10-K 1 tegp2015123110k.htm 10-K 10-K



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
 
 
FORM 10-K
 
 
 
 (Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2015
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-37365
 
 
 
 
 Tallgrass Energy GP, LP
(Exact name of registrant as specified in its charter)
 
 
 
Delaware
 
 
 
46-3159268
(State or other Jurisdiction of Incorporation or Organization)
 
 
 
(IRS Employer Identification Number)
 
 
 
 
 
4200 W. 115th Street, Suite 350
 
 
 
 
Leawood, Kansas
 
 
 
66211
(Address of Principal Executive Offices)
 
 
 
(Zip Code)
(913) 928-6060
(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Class A Shares Representing Limited Partner Interests
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
 
 
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  ¨    No  ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  ¨    No  ý Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer", and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
 
¨
  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
x (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
The aggregate market value of voting and non-voting common equity held by non-affiliates on June 30, 2015, the last business day of the Registrant’s most recently completed second fiscal quarter (based on the closing sale price of $32.15 of the Registrant’s Class A shares, as reported by the New York Stock Exchange on such date) was approximately $1,512.6 million.
On February 17, 2016, the Registrant had 47,725,000 Class A shares and 109,504,440 Class B shares outstanding.





TALLGRASS ENERGY GP, LP
TABLE OF CONTENTS
 





Glossary of Common Industry and Measurement Terms
Bakken oil production area: Montana and North Dakota in the United States and Saskatchewan and Manitoba in Canada.
Barrel (or bbl): forty two U.S. gallons.
Base Gas (or Cushion Gas): the volume of gas that is intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates.
BBtu: one billion British Thermal Units.
Bcf: one billion cubic feet.
British Thermal Units or Btus: the amount of heat energy needed to raise the temperature of one pound of water by one degree Fahrenheit.
Commodity sensitive contracts or arrangements: contracts or other arrangements, including tariff provisions, that directly expose our cash flows to increases and decreases in the price of commodities such as crude oil, natural gas and NGLs. Examples are Keep Whole Processing Contracts and Percent of Proceeds Processing Contracts, as well as pipeline loss allowances on our pipelines.
Condensate: a NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
Contract barrels: barrels of crude oil that our customers have contractually agreed to ship in exchange for firm service assurance of capacity and deliverability to delivery points.
Delivery point: any point at which product in a pipeline is delivered to or for the account of a customer.
Dry gas: a gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.
Dth: a dekatherm, which is a unit of energy equal to 10 therms or one million British thermal units.
End-user markets: the ultimate users and consumers of transported energy products.
EPA: the United States Environmental Protection Agency.
FERC: Federal Energy Regulatory Commission.
Firm fee contracts: firm fee contracts generally obligate our customers to pay a fixed recurring charge to reserve an agreed upon amount of capacity and/or deliverability on our assets, regardless if the contracted capacity is actually used by the customer. Such contracts are also commonly known as "take-or-pay" contracts.
Firm services: services pursuant to which customers receive firm assurances regarding the availability of capacity and/or deliverability of natural gas, crude oil or other hydrocarbons or water on our assets up to a contracted amount.
Fractionation: the process by which NGLs are further separated into individual, typically more valuable components including ethane, propane, butane, isobutane and natural gasoline.
GAAP: generally accepted accounting principles in the United States of America.
GHGs: greenhouse gases.
Header system: networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large diameter high pressure long-haul transportation pipelines.
Interruptible services: services pursuant to which customers receive limited, or no, assurances regarding the availability of capacity and deliverability in our assets.
Keep Whole Processing Contracts: natural gas processing contracts in which we are required to replace the Btu content of the NGLs extracted from inlet wet gas processed with purchased dry natural gas.
Line fill: the volume of oil, in barrels, in the pipeline from the origin to the destination.





Liquefied natural gas or LNG: natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.
Local distribution company or LDC: LDCs are involved in the delivery of natural gas to consumers within a specific geographic area.
Long-term: with respect to any contract, a contract with an initial duration greater than one year.
MMBtu: one million British Thermal Units.
Mcf: one thousand cubic feet.
MMcf: one million cubic feet.
Natural gas liquids or NGLs: those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).
Natural Gas Processing: the separation of natural gas into pipeline-quality natural gas and a mixed NGL stream.
Non-contract barrels (or walk-up barrels): barrels of crude oil that our customers ship based solely on availability of capacity and deliverability with no assurance of future capacity.
No-notice service: those services pursuant to which customers receive the right to transport or store natural gas on assets outside of the daily nomination cycle without incurring penalties.
NYMEX: New York Mercantile Exchange.
Park and loan services: those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our facilities on a seasonal basis.
Percent of Proceeds Processing Contracts: natural gas processing contracts in which we process our customer’s natural gas, sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. Some percent of proceeds contracts may also require our customers to pay a monthly reservation fee for processing capacity.
PHMSA: the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration.
Play: a proven geological formation that contains commercial amounts of hydrocarbons.
Produced water: all water removed from a well as a byproduct of the production of hydrocarbons and water removed from a well in connection with operations being conducted on the well, including naturally occurring water in the recovery formation, flow back water recovered during completion and fracturing operations and water entering the recovery formation through water flooding techniques.
Receipt point: the point where a product is received by or into a gathering system, processing facility, or transportation pipeline.
Reservoir: a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (such as crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.
Residue gas: the natural gas remaining after being processed or treated.
Shale gas: natural gas produced from organic (black) shale formations.
Tailgate: the point at which processed natural gas and NGLs leave a processing facility for transportation to end-user markets.
TBtu: one trillion British Thermal Units.
Tcf: one trillion cubic feet.





Throughput: the volume of products, such as crude oil, natural gas or water, transported or passing through a pipeline, plant, terminal or other facility during a particular period.
Uncommitted shippers (or walk-up shippers): customers that have not signed long-term shipper contracts and have rights under the FERC tariff as to rates and capacity allocation that are different than long-term committed shippers.
Volumetric fee contracts: volumetric fee contracts generally obligate a customer to pay fees based upon the extent to which such customer utilizes our assets for midstream energy services. Unlike firm fee contracts, under volumetric fee contracts our customers are not generally required to pay a charge to reserve an agreed upon amount of capacity and/or deliverability.
Wellhead: the equipment at the surface of a well that is used to control the well’s pressure; also, the point at which the hydrocarbons and water exit the ground.
Working gas: the volume of gas in the storage reservoir that is in addition to the cushion or base gas. It may or may not be completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be used more than once during any season.
Working gas storage capacity: the maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes base gas and non-cycling working gas.
X/d: the applicable measurement metric per day. For example, MMcf/d means one million cubic feet per day.





PART I

As used in this Annual Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEGP" and similar terms refer to Tallgrass Energy GP, LP, in its individual capacity or to Tallgrass Energy GP, LP and its consolidated subsidiaries collectively (including Tallgrass Equity, TEP and their respective subsidiaries), as the context requires. The term our "general partner" refers to TEGP Management, LLC. References to "Tallgrass Development" or "TD" refer to Tallgrass Development, LP. References to "Kelso" are to Kelso & Company and its affiliated investment funds and, as the context may require, other entities under its control, and references to "EMG" are to The Energy & Minerals Group, its affiliated investment funds and, as the context may require, other entities under its control.
A reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8.Financial Statements and Supplementary Data. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.
Cautionary Statement Regarding Forward-Looking Statements
This Annual Report and the documents incorporated by reference herein contain forward-looking statements concerning our operations, economic performance and financial condition. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "could," "will," "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our and Tallgrass Development’s infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
our ability to complete and integrate acquisitions from Tallgrass Development or from third parties, including our acquisition of water business assets in Weld County, Colorado that was completed in December 2015 and our purchase of an additional 31.3% interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express") that was completed in January 2016;
changes in general economic conditions;
competitive conditions in our industry;
actions taken by third-party operators, processors and transporters;
the demand for our services, including crude oil transportation services, natural gas transportation, storage and processing services and water business services;
our ability to successfully implement our business plan;
our ability to complete internal growth projects on time and on budget;
the price and availability of debt and equity financing;
the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil, natural gas, NGLs, and other hydrocarbons;
the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the price of alternative and competing fuels;
competition from the same and alternative energy sources;
energy efficiency and technology trends;

1




operating hazards and other risks incidental to transporting crude oil, transporting, storing and processing natural gas, and transporting, gathering and disposing of water produced in connection with hydrocarbon exploration and production activities;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
interest rates;
labor relations;
large or multiple customer defaults;
changes in tax status;
the effects of existing and future laws and governmental regulations;
the effects of future litigation; and
certain factors discussed elsewhere in this Annual Report.
Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.
Item 1. Business
Overview
TEGP is a limited partnership formed in 2015 that has elected to be treated as a corporation for U.S. federal income tax purposes. We were formed as part of a reorganization involving entities that were previously controlled by Tallgrass Equity, LLC ("Tallgrass Equity"), in order to effect the initial public offering of our Class A shares (the "Offering"). The Offering was completed on May 12, 2015.
Our sole cash-generating asset is an approximate 30.35% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of the direct and indirect partnership interests in Tallgrass Energy Partners, LP, a Delaware limited partnership ("TEP"), described below:
Tallgrass Equity owns 100% of the outstanding membership interests in Tallgrass MLP GP, LLC ("TEP GP"), which owns all of the general partner interest in TEP and all of TEP's incentive distribution rights ("IDRs"). The general partner interest in TEP is represented by 834,391 general partner units, representing an approximate 1.23% general partner interest in TEP at February 17, 2016.
Tallgrass Equity owns 20,000,000 TEP common units, representing an approximately 29.41% limited partner interest in TEP at February 17, 2016.
TEP is a publicly traded, growth-oriented limited partnership formed in 2013 to own, operate, acquire and develop midstream energy assets in North America. TEP currently provides crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Pony Express, which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). TEP provides natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). TEP also provides services for customers in Wyoming at the Casper and Douglas natural gas processing facilities and the West Frenchie Draw natural gas treating facility (collectively, the "Midstream Facilities"), and NGL transportation services in Northeast Colorado. TEP performs water business services in Colorado and Texas through BNN Water Solutions, LLC ("Water Solutions"). TEP's operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations.
TEP intends to continue to leverage its relationship with Tallgrass Development and utilize the significant experience of its management team to execute its growth strategy of acquiring midstream assets from Tallgrass Development and third parties, increasing utilization of its existing assets and expanding its systems through construction of additional assets. TEP's reportable business segments are:
Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system;

