meets the required continuing service obligations. The remaining 35,000 EPUs that will vest on the earliest date on or after April 1, 2021, on which the average compounded annual distribution growth rate for our regular quarterly distributions, based upon the regular quarterly distribution paid by us on, or immediately prior to, such date is at least 5% over an annualized distribution rate of $3.34 per common unit, as determined by the board of directors of our general partner. If such date has not occurred by August 2, 2024, these 35,000 EPUs will expire and terminate and no vesting will occur.
|
|
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
|
35,000
|
|
(3)
|
$
|
900,900
|
|
|
—
|
|
|
$
|
—
|
|
Gary D. Watkins
|
35,000
|
|
(3)
|
$
|
900,900
|
|
|
—
|
|
|
$
|
—
|
|
(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
$25.74
per TEGP Class A share at December 29, 2017.
|
(3)
|
Mr. Jones and Mr. Watkins each hold 35,000 equity participation shares that will vest on May 12, 2019 as long as they meet the required continuing service obligations.
|
|
Number of EPUs Acquired on Vesting
(1)
|
|
Value Realized on Vesting
(2)
|
|||
David G. Dehaemers, Jr.
|
—
|
|
|
$
|
—
|
|
President, Chief Executive
|
|
|
|
|||
Officer and Director
|
|
|
|
|||
|
|
|
|
|||
William R. Moler
|
33,333
|
|
|
$
|
1,675,983
|
|
Executive Vice President, Chief
|
|
|
|
|||
Operating Officer and Director
|
|
|
|
|||
|
|
|
|
|||
Gary J. Brauchle
|
33,333
|
|
|
$
|
1,675,983
|
|
Executive Vice President and
|
|
|
|
|||
Chief Financial Officer
|
|
|
|
|||
|
|
|
|
|||
Christopher R. Jones
|
16,000
|
|
|
$
|
804,480
|
|
Vice President, General Counsel
|
|
|
|
|||
and Secretary
|
|
|
|
|||
|
|
|
|
|||
Gary D. Watkins
|
16,666
|
|
|
$
|
837,966
|
|
Vice President and
|
|
|
|
|||
Chief Accounting Officer
|
|
|
|
(1)
|
Represents the gross number of EPUs that vested during the year ended
December 31, 2017
. The actual number of EPUs delivered to the Named Executive Officers was, in some cases, less than the number shown in the above table due to the Named Executive Officers' option to net out common units to cover a portion of applicable tax withholding obligations.
|
(2)
|
The stated value realized upon vesting is computed by multiplying the closing market price ($50.28) of our common units on the date they vested (May 13, 2017) by the number of units that vested.
|
•
|
"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.
|
•
|
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.
|
•
|
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.
|
•
|
a person other than certain designated persons directly or indirectly acquires direct or indirect ownership or control of 50% or more of the voting interests in our general partner, the ownership of fifty percent 50% or more of the general partner interests in TEP, or the ownership of such other rights or interests that grant to the owner or holder thereof the ability to direct the management or policies of TEP, whether through the ownership of voting rights, by contract, or otherwise;
|
•
|
our limited partners approve, in one or a series of transactions, a plan of complete liquidation of TEP; or
|
•
|
the sale or other disposition by TEP of all or substantially all of its assets in one or more transactions to any person other than our general partner and its affiliates.
|
(1)
|
The stated value upon a change in control is computed by assuming that a triggering change of control event occurred on December 29, 2017 and multiplying the closing market price (TEP:
$45.85
and TEGP:
$25.74
) of the relevant units and shares on such date by the number of units and shares that would have vested.
|
•
|
Quarterly cash payments of $10,000, resulting in an effective annual cash payment of $40,000.
|
•
|
For serving as the conflicts committee chair, a quarterly committee chair cash payment of $5,000.
|
Name and Principal Position
|
Fees Earned
|
|
EPU Awards
|
|
Non-Equity Incentive Plan Compensation
|
|
Total
|
||||||||
Terrance D. Towner
|
$
|
40,000
|
|
|
$
|
63,930
|
|
|
$
|
—
|
|
|
$
|
103,930
|
|
Roy N. Cook
|
$
|
60,000
|
|
|
$
|
63,930
|
|
|
$
|
—
|
|
|
$
|
123,930
|
|
Jeffrey R. Armstrong
|
$
|
40,000
|
|
|
$
|
63,930
|
|
|
$
|
—
|
|
|
$
|
103,930
|
|
•
|
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.
|
Name of Beneficial Owner
(1)
|
|
Common Units Beneficially Owned
(2)
|
|
Percentage of Common Units Beneficially Owned
|
||
Tallgrass Energy Holdings
(3)
|
|
25,619,218
|
|
|
35.00
|
%
|
Tortoise Capital Advisors, L.L.C.
(4)
|
|
7,206,390
|
|
|
9.84
|
%
|
Funds advised by ALPS Advisors, Inc.
(5)
|
|
3,910,660
|
|
|
5.34
|
%
|
Salient Capital Advisors, LLC
(6)
|
|
3,700,374
|
|
|
5.06
|
%
|
David G. Dehaemers, Jr.
(7)
|
|
573,206
|
|
|
*
|
|
William R. Moler
(8)
|
|
47,761
|
|
|
*
|
|
Gary J. Brauchle
(9)
|
|
62,113
|
|
|
*
|
|
Christopher R. Jones
|
|
20,615
|
|
|
*
|
|
Gary D. Watkins
|
|
17,893
|
|
|
*
|
|
Frank J. Loverro
|
|
—
|
|
|
—
|
|
Stanley de J. Osborne
|
|
—
|
|
|
—
|
|
Jeffrey A. Ball
|
|
20,000
|
|
|
*
|
|
John T. Raymond
|
|
100,000
|
|
|
*
|
|
Roy N. Cook
|
|
52,000
|
|
|
*
|
|
Terrance D. Towner
|
|
25,000
|
|
|
*
|
|
Jeffrey R. Armstrong
|
|
3,000
|
|
|
*
|
|
All directors and executive officers as a group (12 persons)
|
|
921,588
|
|
|
1.26
|
%
|
*
|
Less than 1%.
|
(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 that may be attributable to such directors and officers based on their indirect ownership of Tallgrass Equity.
|
(3)
|
Consists of common units held of record by Tallgrass Equity. 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 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; however, each disclaims beneficial ownership.
|
(4)
|
As reported on Schedule 13G filed with the SEC on July 7, 2017. Tortoise Capital Advisors, L.L.C. (“TCA”) acts as an investment advisor to certain investment companies registered under the Investment Company Act of 1940. TCA, by virtue of investment advisory agreements with these investment companies, has all investment and voting power over securities owned of record by these investment companies. However, despite their delegation of investment and voting power to TCA, these investment companies may be deemed to be the beneficial owner under Rule 13d-3 of the Act, of the
|
(5)
|
As reported on Schedule 13G filed with the SEC on February 6, 2018. ALPS Advisors, Inc. (“AAI”), an investment adviser registered under Section 203 of the Investment Advisors Act of 1940, furnishes investment advice to investment companies registered under the Investment Company Act of 1940 (collectively referred to as the “AAI Funds”). In its role as investment advisor, AAI has voting and/or investment power over the securities of TEP that are owned by the AAI Funds, and may be deemed to be the beneficial owner of the shares of TEP held by the AAI Funds. However, all securities reported in this schedule are owned by the AAI Funds. AAI disclaims beneficial ownership of such securities. In addition, the filing of the Schedule 13G shall not be construed as an admission that the reporting person or any of its affiliates is the beneficial owner of any securities covered by the Schedule 13G for any other purposes than Section 13(d) of the Securities Exchange Act of 1934. Alerian MLP ETF, which beneficially owns 3,887,310 common units, is an investment company registered under the Investment Company Act of 1940 and is one of the AAI Funds to which AAI provides investment advice. The business address for AAI and Alerian MLP ETF is 1290 Broadway, Suite 110, Denver, Colorado 80203.