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Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and
Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, the provision of water business services primarily to the oil and gas exploration and production industry and the transportation of NGLs.
Additional segment and financial information is contained in TEP's segment results included in Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations and the notes to our consolidated financial statements included in Item 8.—Financial Statements and Supplementary Data of this Annual Report.
TEP's Assets
TEP's assets primarily consist of the Pony Express System, the TIGT System, the Trailblazer Pipeline, the Midstream Facilities, and Water Solutions, each of which is described in more detail below. The following map shows the Pony Express System, the TIGT System, the Trailblazer Pipeline, the Midstream Facilities, and TEP's Northeast Colorado and NGL infrastructure, which includes TEP's NGL transportation line and Water Solutions' freshwater delivery and storage and produced water gathering and disposal systems.
Crude Oil Transportation & Logistics Segment
Pony Express. The Pony Express System is an approximately 764-mile crude oil pipeline commencing in Guernsey, Wyoming, and terminating in Cushing, Oklahoma, with delivery points at the Ponca City Refinery and in Cushing, Oklahoma. It includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado. As of December 31, 2015, TEP owned a 66.7% membership interest in Pony Express, but effective January 1, 2016, TEP acquired an additional 31.3% membership interest, bringing its total membership interest in Pony Express to 98.0%. For the year ended December 31, 2015, Continental Resources and Shell Trading (US) Company ("Shell") accounted for approximately 28% and 19% of TEP's segment revenue in the Crude Oil Transportation & Logistics segment, respectively, and approximately 16% and 15% of TEP's revenues on a consolidated basis, respectively.

3




The table below sets forth certain information regarding TEP's Crude Oil Transportation & Logistics segment as of December 31, 2015 and for the three months ended December 31, 2015:
Approximate Design Capacity (bbls/d) (1)
 
Approximate Contractible Capacity Under Contract (2)
 
Weighted Average Remaining Firm Contract Life (3)
 
Approximate Average Daily Throughput (bbls/d) (4)
320,000

 
100
%
 
4 years
 
288,362

(1) 
Excludes additional capacity related to the Pony Express System's ability to inject drag reducing agent, which is an additive that increases pipeline flow efficiency.
(2) 
TEP is required to make no less than 10% of design capacity available for non-contract, or "walk-up", shippers. Approximately 100% of the remaining design capacity (or available contractible capacity) is committed under contract.
(3) 
Based on the average annual reservation capacity for each such contract's remaining life.
(4) 
Approximate average daily throughput for the year ended December 31, 2015 was 236,256 bbls/d and is reflective of 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.
Natural Gas Transportation & Logistics Segment
TIGT System. The TIGT System is a FERC-regulated natural gas transportation and storage system with approximately 4,655 miles of varying diameter transportation pipelines serving Wyoming, Colorado, Kansas, Missouri and Nebraska. The TIGT System includes the Huntsman natural gas storage facility located in Cheyenne County, Nebraska. The TIGT System primarily provides transportation and storage services to on-system customers such as local distribution companies and industrial users, including ethanol plants, and irrigation and grain drying operations, which depend on the TIGT System’s interconnections to their facilities to meet their demand for natural gas and a majority of whom pay FERC-approved recourse rates. For the year ended December 31, 2015, approximately 87% of the TIGT System's transportation revenue was generated from contracts with on-system customers.
Trailblazer Pipeline. The Trailblazer Pipeline is a FERC-regulated natural gas pipeline system with approximately 454 miles of transportation pipelines that begins along the border of Wyoming and Colorado and extends to Beatrice, Nebraska. Substantially all of Trailblazer Pipeline's currently available design capacity of approximately 902 MMcf/d is subscribed for under firm transportation contracts.
The following tables provide information regarding TEP's Natural Gas Transportation & Logistics segment assets as of December 31, 2015 and for the years ended December 31, 2015, 2014, and 2013:
 
Approximate Average Daily Throughput (MMcf/d)
 
Year Ended December 31,
 
2015
 
2014
 
2013
Transportation
1,129

 
955

 
991

 
Approximate Number of Miles
 
Approximate Capacity
 
Total Firm Contracted Capacity (1)
 
Approximate % of Capacity Subscribed under Firm Contracts
 
Weighted Average Remaining Firm Contract Life (2)
Transportation
5,109

 
1,982 MMcf/d
 
1,428 MMcf/d
 
72
%
 
2 years
Storage
n/a

 
15.974 Bcf
(3) 
11 Bcf
 
69
%
 
6 years
(1) 
Reflects total capacity reserved under long-term firm fee contracts, including backhaul service, as of December 31, 2015.
(2) 
Weighted by contracted capacity as of December 31, 2015.
(3) 
The FERC certificated working gas storage capacity.

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Processing & Logistics Segment
Midstream Facilities. TEP owns and operates natural gas processing plants in Casper and Douglas, Wyoming and a natural gas treating facility at West Frenchie Draw, Wyoming. The Casper and Douglas plants currently have combined processing capacity of approximately 190 MMcf/d. The Casper plant also has a NGL fractionator with a capacity of approximately 3,500 barrels per day. The natural gas processed and treated at these facilities primarily comes from the Wind River Basin and the Powder River Basin, both in central Wyoming. In the fourth quarter of 2015, TEP completed construction and commenced commercial service on a new NGL pipeline with an approximate capacity of 19,500 barrels per day that transports NGLs from a processing plant in Northeast Colorado to an interconnect with Overland Pass Pipeline. As of December 31, 2015, approximately 92% of TEP's reserved processing capacity was subject to firm or volumetric fee contracts, with the majority of fee revenue based on the volumes actually processed. The remaining 8% was subject to commodity sensitive contracts. TEP's NGL pipeline in Northeast Colorado is supported by a 10-year lease for 100% of the pipeline capacity.
The table below sets forth certain information regarding the Midstream Facilities in TEP's Processing & Logistics segment as of December 31, 2015 and for the years ended December 31, 2015, 2014, and 2013:
Approximate Plant Capacity (MMcf/d) (1)
 
Approximate Capacity Under Contract
 
Weighted Average Remaining Contract Life (2)
 
Approximate Average Inlet Volumes (MMcf/d)
 
 
 
Year Ended December 31,
 
 
 
2015
 
2014
 
2013
190

 
89
%
 
3 years
 
122

 
152

 
133

(1) 
The West Frenchie Draw natural gas treating facility treats natural gas before it flows into the Casper and Douglas plants and therefore does not result in additional inlet capacity.
(2) 
Based on the average annual reservation capacity for each such contract's remaining life.
Water Solutions. TEP provides water business services through its approximate 92% membership interest in Water Solutions. Water Solutions owns and operates a freshwater delivery and storage system and a produced water gathering and disposal system in Weld County, Colorado. This system is used to support third party exploration, development, and production of oil and natural gas. Water Solutions also sources treated wastewater from municipalities in Texas and recycles flowback water and other water produced in association with the production of oil and gas in Colorado.
The table below sets forth certain information regarding the Water Solutions assets in our Processing & Logistics segment as of December 31, 2015 and for the years ended December 31, 2015, 2014, and 2013:
 
 
Approximate Capacity Under Contract
 
Approximate Current Design Capacity (bbls/d)
 
Remaining Contract Life
 
Approximate Average Volumes (bbls/d)
 
 
 
 
 
Year Ended December 31,
 
 
 
 
 
2015
 
2014
 
2013
Freshwater
 
56
%
 
30,863

(1) 
5 years
 
14,579

 
16,433

 

Gathering and Disposal
 
80
%
 
35,000

(2) 
9 years
 
7,951

(2) 

 

(1) 
Represents the average daily fresh water supply for the BNN Redtail, LLC fresh water pipeline acquired in 2014 and the BNN Western, LLC ("Western") fresh water delivery and storage system in Weld County, Colorado acquired in December 2015 as discussed under "Acquisitions" below.
(2) 
Represents the daily disposal well injection capacity and the average daily disposal injection volumes, respectively, for the Western produced water gathering and disposal system in Weld County, Colorado acquired in December 2015 as discussed under "Acquisitions" below.
Organizational Structure
Our general partner interest is held by TEGP Management, LLC, whose sole member is Tallgrass Energy Holdings. Tallgrass Energy Holdings is also the general partner of Tallgrass Development. A group of persons, which we refer to as the Exchange Right Holders, collectively own 100% of the voting power of Tallgrass Energy Holdings, all of our outstanding Class B shares and an equivalent number of Tallgrass Equity units. The Exchange Right Holders are entitled to exercise the right to exchange their Tallgrass Equity units (together with an equivalent number of Class B shares) for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged. The Exchange Right Holders primarily consist of Kelso, EMG, and Tallgrass KC. Tallgrass KC refers to Tallgrass KC, LLC, which is an entity owned by certain members of our and TEP's management.

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While we, like TEP, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of TEP. Most notably, (i) we have elected to be treated as a corporation for U.S. federal income tax purposes, (ii) neither our general partner nor the holder of our Class B shares are entitled to receive any distributions from us and (iii) our capital structure does not include incentive distribution rights. Therefore, our distributions will be made exclusively to our Class A shares. However, holders of our Class A shares and Class B shares vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or our partnership agreement. The term "shares" used in this annual report refers to both the Class A shares and Class B shares representing limited partner interests in us. References to our "shareholders" refer to the holders of our Class A and Class B shares.
Our operations are conducted directly and indirectly through, and our operating assets are owned by, our subsidiaries. Our general partner is responsible for conducting our business and managing our operations. However, Tallgrass Energy Holdings effectively controls our business and affairs through the exercise of its rights as the sole member of our general partner, including its right to appoint members to the board of directors of our general partner.