|
(6)
|
As reported on Schedule 13G filed with the SEC on January 18, 2018. Consists of common units of record by Salient Capital Advisors, LLC. The business address for this person is 4265 San Felipe, 8th Floor, Houston, TX 77027.
|
(7)
|
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.
|
Plan Category
|
|
(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))
|
||||
Equity compensation plans approved by security holders
(1)
|
|
989,393
|
|
|
$
|
38.58
|
|
|
7,957,987
|
|
Equity compensation plans not approved by security holders
(2)
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
Total
|
|
989,393
|
|
|
$
|
38.58
|
|
|
7,957,987
|
|
(1)
|
Amounts shown represent equity participation unit awards outstanding under the TEP LTIP as of December 31, 2017. 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.
|
•
|
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 owned by Tallgrass Development Holdings, which currently only includes the 25.01% membership interest in Rockies Express, if Tallgrass Development Holdings decides to sell such assets to a non-affiliate.
|
|
Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
Audit fees
(1)
|
$
|
1,592
|
|
|
$
|
1,634
|
|
Audit related fees
(2)
|
—
|
|
|
—
|
|
||
Tax fees
(3)
|
520
|
|
|
445
|
|
||
Total
|
$
|
2,112
|
|
|
$
|
2,079
|
|
(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.
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions)
|
||||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
25.7
|
|
|
$
|
118.4
|
|
Accounts receivable, net
|
75.8
|
|
|
59.4
|
|
||
Regulatory assets
|
10.9
|
|
|
12.3
|
|
||
Gas imbalances
|
6.3
|
|
|
2.6
|
|
||
Other current assets
|
3.7
|
|
|
3.0
|
|
||
Total Current Assets
|
122.4
|
|
|
195.7
|
|
||
Property, plant and equipment, net
|
5,939.2
|
|
|
6,063.7
|
|
||
Deferred charges and other assets
|
11.8
|
|
|
15.6
|
|
||
Total Noncurrent Assets
|
5,951.0
|
|
|
6,079.3
|
|
||
Total Assets
|
$
|
6,073.4
|
|
|
$
|
6,275.0
|
|
|
|
|
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
20.3
|
|
|
$
|
38.1
|
|
Accrued interest
|
56.3
|
|
|
56.3
|
|
||
Accrued taxes
|
60.0
|
|
|
67.7
|
|
||
MFN revenue sharing liability
|
9.3
|
|
|
9.4
|
|
||
Current portion of long-term debt
|
550.0
|
|
|
—
|
|
||
Construction advances
|
6.8
|
|
|
11.7
|
|
||
Accrued other current liabilities
|
11.3
|
|
|
4.9
|
|
||
Total Current Liabilities
|
714.0
|
|
|
188.1
|
|
||
Long-term Liabilities and Deferred Credits:
|
|
|
|
||||
Long-term debt
|
2,014.8
|
|
|
2,561.7
|
|
||
Other long-term liabilities and deferred credits
|
34.5
|
|
|
95.2
|
|
||
Total Long-term Liabilities and Deferred Credits
|
2,049.3
|
|
|
2,656.9
|
|
||
|
|
|
|
||||
Commitments and Contingencies
|
|
|
|
||||
|
|
|
|
||||
Members' Equity:
|
|
|
|
||||
Members' equity
|
3,310.1
|
|
|
3,430.0
|
|
||
Total Liabilities and Members' Equity
|
$
|
6,073.4
|
|
|
$
|
6,275.0
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Transportation services
|
$
|
839.6
|
|
|
$
|
715.1
|
|
|
$
|
779.0
|
|
Natural gas sales
|
9.6
|
|
|
—
|
|
|
2.1
|
|
|||
Total Revenues
|
849.2
|
|
|
715.1
|
|
|
781.1
|
|
|||
Operating Costs and Expenses:
|
|
|
|
|
|
||||||
Cost of transportation services
|
29.8
|
|
|
26.5
|
|
|
30.2
|
|
|||
Cost of natural gas sales
|
7.3
|
|
|
—
|
|
|
2.3
|
|
|||
Operations and maintenance
|
25.3
|
|
|
24.8
|
|
|
21.2
|
|
|||
Depreciation and amortization
|
218.4
|
|
|
204.3
|
|
|
199.4
|
|
|||
General and administrative
|
30.5
|
|
|
39.9
|
|
|
26.7
|
|
|||
Taxes, other than income taxes
|
65.3
|
|
|
71.9
|
|
|
73.9
|
|
|||
Total Operating Costs and Expenses
|
376.6
|
|
|
367.4
|
|
|
353.7
|
|
|||
Operating Income
|
472.6
|
|
|
347.7
|
|
|
427.4
|
|
|||
|
|
|
|
|
|
||||||
Other (Expense) Income:
|
|
|
|
|
|
||||||
Interest expense, net
|
(168.0
|
)
|
|
(158.6
|
)
|
|
(170.1
|
)
|
|||
Gain on litigation settlement
|
150.0
|
|
|
61.7
|
|
|
—
|
|
|||
Other income, net
|
3.4
|
|
|
27.7
|
|
|
6.6
|
|
|||
Total Other Expense, net
|
(14.6
|
)
|
|
(69.2
|
)
|
|
(163.5
|
)
|
|||
Net Income to Members
|
$
|
458.0
|
|
|
$
|
278.5
|
|
|
$
|
263.9
|
|
|
Total
|
|
Rockies Express Holdings, LLC
|
|
TEP REX Holdings, LLC
|
|
Sempra REX Holdings, LLC
|
|
P66 REX LLC
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Members' Equity:
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance at January 1, 2015
|
$
|
2,820.2
|
|
|
$
|
1,410.0
|
|
|
$
|
—
|
|
|
$
|
705.1
|
|
|
$
|
705.1
|
|
Net Income to Members
|
263.9
|
|
|
131.9
|
|
|
—
|
|
|
66.0
|
|
|
66.0
|
|
|||||
Contributions from Members
|
733.1
|
|
|
366.5
|
|
|
—
|
|
|
183.3
|
|
|
183.3
|
|
|||||
Distributions to Members
|
(499.0
|
)
|
|
(249.4
|
)
|
|
—
|
|
|
(124.8
|
)
|
|
(124.8
|
)
|
|||||
Balance at December 31, 2015
|
$
|
3,318.2
|
|
|
$
|
1,659.0
|
|
|
$
|
—
|
|
|
$
|
829.6
|
|
|
$
|
829.6
|
|
Net Income to Members
|
278.5
|
|
|
139.3
|
|
|
42.6
|
|
|
27.0
|
|
|
69.6
|
|
|||||
Contributions from Members
|
304.9
|
|
|
152.5
|
|
|
50.0
|
|
|
26.2
|
|
|
76.2
|
|
|||||
Distributions to Members
|
(471.6
|
)
|
|
(235.8
|
)
|
|
(75.9
|
)
|
|
(42.0
|
)
|
|
(117.9
|
)
|
|||||
Transfer of equity interest
|
—
|
|
|
—
|
|
|
840.8
|
|
|
(840.8
|
)
|
|
—
|
|
|||||
Balance at December 31, 2016
|
$
|
3,430.0
|
|
|
$
|
1,715.0
|
|
|
$
|
857.5
|
|
|
$
|
—
|
|
|
$
|
857.5
|
|
Net Income to Members
|
458.0
|
|
|
131.1
|
|
|
212.4
|
|
|
—
|
|
|
114.5
|
|
|||||
Contributions from Members
|
92.0
|
|
|
29.7
|
|
|
39.3
|
|
|
—
|
|
|
23.0
|
|
|||||
Distributions to Members
|
(669.9
|
)
|
|
(197.6
|
)
|
|
(304.8
|
)
|
|
—
|
|
|
(167.5
|
)
|
|||||
Transfer of equity interest (see Note 1)
|
—
|
|
|
(850.3
|
)
|
|
850.3
|
|
|
—
|
|
|
—
|
|
|||||
Balance at December 31, 2017
|
$
|
3,310.1
|
|
|
$
|
827.9
|
|
|
$
|
1,654.7
|
|
|
$
|
—
|
|
|
$
|
827.5
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Cash Flows from Operating Activities:
|
|
|
|
|
|
||||||
Net income to Members
|
$
|
458.0
|
|
|
$
|
278.5
|
|
|
$
|
263.9
|
|
Adjustments to reconcile net income to net cash flows provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