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The chart below shows the structure of Tallgrass Energy Holdings and its subsidiaries as of February 17, 2016 in a summary format.

7




Tallgrass Development
Tallgrass Development is controlled by its general partner, Tallgrass Energy Holdings. In connection with TEP's initial public offering on May 17, 2013 (the "TEP IPO"), Tallgrass Development contributed to TEP 100% of the membership interest in Tallgrass Interstate Gas Transmission, LLC ("TIGT"), which owns and operates the TIGT System, and 100% of the membership interest in Tallgrass Midstream, LLC ("TMID"), which owns and operates the Midstream Facilities. Since then, TEP has acquired the following additional assets from Tallgrass Development: (1) in April 2014, a 100% membership interest in Trailblazer Pipeline Company LLC ("Trailblazer"), which owns and operates the Trailblazer Pipeline, and (2) in three separate transactions, the most recent of which was effective on January 1, 2016, a 98.0% membership interest in Pony Express, which owns and operates the Pony Express System. Tallgrass Development continues to own and manage a portfolio of midstream assets, including the following:
a 50% interest in, and operation of, the Rockies Express Pipeline, or REX Pipeline, an approximately 1,713 mile natural gas pipeline with a bi-directional design capacity of up to 1.8 Bcf/d, that extends from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio; and
Tallgrass Terminals, LLC, or Terminals, which holds a 20% membership interest in Deeprock Development, LLC (the owner of a crude oil terminal in Cushing, Oklahoma with approximately 2.3 million bbls of storage capacity), and a crude oil terminal in Sterling, Colorado with approximately 1.3 million bbls of storage capacity.
Pursuant to an Omnibus Agreement entered into upon the closing of the TEP IPO, among TEP, TEP GP, Tallgrass Development and Tallgrass Energy Holdings (the "TEP Omnibus Agreement"), Tallgrass Development granted TEP a right of first offer to acquire certain assets held by Tallgrass Development at the time of the TEP IPO, which we refer to as the Retained Assets, if Tallgrass Development decides to sell such assets. The Retained Assets include Tallgrass Development's interest in Rockies Express Pipeline LLC and Tallgrass Development's remaining noncontrolling interest in Pony Express. Terminals is not a Retained Asset. Tallgrass Development is otherwise under no obligation to offer to sell TEP additional assets or to pursue acquisitions jointly with TEP, and TEP is under no obligation to buy any assets from Tallgrass Development or pursue any such joint acquisitions. However, given the significant economic interest in TEP held by Tallgrass Development and its affiliates, including Tallgrass Energy Holdings, we believe Tallgrass Development will be incentivized to offer TEP the opportunity to acquire the Retained Assets and Terminals as each continues maturing into an operating profile conducive to TEP's principal business objective of increasing the quarterly cash distributions that TEP pays to its unitholders over time while ensuring the ongoing stability of TEP's business.
Further, in connection with the closing of the Offering, we, our general partner, Tallgrass Equity and Tallgrass Energy Holdings entered into an omnibus agreement (the "TEGP Omnibus Agreement"), that addresses the following matters:
Tallgrass Equity’s obligation to reimburse Tallgrass Management, LLC and its affiliates for expenses incurred (i) on our behalf, (ii) on behalf of our general partner and (iii) for any other purposes related to our business and activities or those of our general partner, including our public company expenses and general and administrative expenses; and
Our use of the names "TEP" and "Tallgrass" and any associated or related marks.
Acquisitions
The acquisition of midstream assets and businesses that are strategic and complementary to TEP's existing operations constitutes an integral component of its business strategy and growth objectives. Such assets and businesses include crude oil and NGL logistics assets, natural gas transportation and storage assets and other energy assets that have characteristics and provide opportunities similar to TEP's existing business lines and enable TEP to leverage its assets, knowledge and skill sets. Below are summaries of significant acquisitions TEP completed in 2015. See Note 4Acquisitions to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data for a full discussion regarding our acquisition activities.
Pony Express System. Effective March 1, 2015, TEP acquired an additional 33.3% membership interest in Pony Express for cash consideration of approximately $700 million, bringing its total ownership in Pony Express to 66.7% on such date. Effective January 1, 2016, TEP acquired an additional 31.3% membership interest in exchange for cash consideration of $475 million and the issuance of 6,518,000 of TEP common units, bringing its total ownership interest in Pony Express to 98.0%.
Weld County, Colorado Water Assets. On December 16, 2015, TEP acquired the following assets located in Weld County, Colorado from Whiting Oil and Gas Corporation ("Whiting") in exchange for total cash consideration of $75 million: a fresh water delivery system and a produced water gathering and disposal system, seven fresh water ponds with approximately 2.4 million barrels of storage and three produced water disposal wells, along with long-term firm fee contracts and acreage dedications from Whiting.

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Competition
All of TEP's businesses face strong competition for acquisitions and development of new projects from both established and start-up companies. Competition may increase the cost to acquire existing facilities or businesses and may result in fewer commitments and lower returns for new pipelines or other development projects. TEP's competitors may have greater financial resources than TEP possesses or may be willing to accept lower returns or greater risks. Competition differs by region and by the nature of the business or the project involved.
Pony Express encounters competition in the crude oil transportation business. A number of pipeline companies compete with Pony Express to service takeaway volumes in markets that Pony Express currently serves, including pipelines owned and operated by Spectra Energy, Plains All American, Suncor, SemGroup, Magellan Midstream Partners, Anadarko, Noble, NGL Energy Partners, Energy Transfer Partners, and Enbridge Energy Partners. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil price benchmarks (West Texas Intermediate Crude and Brent Crude), and with refineries that source barrels in areas served by Pony Express.
TEP's principal competitors in its natural gas transportation and storage business include companies that own major natural gas pipelines, such as Wyoming Interstate Company, LLC, Colorado Interstate Gas Company, LLC, Cheyenne Plains Gas Pipeline Company, LLC, Northern Natural Gas Company, and Southern Star Central Gas Pipeline, Inc., some of whom also have existing storage facilities connected to their transportation systems that compete with TEP's storage facilities. In addition to this competition, which is primarily comprised of other pipeline companies that transport gas out of the Rocky Mountain region, Trailblazer also delivers gas into a very competitive marketplace that receives gas from the developing shale plays like the Bakken, Marcellus and Utica. As these supplies increase, it reduces the need for traditional Rockies gas production that is accessible from Trailblazer.
TEP also experiences competition in the natural gas processing business. TEP's principal competitors for processing business include other facilities that service its supply areas, such as the other regional processing and treating facilities in the greater Powder River Basin which include plants owned and operated by Kinder Morgan, Inc., which we refer to as Kinder Morgan, ONEOK Partners, LP, Western Gas Partners, LP, Williams Partners L.P. and Meritage Midstream Services II, LLC. In addition, due to the competitive nature of the liquids-rich plays in the Wind River Basin and Powder River Basin, it is possible that one of TEP's competitors could build additional processing facilities that service TEP's supply areas.
Further, TEP experiences competition in the water business services. TEP's principal competitors in such business are transactional water service companies and larger produced water disposal well owners. An example of a competitor that is a transactional water service company would be Select Energy Services, as they provide temporary fresh water supply and water recycling that competes with Water Solutions. An example of a competitor that is a larger disposal well owner would be NGL Energy Partners, as they compete with Water Solutions through produced water gathering and disposal in areas of concentrated production activity.
Additionally, pending and future construction projects, if and when brought online, may also compete with TEP's crude oil transportation, natural gas transportation and storage, water transportation, gathering and disposal, and processing services. Further, as a provider of midstream services to the natural gas and crude oil industries, TEP generally competes with other forms of energy available to consumers, including electricity, coal, propane and fuel oils. Several factors influence the demand for natural gas and crude oil, including price changes, the availability of natural gas and crude oil and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, weather, and the ability to convert to alternative fuels.
Regulatory Environment
Federal Energy Regulatory Commission
TEP provides open-access interstate transportation service on its natural gas transportation systems pursuant to tariffs approved by the FERC. As interstate transportation and storage systems, the rates, terms of service and continued operations of the TIGT System and the Trailblazer Pipeline are subject to regulation by the FERC, under among other statutes, the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EPAct 2005. The rates and terms of service on the Pony Express System are subject to regulation by the FERC under the Interstate Commerce Act, or the ICA, and the Energy Policy Act of 1992. TEP provides interstate transportation service on the Pony Express System pursuant to tariffs on file with the FERC. TEP's NGL pipeline is leased to a third party who has obtained a temporary waiver for itself from the FERC from the tariff, filing and reporting requirements of the ICA.

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The FERC has jurisdiction over, among other things, the construction, ownership and commercial operation of pipelines and related facilities used in the transportation and storage of natural gas in interstate commerce, including the modification, extension, enlargement and abandonment of such facilities. The FERC also has jurisdiction over the rates, charges and terms and conditions of service for the transportation and storage of natural gas in interstate commerce. The FERC’s authority over crude oil pipelines is less broad than its authority over interstate natural gas pipelines and includes rates, rules and regulations for service, the form of tariffs governing service, the maintenance of accounts and records, and depreciation and amortization policies.
The rates and terms for access to natural gas pipeline transportation services are subject to extensive regulation and the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of these initiatives, interstate natural gas transportation and marketing entities have been substantially restructured to remove barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from competing effectively with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The FERC’s regulations require, among other things, that interstate natural gas pipelines provide firm and interruptible transportation service on an open access basis, provide internet access to current information about available pipeline capacity and other relevant information, and permit pipeline shippers under certain circumstances to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. The result of the FERC’s initiatives has been to eliminate interstate natural gas pipelines’ historical role of providing bundled sales service of natural gas and to require pipelines to offer unbundled storage and transportation services on a not unduly discriminatory or preferential basis. The rates for such transportation and storage services are subject to the FERC’s ratemaking authority, and the FERC exercises its authority by applying cost-of-service principles to limit the maximum and minimum levels of tariff-based recourse rates; however it also allows for the negotiated rates as an alternative to cost-based rates and may grant market-based rates in certain circumstances, typically with respect to storage services. The FERC regulations also restrict interstate natural gas pipelines from sharing transportation or customer information with marketing affiliates and require that the transmission function personnel of interstate natural gas pipelines operate independently of the marketing function personnel of the pipeline or its affiliates.
TIGT 2015 Cost and Revenue Study
On October 3, 2015, TIGT submitted a cost and revenue study in compliance with Article IV of the Stipulation and Agreement of Settlement filed on May 5, 2011 in FERC Docket No. RP11-1494 ("2011 Settlement") and approved by the FERC on September 22, 2011. The cost and revenue study demonstrates that TIGT is under-recovering its cost of service. Consistent with the 2011 Settlement, the study was based on the unadjusted actual costs, revenues and volumes for a 12-month base period ended June 30, 2015, in compliance with Section 154.303(a)(1) of the FERC’s regulations. The cost and revenue study did not propose any change to TIGT’s currently effective rates. The cost and revenue study was accepted by FERC on February 1, 2016 in compliance with the 2011 Settlement.
TIGT 2015 General Rate Case Filing
On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA. The rate case proposed a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT. In addition, TIGT proposed certain changes to the transportation rate design of its system to replace the current rate zone structure with a single "postage stamp" rate. TIGT also proposed new incremental charges, including (i) a charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a Cost Recovery Mechanism ("CRM") charge to completely or partially reimburse TIGT for certain expenses and costs it incurs to comply with anticipated new PHMSA and EPA regulations. TIGT also proposed to replace its fixed fuel and lost and unaccounted for ("FL&U") charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period’s under/over collection and the forecasted FL&U expense for the upcoming period. TIGT also proposed to implement a power cost tracker to recover the actual power costs incurred by TIGT to power its compressors. Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under the NGA and the FERC’s regulations, TIGT’s shippers and other interested parties, including the FERC’s Trial Staff, have a right to challenge any aspect of TIGT’s rate case filing. Accordingly, numerous TIGT customers have protested aspects of TIGT’s NGA Section 4 rate filing.
On November 30, 2015, the FERC issued an order accepting and suspending the proposed rates and a majority of the proposed tariff records to be effective upon motion May 1, 2016, subject to refund, certain modifications to TIGT’s proposed CRM charge, and the outcome of an evidentiary hearing before a FERC Administrative Law Judge (the "Suspension Order"). In the Suspension Order, the FERC also accepted two tariff records related to force majeure events and reservation charge crediting to be effective December 1, 2015, subject to certain modifications. On December 21, 2015, TIGT made a compliance filing with the FERC to modify TIGT’s proposed CRM charge and update the tariff records related to force majeure events and reservation charge crediting as directed by the FERC in the Suspension Order. No comments or protests were filed in response to the compliance filing and FERC accepted the compliance filing on February 1, 2016. One request for rehearing of the Suspension Order is currently pending before the FERC with respect to the Suspension Order’s acceptance, subject to a five-month suspension period, refund, the outcome of the hearing and the modifications made in TIGT's December 21, 2015

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compliance filing, of TIGT’s proposed CRM charge. The FERC Administrative Law Judge assigned to the proceeding has issued an order establishing the procedural schedule and TIGT, the FERC’s Trial Staff, and other participants that successfully intervened are actively participating in the litigated proceeding to address those rate and tariff matters set for hearing by the FERC in its Suspension Order. On January 27, 2016, the FERC issued a tolling order to afford the FERC additional time for consideration of matters raised on rehearing regarding the Suspension Order. Additional FERC action is pending.
2014 Trailblazer Rate Settlement
On January 22, 2014, Trailblazer, the FERC’s Trial Staff, and the active parties in the pipeline’s general rate case finalized a settlement in principle resolving the pending rate issues, including: (i) establishing transportation rates, as well as FL&U charges; (ii) providing a limited profit sharing arrangement for certain revenues earned from interruptible and short-term firm transport; and (iii) setting the minimum and maximum time that can elapse before Trailblazer’s next rate case at the FERC. Trailblazer filed a motion with the FERC’s Chief Administrative Law Judge to accept the settlement rates on an interim basis ("Interim Rates") while the participants finalized a definitive settlement. The Chief Administrative Law Judge accepted the Interim Rates effective February 1, 2014. On February 24, 2014, Trailblazer filed an uncontested offer of settlement ("Stipulation and Agreement") among active party shippers. The Stipulation and Agreement established the Interim Rates as final settlement rates effective February 1, 2014, subject to the issuance of refunds to certain shippers for January 2014 transportation services and revised fuel and lost and unaccounted for rates, effective July 1, 2014. On March 11, 2014, the Presiding Administrative Law Judge certified the Stipulation and Agreement. On May 29, 2014, the FERC approved the Stipulation and Agreement. On June 30, 2014, Trailblazer filed tariff sheets to implement the Stipulation and Agreement effective July 1, 2014. Estimated refunds were reserved from revenues recorded in January 2014. On July 1, 2014, Trailblazer submitted refunds to its customers for amounts collected in excess of amounts that would have been collected under the Settlement Rates, with interest, and on July 18, 2014, filed a report of refunds with the FERC. The FERC issued orders accepting the tariff sheets with the requested effective date of July 1, 2014 and accepting the refund report filing on July 25, 2014 and August 7, 2014, respectively. Per the terms of the Stipulation and Agreement, Trailblazer is required to file a new rate case by January 1, 2019, and no settling party was permitted to file a change to the settlement rates before January 1, 2016.
Trailblazer Annual Fuel Tracker Filing
On April 1, 2015, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2015 in Docket No. RP15-841-000. This filing incorporates the revised fuel tracker and power cost tracker mechanisms agreed to in the Stipulation and Agreement, which resolves all outstanding issues related to Trailblazer fuel recoveries. The FERC approved this filing on April 23, 2015.
Trailblazer Notice to Vacate Authorization for the Niobrara Lateral Project
On December 18, 2015, Trailblazer filed a notice in Docket No. CP15-27-000 informing FERC that, based upon current market conditions, it will not be constructing certain gas supply facilities located in Weld County, Colorado and Kimball County, Nebraska interconnecting Trailblazer to the Rockies Express pipeline system, referred to as the Niobrara Lateral.
Initiation of Service on the Pony Express System
In 2013, TIGT received FERC authorization to remove from natural gas service approximately 433 miles of mainline natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the "Pony Express Assets"), abandon those assets by sale to Pony Express for redeployment to provide transportation of oil as part of the Pony Express System, and construct certain replacement facilities. The construction of the Pony Express System consisted of three primary phases: (1) conversion of 433 miles of the Pony Express Assets from a natural gas pipeline into a crude oil pipeline; (2) construction of an approximately 265 mile extension from the converted pipeline to Cushing, Oklahoma; and (3) construction of an approximate 66 mile lateral in Northeast Colorado. The facilities constructed in phases (1) and (2) of the Pony Express System were placed in service in the fall of 2014. The lateral in Northeast Colorado constructed under phase (3) was placed in service during the second quarter of 2015. Following completion of the lateral in Northeast Colorado, the total system design capacity of the Pony Express System was approximately 320,000 bbls/d. Approximately 90% of the pipeline capacity is committed to contract shippers under 5 year firm contracts and at least 10% is reserved for non-contract shippers.
In anticipation of completing the construction of various facilities and commencing various transportation services three petitions for declaratory orders were submitted over time to the FERC by Pony Express, and certain joint tariff upstream pipelines interconnected with Pony Express to address considerations related to the Pony Express System, local services and rate structures, joint tariff services and rate structures, cost recovery, prorationing policies, committed shipper contract provisions, and other matters. In response to these petitions, the FERC issued declaratory orders (two in 2012 and one in 2014) granting each of the three petitions.

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Thereafter, Pony Express made certain public tariff filings with the FERC to establish initial tariff rates and initial tariff rules and regulations for oil transportation services as each service was commenced upon completion of facilities. Initial local tariff non-contract rates from the Guernsey origin, along with initial Rules and Regulations for all services, were filed to be effective October 1, 2014. Initial local tariff contract rates from the Guernsey origin were filed to be effective November 1, 2014. Initial joint tariff contract rates for oil received from Belle Fourche Pipeline were filed to be effective November 1, 2014. Initial joint tariff non-contract and contract rates for oil received from Hiland Pipeline were filed to be effective January 1, 2015, but contract service under the Hiland joint tariff did not commence until April 1, 2015. Initial local tariff non-contract rates from origins on the Northeast Colorado lateral were filed to be effective April 2, 2015. Initial local tariff contract rates from origins on the Northeast Colorado lateral were filed to be effective June 1, 2015. Following these initial tariff filings, additional filings were made in 2015 for each contract and non-contract rate service provided by Pony Express to implement a 4.6% rate increase related to the annual FERC index adjustment. The increases became effective during the third and fourth quarters of 2015 in accordance with the provisions of various shipper contracts with respect to contract rates, and in accordance with FERC regulations with respect to non-contract rates.
Compliance with 2014 FERC Show Cause Order Issued to All Interstate Pipelines Regarding Notice of Offers to Purchase Released Capacity
On March 20, 2014, the FERC issued an Order to Show Cause to all interstate natural gas pipelines requiring the pipelines to revise their respective FERC Gas Tariffs to provide for the posting of offers to purchase released capacity as required by 18 C.F.R. §284.8(d). Both TIGT and Trailblazer submitted compliance filings proposing revisions to their respective tariffs, and the FERC accepted their compliance filings effective October 21, 2014.
FERC; Market Behavior Rules; Posting and Reporting Requirement; Other Enforcement Authorities
EPAct 2005, among other matters, amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and, furthermore, provides the FERC with additional civil penalty authority. The FERC adopted rules implementing the anti-manipulation provision of EPAct 2005 that make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas transportation services subject to the jurisdiction of the FERC to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person.
These anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services as well as otherwise non-jurisdictional entities to the extent the activities are conducted ‘‘in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. These anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a ‘‘nexus’’ to jurisdictional transactions. EPAct 2005 also amended the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes, up to $1 million per day per violation. In connection with this enhanced civil penalty authority, the FERC issued policy statements on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should TEP fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, TEP could be subject to substantial penalties and fines, including the disgorgement of unjust profits.
EPAct 2005 also amended the NGA to authorize the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. The FERC has taken steps to enhance its market oversight and monitoring of the natural gas industry by adopting rules that (1) require buyers and sellers of annual quantities of 2,200,000 MMBtu or more of gas in any year to report by May on the aggregate volumes of natural gas they purchased or sold at wholesale in the prior calendar year; (2) report whether they provide prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting; and (3) increase the Internet posting obligations of interstate pipelines.
In addition, the Commodity Futures Trading Commission, or CFTC, is directed under the Commodities Exchange Act, or CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, in July 2010 and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.