223.7
|
|
|
209.6
|
|
|
204.8
|
|
|||
Changes in components of working capital:
|
|
|
|
|
|
||||||
Accounts receivable
|
(25.4
|
)
|
|
28.2
|
|
|
(23.8
|
)
|
|||
Current regulatory assets and liabilities, net
|
3.4
|
|
|
(12.5
|
)
|
|
(10.2
|
)
|
|||
Accounts payable
|
(7.0
|
)
|
|
12.2
|
|
|
3.7
|
|
|||
Accrued taxes
|
(7.6
|
)
|
|
(0.6
|
)
|
|
3.7
|
|
|||
Other current assets and liabilities
|
—
|
|
|
(0.7
|
)
|
|
(0.9
|
)
|
|||
Return of customer deposits
|
(55.7
|
)
|
|
—
|
|
|
—
|
|
|||
Receipt of customer deposits
|
5.8
|
|
|
52.9
|
|
|
32.2
|
|
|||
Other operating, net
|
1.1
|
|
|
(22.5
|
)
|
|
(3.0
|
)
|
|||
Net Cash Provided by Operating Activities
|
596.3
|
|
|
545.1
|
|
|
470.4
|
|
|||
Cash Flows from Investing Activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(108.9
|
)
|
|
(305.7
|
)
|
|
(281.9
|
)
|
|||
Other investing, net
|
(2.2
|
)
|
|
(2.3
|
)
|
|
(1.9
|
)
|
|||
Net Cash Used in Investing Activities
|
(111.1
|
)
|
|
(308.0
|
)
|
|
(283.8
|
)
|
|||
Cash Flows from Financing Activities:
|
|
|
|
|
|
||||||
Distributions to Members
|
(669.9
|
)
|
|
(471.6
|
)
|
|
(499.0
|
)
|
|||
Contributions from Members
|
92.0
|
|
|
304.9
|
|
|
733.1
|
|
|||
Repayment of debt
|
—
|
|
|
—
|
|
|
(450.0
|
)
|
|||
Payments for deferred financing costs
|
—
|
|
|
—
|
|
|
(0.7
|
)
|
|||
Net Cash Used in Financing Activities
|
(577.9
|
)
|
|
(166.7
|
)
|
|
(216.6
|
)
|
|||
Net Change in Cash and Cash Equivalents
|
(92.7
|
)
|
|
70.4
|
|
|
(30.0
|
)
|
|||
Cash and Cash Equivalents, beginning of period
|
118.4
|
|
|
48.0
|
|
|
78.0
|
|
|||
Cash and Cash Equivalents, end of period
|
$
|
25.7
|
|
|
$
|
118.4
|
|
|
$
|
48.0
|
|
Supplemental Disclosures:
|
|
|
|
|
|
||||||
Cash payments for interest, net
|
$
|
(164.9
|
)
|
|
$
|
(155.6
|
)
|
|
$
|
(170.7
|
)
|
Schedule of Noncash Investing and Financing Activities:
|
|
|
|
|
|
||||||
Increase in accrual for payment of property, plant and equipment
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8.4
|
|
•
|
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.
|
•
|
49.99%
- TEP REX Holdings, LLC ("TEP REX"), an indirect wholly owned subsidiary of Tallgrass Energy Partners, LP ("TEP");
|
•
|
25.01%
- Rockies Express Holdings, LLC ("REX Holdings"), an indirect wholly owned subsidiary of Tallgrass Development, LP ("TD"); and
|
•
|
25%
- P66REX LLC, a wholly owned subsidiary of Phillips 66.
|
•
|
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;
|
•
|
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.
|
•
|
Rockies Express management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status.
|
•
|
Rockies Express management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts.
|
•
|
Rockies Express management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process.
|
•
|
Rockies Express management plans to provide internal training and awareness related to the revised guidance to the key stakeholders throughout its organization.
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions)
|
||||||
Natural gas pipelines
|
$
|
7,661.2
|
|
|
$
|
7,085.8
|
|
General and other
|
15.4
|
|
|
9.9
|
|
||
Construction work in progress
|
11.9
|
|
|
503.2
|
|
||
Accumulated depreciation and amortization
|
(1,749.3
|
)
|
|
(1,535.2
|
)
|
||
Total property, plant and equipment, net
|
$
|
5,939.2
|
|
|
$
|
6,063.7
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions)
|
||||||
6.85% senior notes due July 15, 2018
|
$
|
550.0
|
|
|
$
|
550.0
|
|
6.00% senior notes due January 15, 2019
|
525.0
|
|
|
525.0
|
|
||
5.625% senior notes due April 15, 2020
|
750.0
|
|
|
750.0
|
|
||
7.50% senior notes due July 15, 2038
|
250.0
|
|
|
250.0
|
|
||
6.875% senior notes due April 15, 2040
|
500.0
|
|
|
500.0
|
|
||
Less: Unamortized debt discount and deferred financing costs
|
(10.2
|
)
|
|
(13.3
|
)
|
||
Total debt
|
2,564.8
|
|
|
2,561.7
|
|
||
Less: Current portion
|
(550.0
|
)
|
|
—
|
|
||
Total long-term debt
|
$
|
2,014.8
|
|
|
$
|
2,561.7
|
|
Year
|
|
Scheduled Maturities
|
||
2018
|
|
$
|
550.0
|
|
2019
|
|
525.0
|
|
|
2020
|
|
750.0
|
|
|
2021
|
|
—
|
|
|
2022
|
|
—
|
|
|
Thereafter
|
|
750.0
|
|
|
Total scheduled maturities
|
|
2,575.0
|
|
|
Unamortized debt discount and deferred financing costs
|
|
(10.2
|
)
|
|
Total debt
|
|
$
|
2,564.8
|
|
•
|
incurring secured indebtedness;
|
•
|
entering into mergers, consolidations and sales of assets;
|
•
|
granting liens;
|
•
|
entering into transactions with affiliates; and
|
•
|
making restricted payments.
|
|
Fair Value
|
|
|
||||||||||||||||
|
Quoted prices in active markets for identical assets
(Level 1) |
|
Significant other observable inputs
(Level 2) |
|
Significant unobservable inputs
(Level 3) |
|
Total
|
|
Carrying
Amount |
||||||||||
|
(in millions)
|
|
|
||||||||||||||||
December 31, 2017
|
$
|
—
|
|
|
$
|
2,752.1
|
|
|
$
|
—
|
|
|
$
|
2,752.1
|
|
|
$
|
2,564.8
|
|
December 31, 2016
|
$
|
—
|
|
|
$
|
2,684.9
|
|
|
$
|
—
|
|
|
$
|
2,684.9
|
|
|
$
|
2,561.7
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Revenues: Transportation services
(1)
|
$
|
—
|
|
|
$
|
14.4
|
|
|
$
|
10.8
|
|
Charges from TD:
|
|
|
|
|
|
||||||
Compensation, benefits and other charges
|
$
|
18.6
|
|
|
$
|
20.6
|
|
|
$
|
18.5
|
|
General and administrative charges from affiliate
|
$
|
8.9
|
|
|
$
|
9.4
|
|
|
$
|
8.6
|
|
Management Fees:
|
|
|
|
|
|
||||||
Tallgrass NatGas Operator, LLC
|
$
|
8.5
|
|
|
$
|
6.2
|
|
|
$
|
6.3
|
|
(1)
|
Transportation services revenue for the
years ended
December 31, 2016
and
2015
is primarily from Sempra Energy prior to the May 6, 2016 sale of Sempra Energy's ownership to TEP REX.