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Further, the Federal Trade Commission, or FTC, has the authority under the Federal Trade Commission Act, or FTCA, and the Energy Independence and Security Act of 2007, or EISA, to regulate wholesale petroleum markets. The FTC has adopted anti-market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of up to $1 million per violation per day. FERC also has the authority under the ICA to regulate the interstate transportation of petroleum on common carrier pipelines, including whether a pipeline’s rates or rules and regulations for service are "just and reasonable." Among other enforcement powers, FERC can order prospective rate changes, suspend the effectiveness of rates, and order reparations for damages.
Pipeline and Hazardous Materials Safety Administration
TEP is also subject to safety regulations imposed by PHMSA, including those regulations requiring TEP to develop and maintain integrity management programs to comprehensively evaluate certain areas along TEP's pipelines and take additional measures to protect pipeline segments located in areas, which are referred to as high consequence areas, or HCAs, where a leak or rupture could potentially do the most harm.
The President signed into law in January 2012 The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or The Pipeline Safety Act of 2011, which amended the Pipeline Safety Improvement Act of 2002, increased penalties for violations of safety laws and rules, among other matters, and may result in the imposition of more stringent regulations in the next few years. This legislation also requires the U.S. Department of Transportation to study and report to Congress on other areas of pipeline safety, including expanding the reach of the integrity management regulations beyond high consequences areas, but restricts the U.S. Department of Transportation from promulgating expanded integrity management rules during the review period and for a period following submission of its report to Congress unless the rulemaking is needed to address a present condition that poses a risk to public safety, property or the environment. PHMSA issued a final rule effective October 25, 2013 that implemented aspects of the new legislation. Among other things, the final rule increases the maximum civil penalties for violations of pipeline safety statutes or regulations, broadens PHMSA’s authority to submit information requests, and provides additional detail regarding PHMSA’s corrective action authority.
Additionally, PHMSA is also currently considering changes to its regulations. In October 2015, PHMSA issued a notice of proposed rule-making to its hazardous liquid pipeline safety regulations. Among other things, the proposed regulations would expand the current leak-detection requirements, apply new, more conservative repair criteria and establish timelines for inspecting pipeline facilities potentially affected by an extreme weather event or natural disaster. The proposal would also increase the stringency of integrity management program requirements and set deadlines for the use of internal inspection tools on certain systems. Further, PHMSA issued an Advisory Bulletin in May 2012, which advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of such pressures, could significantly increase TEP's costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for maximum allowable operating pressure, or MAOP. TEP is currently undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on TEP's pipelines. At the state level, several states have passed legislation or promulgated rulemaking dealing with pipeline safety. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts TEP currently anticipates. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of TEP's pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of TEP's pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures.

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Pipeline Integrity Issues
The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs can have a significant impact on the costs to perform integrity testing and repairs. Trailblazer recently conducted smart tool surveys and preliminary analysis on segments of its natural gas pipeline to evaluate the growth rate of corrosion downstream of compressor stations. Trailblazer currently believes that approximately 25 - 35 miles of pipe will likely need to be repaired or replaced in order for the pipeline to operate at its MAOP of 1,000 pounds per square inch. Such repair or replacement will likely occur over a period of years, depending upon final assessment of corrosion growth rates and the remediation and repair plan implemented by Trailblazer. Trailblazer is currently operating at less than its current MAOP, public notice of which was first provided in June 2014. The current pressure reduction is not expected to prevent Trailblazer from fulfilling its firm service obligations at existing subscription levels and to date it has not had a material adverse financial impact on TEP.
During 2015, Trailblazer completed 32 excavation digs at an aggregate cost of approximately $1.3 million based on preliminary analysis of the smart tool surveys performed in 2014. Segments of the Trailblazer Pipeline that require full replacement are currently expected to cost in the range of approximately $2.2 million to $2.7 million per mile. Repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. Trailblazer is continuing to develop a remediation and repair plan, which involves, among other things, finalizing cost recovery options, establishing project scope and timing and setting an overall project budget. In 2016, Trailblazer intends to replace approximately 8 miles of pipe at an estimated cost of $21.5 million. Trailblazer is currently exploring all possible cost recovery options. It may not ultimately be able to recover any or all of such out of pocket costs unless and until Trailblazer recovers them through a general rate increase or other FERC-approved recovery mechanism, or through negotiated rate agreements with its customers.
In connection with TEP's acquisition of the Trailblazer Pipeline, Tallgrass Development agreed to contractually indemnify TEP for any out of pocket costs incurred between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline’s disbonded Hi-Melt CTE coating. The contractual indemnity provided by Tallgrass Development is currently capped at $20 million and is subject to an annual $1.5 million deductible. TEP will continue pipeline integrity testing programs to assess and maintain the integrity of its existing and future pipelines as required by the U.S. Department of Transportation regulations. The results of these tests could cause TEP to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines, which expenditures could be material.
In addition, TEP may be subject to enforcement actions and penalties for failure to comply with pipeline regulations. For example, on March 12, 2015, an event occurred at the Yoder Pump Station in Goshen County, Wyoming, related to repair and replacement activities resulting in a spill of approximately 300 bbls of crude oil. In this instance, the remediation activities have been completed without material cost to the Pony Express System and the matters have been closed by the applicable agencies. In late 2015, anomalies were detected on the portion of the Pony Express System’s pipeline that was converted from gas service.  These anomalies were reported to PHMSA on December 2, 2015. Pony Express is continuing to evaluate and remediate these issues on the converted pipeline section of the Pony Express System. Tallgrass Development has agreed to contractually indemnify TEP for out of pocket costs incurred to repair, replace or remediate anomalies in any part of the Pony Express System’s pipeline that was converted from gas service to the extent such anomalies are identified by in-line inspection tools during the period from January 1, 2015 until January 1, 2019. The contractual indemnity provided by Tallgrass Development is capped at $11 million and is subject to an annual $1 million deductible.
From time to time, TEP's pipelines may experience integrity issues. These integrity issues may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, TEP may be sued for damages caused by an alleged failure to properly mark the locations of its pipelines and/or to properly maintain its pipelines. For example, on June 13, 2013, a failure occurred on a segment of the TIGT System in Goshen County, Wyoming, resulting in the release of natural gas and the issuance of a Corrective Action Order, or CAO, by PHMSA. The line was promptly brought back into service and the failure did not cause any known injuries, fatalities, fires or evacuations. Pursuant to a letter dated August 14, 2015, PHMSA informed TIGT that it had complied with the terms of the CAO and declared the case closed. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties and TEP may also be subject to private civil liability for such matters.
For additional information, see Note 18 – Legal and Environmental Matters to our Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data in this Form 10-K.

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Environmental, Health and Safety Matters
General
The ownership, operation and expansion of TEP's assets are subject to federal, state and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health. These laws and regulations can restrict or impact TEP's business activities in many ways, such as restricting the way TEP can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operations, regulating future construction activities to mitigate harm to threatened or endangered species, wetlands and migratory birds, and requiring the installation and operation of pollution control or seismic monitoring equipment. The cost of complying with these laws and regulations can be significant, and TEP expects to incur significant compliance costs in the future as new, more stringent requirements are adopted and implemented.
Failure to comply with existing environmental laws, regulations, permits, approvals or authorizations or to meet the requirements of new environmental laws, regulations or permits, approvals and authorizations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and/or temporary or permanent interruptions in TEP's operations that could influence its business, financial position, results of operations and prospects. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. The costs and liabilities resulting from a failure to comply with environmental laws and regulations could negatively affect TEP's business, financial position, results of operations and prospects. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
In addition, TEP has agreed to a number of conditions in its environmental permits, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where TEP currently operates, and would operate in the future, and TEP is unable to predict the effect that any such measures would have on its business, financial position, results of operations or prospects.
TEP is also subject to the requirements of the Occupational Health and Safety Act, or OSHA, the Pipeline Safety Act and other comparable federal and state statutes. In general, TEP expects that it may have to increase expenditures in the future to comply with higher industry and regulatory safety standards. Such increases in expenditures could become significant over time.
Historically, TEP's total expenditures for environmental control measures and for remediation have not been significant in relation to TEP's consolidated financial position or results of operations. It is reasonably likely, however, that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business.
For additional information regarding Environmental, Health and Safety Matters, please read Item 1A.—Risk Factors.
Air Emissions
TEP's operations are subject to the federal Clean Air Act, or CAA, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that TEP obtains pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions (including GHG emissions, as discussed below), obtain and strictly comply with air permits containing various emissions and operational limitations and/or install emission control equipment. TEP may be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.
In September 2015, the EPA issued a proposed rule under the New Source Performance Standard Program, or NSPS Program, to limit methane emissions from the oil and gas and transmission sectors. The proposed rule would update and expand the NSPS Program by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. Also, in January 2016, the Bureau of Land Management of the U.S. Department of the Interior, or BLM, proposed new rules to reduce venting, flaring and leaks during oil and natural gas production activities onshore Federal and Indian lands.