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions)
|
||||||
Payables to affiliated companies:
|
|
|
|
||||
TD
|
$
|
2.3
|
|
|
4.5
|
|
|
TEP
|
1.3
|
|
|
0.6
|
|
||
Total payables to affiliated companies
|
$
|
3.6
|
|
|
$
|
5.1
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions)
|
||||||
Affiliate gas imbalance receivables
|
$
|
0.4
|
|
|
$
|
—
|
|
Affiliate gas imbalance payables
|
$
|
—
|
|
|
$
|
0.2
|
|
Year
|
|
Future Minimum Lease Payments
|
||
2018
|
|
$
|
29.2
|
|
2019
|
|
29.2
|
|
|
2020
|
|
29.2
|
|
|
2021
|
|
29.2
|
|
|
2022
|
|
29.2
|
|
|
Thereafter
|
|
146.0
|
|
|
Total
|
|
$
|
292.0
|
|
Exhibit No.
|
|
Description
|
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
101.INS*
|
|
XBRL Instance Document.
|
|
|
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document.
|
|
|
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
|
|
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
|
|
|
101.LAB*
|
|
XBRL Taxonomy Extension Label Linkbase Document.
|
|
|
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
* -
|
filed herewith
|
† -
|
Management contract of compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b).
|
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)
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ David G. Dehaemers, Jr.
|
|
Director, President and Chief Executive Officer
|
|
February 13, 2018
|
David G. Dehaemers, Jr.
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Gary J. Brauchle
|
|
Executive Vice President and Chief Financial Officer
|
|
February 13, 2018
|
Gary J. Brauchle
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ Gary D. Watkins
|
|
Vice President and Chief Accounting Officer
|
|
February 13, 2018
|
Gary D. Watkins
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Frank J. Loverro
|
|
Director
|
|
February 13, 2018
|
Frank J. Loverro
|
|
|
|
|
|
|
|
|
|
/s/ Stanley de J. Osborne
|
|
Director
|
|
February 13, 2018
|
Stanley de J. Osborne
|
|
|
|
|
|
|
|
|
|
/s/ Jeffrey A. Ball
|
|
Director
|
|
February 13, 2018
|
Jeffrey A. Ball
|
|
|
|
|
|
|
|
|
|
/s/ John T. Raymond
|
|
Director
|
|
February 13, 2018
|
John T. Raymond
|
|
|
|
|
|
|
|
|
|
/s/ William R. Moler
|
|
Director
|
|
February 13, 2018
|
William R. Moler
|
|
|
|
|
|
|
|
|
|
/s/ Terrance D. Towner
|
|
Director
|
|
February 13, 2018
|
Terrance D. Towner
|
|
|
|
|
|
|
|
|
|
/s/ Roy N. Cook
|
|
Director
|
|
February 13, 2018
|
Roy N. Cook
|
|
|
|
|
|
|
|
|
|
/s/ Jeffrey R. Armstrong
|
|
Director
|
|
February 13, 2018
|
Jeffrey R. Armstrong
|
|
|
|
|
|
TEP
(1)
|
||||||||||||||||||
|
Year Ended December 31,
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Earnings from continuing operations before fixed charges:
|
|
|
|
|
|
|
|
|
|
||||||||||
Pre-tax income from continuing operations before earnings from unconsolidated affiliates
|
$
|
203,379
|
|
|
$
|
220,358
|
|
|
$
|
194,413
|
|
|
$
|
64,169
|
|
|
$
|
12,971
|
|
Fixed charges
|
87,791
|
|
|
51,306
|
|
|
25,437
|
|
|
11,626
|
|
|
13,360
|
|
|||||
Amortization of capitalized interest
|
80
|
|
|
65
|
|
|
66
|
|
|
35
|
|
|
—
|
|
|||||
Distributed earnings from unconsolidated affiliates
|
237,192
|
|
|
54,449
|
|
|
3,096
|
|
|
1,280
|
|
|
—
|
|
|||||
less: Capitalized interest
|
(964
|
)
|
|
(471
|
)
|
|
(811
|
)
|
|
(1,025
|
)
|
|
(242
|
)
|
|||||
Earnings from continuing operations before fixed charges
|
$
|
527,478
|
|
|
$
|
325,707
|
|
|
$
|
222,201
|
|
|
$
|
76,085
|
|
|
$
|
26,089
|
|
Fixed charges:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net of capitalized interest
|
79,167
|
|
|
37,189
|
|
|
14,226
|
|
|
7,648
|
|
|
11,264
|
|
|||||
Capitalized interest
|
964
|
|
|
471
|
|
|
811
|
|
|
1,025
|
|
|
242
|
|
|||||
Estimate of interest within rental expense (33.3%)
|
3,148
|
|
|
10,032
|
|
|
8,615
|
|
|
1,574
|
|
|
109
|
|
|||||
Amortization of debt costs
|
4,512
|
|
|
3,614
|
|
|
1,785
|
|
|
1,379
|
|
|
1,745
|
|
|||||
Total fixed charges
|
$
|
87,791
|
|
|
$
|
51,306
|
|
|
$
|
25,437
|
|
|
$
|
11,626
|
|
|
$
|
13,360
|
|
Ratio of earnings to fixed charges
(2)
|
6.01
|
|
|
6.35
|
|
|
8.74
|
|
|
6.54
|
|
|
1.95
|
|
(1)
|
TEP closed the acquisition of Trailblazer on April 1, 2014, the acquisition of a controlling 33.3% membership interest in Pony Express effective September 1, 2014, and the acquisitions of Terminals and NatGas effective January 1, 2017. As these acquisitions 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, the initial 33.3% of Pony Express, and Terminals and NatGas. TEP closed the acquisitions of an additional 33.3% and 31.3% membership interests in Pony Express effective March 1, 2015 and January 1, 2016, respectively, which 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 has not been recast to reflect the additional 33.3% and 31.3% membership interests.
|
(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.
|
Company
|
Jurisdiction of Organization
|
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
|
BNN Great Plains, LLC
|
Delaware
|
Stanchion Energy, LLC
|
Delaware
|
Tallgrass Midstream Gathering, LLC
|
Colorado
|
Deeprock Development, LLC
|
Delaware
|
Tallgrass Crude Gathering, LLC
|
Delaware
|
Tallgrass Cheyenne Connector Holdings, LLC
|
Delaware
|
Cheyenne Connector, LLC
|
Delaware
|
Cheyenne Connector Pipeline, Inc.
|
Colorado
|
Buckhorn Energy Services, LLC
|
Delaware
|
Buckhorn SWD Solutions, LLC
|
Delaware
|
Tallgrass Operations, LLC
|
Delaware
|
Tallgrass Iron Horse Holdings, LLC
|
Delaware
|
Tallgrass Iron Horse Operator, LLC
|
Delaware
|
Iron Horse Pipeline, LLC
|
Delaware
|
1.
|
I have reviewed this Annual Report on Form 10-K of Tallgrass Energy Partners, LP;
|
2.
|
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;
|
3.
|
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;
|
4.
|
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)
|
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;
|
b)
|
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;
|
c)
|
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
|
d)
|
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)
|
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
|
b)
|
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)
|
1.
|
I have reviewed this Annual Report on Form 10-K of Tallgrass Energy Partners, LP;
|
2.
|
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;
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3.
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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;
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4.
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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:
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a)
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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;
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b)
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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;
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c)
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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
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d)
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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
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5.
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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):
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a)
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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
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b)
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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.
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By:
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/s/ Gary J. Brauchle
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Gary J. Brauchle
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Executive Vice President and Chief Financial Officer of Tallgrass MLP GP, LLC (the general partner of Tallgrass Energy Partners, LP)
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1.
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
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2.
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
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By:
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/s/ David G. Dehaemers, Jr.
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David G. Dehaemers, Jr.
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President and Chief Executive Officer of Tallgrass MLP GP, LLC (the general partner of Tallgrass Energy Partners, LP)
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1.
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
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2.
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
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By:
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/s/Gary J. Brauchle
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Gary J. Brauchle
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Executive Vice President and Chief Financial Officer of Tallgrass MLP GP, LLC (the general partner of Tallgrass Energy Partners, LP)
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