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Developments in GHG Regulations
Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and products produced from crude oil, are examples of GHGs. The EPA has determined that the emission of GHGs present an endangerment to public health and the environment because emissions of such gases contribute to the warming of the Earth’s atmosphere and other climatic changes. Various laws and regulations exist or are under development that seek to regulate the emission of such GHGs, including the EPA programs to control GHG emissions and state actions to develop statewide or regional programs. In recent years, the U.S. Congress has considered, but not adopted, legislation to reduce emissions of GHGs. There have also been efforts to regulate GHGs at an international level, most recently in the Paris Agreement, negotiated in December 2015, which aims to limit global GHG emissions.
Because TEP's operations, including its compressor stations, emit various types of GHGs, primarily methane and carbon dioxide, such new legislation or regulation could increase its costs related to operating and maintaining its facilities. Depending on the particular new law, regulation or program adopted, TEP could be required to incur capital expenditures for installing new emission controls on its facilities, acquire permits or other authorizations for emissions of GHGs from its facilities, acquire and surrender allowances for its GHG emissions, pay taxes related to its GHG emissions and administer and manage a GHG emissions program. TEP is not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to TEP. While TEP may be able to include some or all of such increased costs in the rates charged by its pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond its control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations. Similarly, while TEP may be able to recover some or all of such increased costs in the rates charged by its processing facilities, such recovery of costs is uncertain and may depend on the terms of its contracts with its customers. In addition, new laws, regulations, or programs adopted could also impact TEP's customers’ operations or the overall demand for fossil fuels. Any of the foregoing could have an adverse effect on TEP's business, financial position, results of operations and prospects.
Regulation of Hydraulic Fracturing
A sizeable portion of the hydrocarbons TEP transports, processes, and stores comes from hydraulically fractured wells. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process typically involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state’s oil and gas commission. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. In addition, some states, including those in which TEP operates, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Other states, including states in which TEP operates, have restrictions on produced water storage from hydraulic fracturing operations and the operation of produced water disposal wells. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for TEP's customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of crude oil, natural gas, and NGLs that TEP's customers produce, and could thereby adversely affect TEP's revenues and results of operations.
Hazardous Substances and Waste
TEP's operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, nonhazardous and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of nonhazardous and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release or threatened release of a hazardous substance into the environment. TEP may handle hazardous substances within the meaning of CERCLA, or analogous state laws, in the course of its ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released or threatened to be released into the environment.

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TEP also generates wastes that are subject to Resource Conservation and Recovery Act, or RCRA, and comparable state laws. RCRA regulates both nonhazardous and hazardous solid wastes, but it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. It is possible that wastes resulting from TEP's operations that are currently treated as non-hazardous wastes could be designated as "hazardous wastes" in the future, subjecting TEP to more rigorous and costly management and disposal requirements. It is also possible that federal or state regulatory agencies will adopt stricter management or disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on TEP's business, financial position, results of operations and prospects or otherwise impose limits or restrictions on its operations or those of its customers.
In some cases, TEP owns or leases properties where hydrocarbons are being or have been handled for many years. Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by TEP or on or under the locations where these hydrocarbons and wastes have been transported for treatment or disposal. TEP could also have liability for releases or disposal on properties owned or leased by others. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, TEP could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners and operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.
TEP's produced water disposal operations require it to comply with the Class II well standards under the federal Safe Drinking Water Act, or SDWA. The SDWA imposes requirements on owners and operators of Class II wells through the EPA’s Underground Injection Control program, including construction, operating, monitoring and testing, reporting and closure requirements. TEP's disposal wells are also subject to comparable state laws and regulations. Compliance with current and future laws and regulations regarding TEP's produced water disposal wells may impose substantial costs and restrictions on its produced water disposal operations, as well as adversely affect demand for its produced water disposal services. State and federal regulatory agencies recently have focused on a possible connection between the operation of produced water injection wells used for oil and gas waste disposal and minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In some instances, operators of produced water injection wells in the vicinity of minor seismic events have been ordered to reduce produced water injection volumes or suspend operations. Regulatory agencies are continuing to study possible linkage between produced water injection activity and induced seismicity. These developments could result in additional regulation of produced water injection wells, such regulations could impose additional costs and restrictions on TEP's produced water disposal operations.
Federal and State Waters
The Federal Water Pollution Control Act, also known as the Clean Water Act, or the CWA, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including petroleum products, into state waters or waters of the United States. The EPA and the U.S. Army Corps of Engineers recently adopted a rule to clarify the meaning of the term "waters of the United States" with respect to federal jurisdiction. Many interested parties believe that the proposed rule expands federal jurisdiction under the CWA. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, permits and/or state permits authorizing these discharges. The CWA and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the CWA and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater. We believe that TEP is in substantial compliance with the CWA permitting requirements as well as the conditions imposed thereunder and that continued compliance with such existing permit conditions will not have a material effect on its results of operations.
The primary federal law related to oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the CWA and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. Spill prevention, control and countermeasure requirements of federal laws and analogous state laws require TEP to maintain spill prevention control and countermeasure plans. These laws also require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. Regulations promulgated pursuant to OPA further require certain facilities to maintain oil spill prevention and oil spill contingency plans. A liable "responsible party" includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, TEP may be liable for costs and damages.

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Endangered Species
The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of TEP's operations may be located in areas that are designated as habitats for endangered or threatened species, We believe that TEP is in substantial compliance with the ESA. However, the designation of previously unlisted endangered or threatened species could cause TEP to incur additional costs or become subject to operating restrictions or bans or limit future development in the affected areas.
National Environmental Policy Act
The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC or other federal approval must undergo a NEPA review. A NEPA review can create delays and increased costs that could materially adversely affect TEP's operations.
Employee Safety
TEP is subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that TEP's operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Seasonality
Weather generally impacts natural gas demand for power generation and heating purposes, which in turn influences the value of transportation and storage. Price volatility also affects gas prices, which in turn influences drilling and production. Peak demand for natural gas typically occurs during the winter months, caused by heating demand. TEP does not expect its crude oil transportation segment to encounter market based seasonality. Nevertheless, because a high percentage of TEP's natural gas transportation and storage and crude oil transportation revenues are derived from firm capacity reservation fees under long-term firm fee contracts, TEP's revenues attributable to those segments are not generally seasonal in nature. TEP experiences some seasonality in its processing segment, as volumes at its processing facilities are slightly higher in the summer months. TEP also experiences some seasonality in its maintenance, repair, overhaul, integrity, and other projects, as warm weather months are most conducive to efficient execution of these activities.
Title to Properties and Rights-of-Way
TEP's real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for its operations. Portions of the land on which its pipelines and facilities are located are owned by TEP in fee title, and we believe that TEP has satisfactory title to these lands. The remainder of the land on which TEP's pipelines and facilities are located are held by TEP pursuant primarily to leases, easements, rights-of-way, permits or licenses between TEP, as grantee, and a third party, as grantor. We believe that TEP has satisfactory title to all of its material parcels that TEP owns in fee and the material parcels in which TEP interest derives from leases, easements, rights-of-way, permits and licenses, and TEP has no knowledge of any challenge that TEP expects will impact its title to such assets or their underlying fee title in any material respect.
Some of the leases, easements, rights-of-way, permits and licenses TEP acquires, including those TEP acquired in the TEP IPO, require the consent of the grantor for the assignment/conveyance of such rights, which in certain instances is a governmental entity. The transferor, such as Tallgrass Development or its affiliates, may continue to hold record title to portions of certain assets until TEP makes the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals that are not obtained prior to transfer. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, Tallgrass Development may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for TEP's benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause its affiliates to retain title, as nominee for TEP's benefit, until a future date. TEP anticipates that there will be no material change in the tax treatment of TEP common units resulting from Tallgrass Development holding the title to any part of such assets subject to future conveyance or as its nominee.

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Insurance
We generally share insurance coverage with Tallgrass Development, for which we reimburse Tallgrass Development and its affiliates pursuant to the terms of the TEGP Omnibus Agreement and TEP Omnibus Agreement. The Tallgrass Development insurance program includes general and excess liability insurance, auto liability insurance, workers’ compensation insurance, property and director and officer liability insurance. All insurance coverage is in amounts which management believes are reasonable and appropriate.
Employees
We do not have any employees. We are managed and operated by the board of directors and executive officers of our general partner. All of our employees are employed by an affiliate of Tallgrass Energy Holdings and devote the portion of their time to our business and affairs that is reasonably required to manage and conduct our operations. Under the terms of the TEGP Omnibus Agreement, the TEP Omnibus Agreement and our partnership agreement, we reimburse Tallgrass Development and our general partner, respectively, for the provision of various general and administrative services for our benefit and for direct expenses incurred by Tallgrass Development or our general partner on our behalf, including services performed and expenses incurred by our executive management personnel in connection with our business and affairs.
Available Information
We make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website, www.tallgrassenergy.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC’s website, www.sec.gov, at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Our press releases and recent presentations are also available on our website.
Item 1A. Risk Factors
Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay quarterly distributions on our Class A shares at the current distribution level, or pay any distribution at all, and the trading price of our Class A shares could decline. References to "us," "we," and "our" in this Item 1A refer to Tallgrass Energy GP, LP in its individual capacity.
Risks Inherent in an Investment in Us
Our only cash-generating assets are interests in Tallgrass Equity and therefore our cash flow is entirely dependent upon the ability of TEP to make cash distributions to Tallgrass Equity, and the ability of Tallgrass Equity to make cash distributions to us.
Our only current source of earnings and cash flow is cash distributions from Tallgrass Equity, which currently consists exclusively of cash distributions from TEP. The amount of cash that TEP can distribute to its partners, including Tallgrass Equity, each quarter principally depends upon the amount of cash it generates from its business. For a description of certain factors that can cause fluctuations in the amount of cash that TEP generates from its business, please read the section entitled "Risks Related to TEP's Business." TEP may not have sufficient available cash each quarter to continue paying distributions at its current level or at all. If TEP reduces its per unit distribution, either because of reduced operating cash flow, higher expenses, capital requirements or otherwise, we will have less cash available for distribution to you and would likely be required to reduce our per share distribution to you. You should also be aware that the amount of cash TEP has available for distribution depends primarily upon TEP’s distributable cash flow, including cash flow from the release of financial reserves as well as borrowings, not profitability, which will be affected by non-cash items. As a result, TEP may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.
Furthermore, Tallgrass Equity’s ability to distribute cash to us and our ability to distribute cash received from Tallgrass Equity to our Class A shareholders is limited by a number of factors, including:
Tallgrass Equity’s payment of costs and expenses associated with our, our general partner's, Tallgrass Energy Holdings', and Tallgrass Equity’s respective operations, including expenses we incur as a result of being a public company, which costs and expenses are not subject to a limit pursuant to the TEGP Omnibus Agreement;
our payment of any income taxes;
interest expense and principal payments on any indebtedness incurred by TEP, Tallgrass Equity, TEP GP or us;

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restrictions on distributions contained in Tallgrass Equity’s and TEP’s respective revolving credit facilities and any future debt agreements entered into by Tallgrass Equity, TEP, TEP GP or us;
reserves created by our general partner as necessary to permit Tallgrass Equity to make capital contributions to TEP GP, including for it to maintain or attain up to a 2.0% general partner interest in TEP; and
reserves our general partner or TEP GP establish for the proper conduct of our, Tallgrass Equity’s or TEP’s business, including reserves to comply with applicable law or any agreement binding on us for future distributions , our subsidiaries, Tallgrass Equity, Tallgrass Equity’s subsidiaries, TEP and TEP’s subsidiaries, which reserves are not subject to a limit pursuant to our partnership agreement, TEP’s partnership agreement or Tallgrass Equity’s limited liability company agreement.
A material increase in amounts paid or reserved with respect to any of these factors could restrict our ability to pay quarterly distributions to our Class A shareholders.
We may limit, modify or eliminate the incentive distributions that Tallgrass Equity is entitled to receive through its ownership of TEP’s incentive distribution rights without the consent of our shareholders, which may reduce cash distributions to you.
We own a 30.35% membership interest in Tallgrass Equity, which, through its ownership of all the membership interests in TEP GP, is entitled to receive increasing percentages (up to a maximum of 48%, to the extent not modified or eliminated) of any cash distributed by TEP in excess of $0.3048 per TEP common unit in any quarter. The majority of the cash flow we receive from Tallgrass Equity is expected to be derived from its ownership of these IDRs.
TEP, like other publicly traded partnerships, generally targets acquisitions or expansion capital projects that, after giving effect to related costs and expenses, would be expected to be accretive, meaning it would increase cash distributions per unit in future periods. Because Tallgrass Equity, through its ownership of TEP GP, currently participates in the IDRs at all levels, including the highest sharing level of 48%, it is harder for an acquisition or capital project to show accretion for the common unitholders of TEP than if the IDRs received less incremental cash flow. As a result, our general partner may agree to allow TEP’s general partner to modify, reduce or eliminate the IDRs to facilitate a particular acquisition or expansion capital project. Any such modification, reduction or elimination of IDRs will reduce the amount of cash that would have otherwise been distributed by Tallgrass Equity to us, which will in turn reduce the cash distributions we would otherwise be able to pay to you. Our shareholders are not able to vote on or otherwise prohibit TEP’s general partner from modifying or eliminating the TEP IDRs, and our general partner may agree to allow TEP’s general partner to reduce, modify or eliminate the IDRs without considering the interests of the holders of our Class A shares. In addition, there can be no guarantee that the expected benefits of any IDR modification, reduction or elimination will be realized.
A reduction in TEP’s distributions will disproportionately affect the amount of cash distributions to which Tallgrass Equity is currently entitled.
Tallgrass Equity’s indirect ownership of TEP’s IDRs entitle it to receive increasing percentages, ranging from 13% up to 48%, to the extent not reduced, modified or eliminated, of all cash distributed by TEP in excess of $0.3048 per TEP common unit per quarter. A decrease in the amount of distributions paid by TEP to less than $0.4313 per TEP common unit per quarter would reduce Tallgrass Equity’s percentage of incremental cash distributions in excess of $0.3048 per TEP common unit per quarter from 48% to as low as 13%. A decrease in the amount of distributions paid by TEP to less than $0.3048 per TEP common unit per quarter would result in Tallgrass Equity not receiving any incremental cash distributions with respect to the IDRs for such quarter. As a result, any such reduction in quarterly cash distributions from TEP would have the effect of disproportionately reducing the amount of distributions that Tallgrass Equity receives from TEP in respect of the IDRs as compared to cash distributions TEP makes with respect to its common units and general partner interest.
Our distributions to our Class A shareholders are not cumulative.
Our distributions to our Class A shareholders are not cumulative. Consequently, if distributions on our Class A shares are not paid with respect to any fiscal quarter then our Class A shareholders will not be entitled to receive that quarter’s payments in the future.
The amount of cash that we and TEP distribute each quarter may limit our ability to grow.
Because we distribute all of our available cash, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. In fact, because our cash flow is generated solely from distributions we receive from Tallgrass Equity, which are derived from Tallgrass Equity’s direct and indirect partnership interests in TEP, our growth is currently completely dependent upon TEP. The amount of distributions received by Tallgrass Equity, including distributions in respect of the IDRs, is based on distributions paid on each TEP common unit, the number of TEP common units outstanding, the number of TEP common units owned by Tallgrass Equity and the general partnership interest owned by TEP GP. If we issue additional Class A shares without canceling an equivalent number of Class B shares, Tallgrass Equity incurs additional debt, we

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incur debt or we or Tallgrass Equity are required to pay taxes, the payment of distributions on those additional Class A shares or interest on that debt or payment of such taxes could increase the risk that we will be unable to maintain or increase our cash distribution levels.
Our rate of growth will be reduced to the extent we purchase additional equity interests from TEP, which will reduce the percentage of our cash flow that we receive from the IDRs.
Our business strategy includes, where appropriate, supporting the growth of TEP through the use of our capital resources, including by potentially purchasing TEP common units or lending funds to TEP to finance acquisitions or internal growth projects. To the extent we purchase common units or securities not entitled to a current distribution from TEP, the rate of our distribution growth will be reduced, at least in the short term, because a smaller percentage of our cash distributions would come from our ownership of the IDRs, which increase at a faster rate than TEP’s common units and any similar equity interests TEP may issue in the future.
Restrictions in Tallgrass Equity’s and TEP’s respective revolving credit facilities could limit Tallgrass Equity’s ability to make distributions to us, thereby limiting our ability to make distributions to our Class A shareholders. Any credit facility we enter into in the future could pose similar restrictions that would further limit our ability to make distributions.
Tallgrass Equity’s and TEP’s respective revolving credit facilities contain various operating and financial restrictions and covenants. Tallgrass Equity’s and TEP’s respective ability to comply with these restrictions and covenants may be affected by events beyond their control, including prevailing economic, financial and industry conditions. If Tallgrass Equity or TEP is unable to comply with these restrictions and covenants, any indebtedness under these revolving credit facilities may become immediately due and payable and Tallgrass Equity’s and TEP’s respective lenders’ commitment to make further loans under these revolving credit facilities may terminate. Tallgrass Equity or TEP might not have, or be able to obtain, sufficient funds to make these accelerated payments.
Tallgrass Equity’s payment of principal and interest on indebtedness reduces its cash distributions to us, thereby reducing our cash available for distribution on our Class A shares. Tallgrass Equity’s revolving credit facility would effectively prevent us from paying distributions to our Class A shareholders to the extent Tallgrass Equity is prohibited from making cash distributions during an event of default or if an event of default would result from the distribution.
We may enter into a credit facility in the future that would impose similar restrictions to those discussed above. In addition, our payment of principal and interest on any future indebtedness would reduce our cash available for distribution to our Class A shares.
For more information regarding Tallgrass Equity’s revolving credit facility, please see Note 10Long-term Debt to the Consolidated Financial Statements in Item 8.—Financial Statements and Supplementary Data. For more information regarding TEP’s revolving credit facility, please see the section "-Risks Related to TEP’s Business-TEP's revolving credit facility could adversely affect its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders."
Tallgrass Equity’s ownership in TEP’s IDRs, TEP’s common units and TEP’s general partner interest, are pledged under Tallgrass Equity’s revolving credit facility.
Tallgrass Equity’s direct ownership of the 20,000,000 TEP common units and its direct ownership of TEP’s general partner (which owns the IDRs and general partner interest) are pledged as security under Tallgrass Equity’s revolving credit facility. Tallgrass Equity’s revolving credit facility contains customary and other events of default. Upon an event of default, the lenders under Tallgrass Equity’s revolving credit facility could foreclose on Tallgrass Equity's ownership interest in TEP GP and the 20,000,000 TEP common units owned by Tallgrass Equity, which are the only assets from which our cash flows are derived. Additionally, this foreclosure could ultimately result in a change in control of TEP GP, which would constitute an immediate event of default under TEP’s credit facility. This would have a material adverse effect on our business, financial condition and results of operations.
Our shareholders do not vote in the election of our general partner’s directors. The Exchange Right Holders own a sufficient number of shares to allow them to prevent the removal of our general partner.
Our shareholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. The board of directors of our general partner, including our independent directors, is designated and elected by Tallgrass Energy Holdings or its designees. Our shareholders do not have the ability to elect our general partner or the members of the board of directors of our general partner.
In addition, if our Class A shareholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. Our general partner may not be removed except by vote of the holders of at least 80% of our outstanding shares, voting together as a single class. The Exchange Right Holders own 69.95% of our outstanding shares. This ownership level enables the Exchange Right Holders to prevent our general partner’s removal.

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As a result of these provisions, the price at which our shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
If TEP’s unitholders remove TEP GP, TEP GP may be required to sell or exchange its IDRs and general partner interest and TEP GP would lose the ability to manage and control TEP.
TEP’s partnership agreement gives unitholders of TEP the right to remove TEP GP upon the affirmative vote of holders of 66 2/3% of TEP’s outstanding units. If TEP GP withdraws as general partner in compliance with TEP’s partnership agreement or is removed as general partner of TEP where cause (as defined in TEP’s partnership agreement) does not exist and a successor general partner is elected in accordance with TEP’s partnership agreement, TEP GP could elect to receive cash in exchange for its IDRs and general partner interest. If TEP GP withdraws in circumstances other than those described in the preceding sentence and a successor general partner is elected in accordance with TEP’s partnership agreement, the successor general partner will have the option to purchase the IDRs and general partner interest for their fair market value. If TEP GP or the successor general partner do not exercise their options, TEP GP’s interests would be converted into common units based on an independent valuation. In each case, TEP GP would also lose its ability to manage TEP.
In addition, if TEP GP is removed as general partner of TEP, we would face an increased risk of being deemed an investment company. Please read the section entitled "-If in the future we cease to manage and control TEP, we may be deemed to be an investment company under the Investment Company Act of 1940."
Our general partner may cause us to issue additional Class A shares or other equity securities, including equity securities that are senior to our Class A shares, without your approval, which may adversely affect you.
Our general partner may cause us to issue an unlimited number of additional Class A shares, or other equity securities of equal rank with the Class A shares, without shareholder approval. In addition, we may issue an unlimited number of shares that are senior to our Class A shares in right of distribution, liquidation and voting. Except for Class A shares issued in connection with the exercise by any Exchange Right Holder of its right to exchange a Class B share for a Class A share (the "Exchange Right"), each of which will result in the cancellation of an equivalent number of Class B shares and therefore have no effect on the total number of outstanding shares, the issuance of additional Class A shares, or other equity securities of equal or senior rank, may have the following effects:
each shareholder’s proportionate ownership interest in us may decrease;
the amount of cash available for distribution on each Class A share may decrease;
the relative voting strength of each previously outstanding Class A share may be diminished;
the ratio of taxable income to distributions may increase; and
the market price of the Class A shares may decline.
You may not have limited liability if a court finds that shareholder action constitutes control of our business.
Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our shareholders (who hold limited partner interests despite the fact that we use the term "shareholder" in this Annual Report) as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the "control" of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.
Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a shareholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
If in the future we cease to manage and control TEP we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to indirectly manage and control TEP and are deemed to be an investment company under the Investment Company Act of 1940, we would have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict the ability of TEP GP, Tallgrass Equity, TEP and us to borrow funds or engage in other transactions involving leverage, require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of our Class A shares.

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Our partnership agreement restricts the rights of shareholders owning 20% or more of our shares.
Our shareholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any shares held by a person or group that owns 20% or more of any class of shares then outstanding, other than our general partner, the Exchange Right Holders or their respective affiliates and persons who acquired such shares with the prior approval of our general partner’s board of directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our shareholders to call meetings or to acquire information about our operations, as well as other provisions limiting our shareholders’ ability to influence the manner or direction of our management. As a result, the price at which our Class A shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
If TEP GP, which is owned by Tallgrass Equity, is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of TEP, its value, and, therefore, the value of our Class A shares, could decline.
TEP GP and its affiliates may make expenditures on behalf of TEP for which TEP GP will seek reimbursement from TEP. Under Delaware partnership law, TEP GP has unlimited liability for the obligations of TEP, such as its debts and environmental liabilities, except for those contractual obligations of TEP that are expressly made without recourse to the general partner. To the extent TEP GP incurs obligations on behalf of TEP, it is entitled to be reimbursed or indemnified by TEP. If TEP is unable or unwilling to reimburse or indemnify TEP GP, TEP GP may not be able to satisfy those liabilities or obligations, which would reduce TEP GP’s cash distributions to Tallgrass Equity and ultimately to us for the benefit of our Class A shareholders.
Our Class A shares and TEP’s common units may not trade in relation or proportion to one another.
Our Class A shares and TEP’s common units may not trade in simple relation or proportion to one another. Instead, while the trading prices of our Class A shares and TEP’s common units are likely to follow generally similar broad trends, the trading prices may diverge because, among other things:
TEP’s cash distributions to its common unitholders have a priority over distributions on its IDRs;
we participate in the distributions on the IDRs and general partner interest in TEP while TEP’s common unitholders do not;
we expect to pay federal income taxes in the future; and
we may pursue business opportunities separate and apart from TEP or any of its affiliates.
An increase in interest rates may cause the market price of our shares to decline.
Like all equity investments, an investment in our Class A shares is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partner interests. Reduced demand for our Class A shares resulting from investors seeking other more favorable investment opportunities may cause the trading price of our Class A shares to decline.
Future sales of our Class A shares in the public market, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, could reduce our Class A share price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
Subject to certain limitations and exceptions, the Exchange Right Holders may cause the exchange of their Tallgrass Equity units (together with a corresponding number of Class B shares) for Class A shares (on a one-for-one basis, subject to customary conversion rate adjustments for equity splits and reclassification and other similar transactions) and then sell those Class A shares. We may also issue additional Class A shares or convertible securities in subsequent public or private offerings.
We cannot predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that future issuances and sales of our Class A shares, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, will have on the market price of our Class A shares. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.
Tallgrass Energy Holdings has sole authority to elect the board of directors of our general partner.
Tallgrass Energy Holdings has the ability to elect all of the members of our board of directors. In addition, Tallgrass Energy Holdings is able to determine the outcome of all matters requiring shareholder approval, including certain mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our shareholders of an opportunity to receive a premium for their Class A shares as part of a sale of our company. The Exchange Right Holders currently own 100% of the voting interests in Tallgrass Energy

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Holdings and entities and/or investment funds affiliated with (i) The Energy & Minerals Group, (ii) Kelso & Company and (iii) members of our and TEP’s management each have the right to designate two members of the board of managers of Tallgrass Energy Holdings for so long as they maintain certain ownership percentages in Tallgrass Energy Holdings. Tallgrass Energy Holdings currently has a six person board of managers. Tallgrass Energy Holdings continues to be able to strongly influence all matters requiring shareholder approval, regardless of whether or not shareholders believe that the transaction is in their own best interests.
A valuation allowance on our deferred tax asset could reduce our earnings.
A significant deferred tax asset was recorded as a result of certain reorganization transactions completed in connection with the Offering. GAAP requires that a valuation allowance must be established for deferred tax assets when it is more likely than not that they will not be realized. If we were to determine that a valuation allowance was appropriate for our deferred tax asset, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ equity and increase in balance sheet leverage as measured by debt to total capitalization.
The NYSE does not require a limited partnership like us or TEP to comply with certain of its corporate governance requirements.
Because we and TEP are limited partnerships, the New York Stock Exchange, or NYSE, does not require our general partner or TEP’s general partner to have a majority of independent directors on their respective board of directors. The NYSE also does not require our general partner or TEP’s general partner to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our shareholders and TEP’s unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. In addition, as limited partnerships, we and TEP are not required to seek shareholder or unitholder approval, as appropriate, for issuances of Class A shares or TEP common units, respectively, including issuances in excess of 20% of outstanding equity securities, or for issuances of equity to certain affiliates.
We may incur liability as a result of our ownership of TEP’s general partner.
Under Delaware law, a general partner of a limited partnership is generally liable for the debts and liabilities of the partnership for which it serves as general partner, subject to the terms of any indemnification agreements contained in the partnership agreement and except to the extent the partnership’s contracts are non-recourse to the general partner. As a result of our structure, we indirectly own and control the general partner of TEP. To the extent the indemnification provisions in TEP’s partnership agreement or non-recourse provisions in our contracts are not sufficient to protect TEP GP from such liability, we may in the future incur liabilities as a result of our indirect ownership of TEP’s general partner. Please read the section entitled "-Risks Related to Conflicts of Interest."
For as long as we are an emerging growth company, we are not required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.
In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act of 2012 (the "JOBS Act"). The JOBS Act contains provisions that, among other things, relax certain reporting requirements for "emerging growth companies," including certain requirements relating to accounting standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we are not required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes Oxley Act of 2002, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board (the "PCAOB") requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise, (4) provide certain disclosure regarding executive compensation required of larger public companies or (5) hold unitholder advisory votes on executive compensation.
If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
We are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we are required to disclose material changes made to our internal controls and procedures on a quarterly basis, we are not required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we need to implement additional internal controls, reporting systems and procedures and may need to hire additional accounting,

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finance and legal staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2015, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an "emerging growth company" within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2020 if we continue to maintain our emerging growth company status for a full five years. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A shares.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results will be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A shares.
Risks Related to Conflicts of Interest
Our existing organizational structure and the relationships among us, TEP, our respective general partners, Tallgrass Energy Holdings, the owners of Tallgrass Energy Holdings, including the Exchange Right Holders, and their affiliated entities present the potential for conflicts of interest. Moreover, additional conflicts of interest may arise in the future among us and the entities affiliated with any general partner or similar interests we acquire or among TEP and such entities.
Conflicts of interest may arise as a result of our organizational structure and the relationships among us, TEP, our respective general partners, TEGP, the owners of Tallgrass Energy Holdings, including the Exchange Right Holders, and their affiliated entities.
Our partnership agreement defines the duties of our general partner (and, by extension, its officers and directors). Our general partner’s board of directors or its conflicts committee has authority on our behalf to resolve any conflict involving us and they have broad latitude to consider the interests of all parties to the conflict.
Conflicts of interest may arise between us and our shareholders, on the one hand, and our general partner and its direct and indirect owners, including Tallgrass Energy Holdings and the Exchange Right Holders, and affiliated entities, on the other hand, or between us and our shareholders, on the one hand, and TEP and its unitholders, on the other hand. The resolution of these conflicts may not always be in our best interest or that of our shareholders.
The Exchange Right Holders own 100% of the voting interests in Tallgrass Energy Holdings and hold a majority of the combined voting power of our Class A and Class B shares.
The Exchange Right Holders own 100% of the voting interests in Tallgrass Energy Holdings and hold approximately 69.65% of the combined voting power of our Class A and Class B shares. Although each of the Exchange Right Holders are entitled to act separately in their own respective interests with respect to their ownership interest in Tallgrass Energy Holdings and us, the Exchange Right Holders collectively have the ability to elect all of the members of Tallgrass Energy Holdings’ board of managers, each of whom serves as a member of the board of directors of our general partner. So long as any of the Exchange Right Holders continue to own a significant amount of the voting interests in Tallgrass Energy Holdings, they will continue to be able to control our management and affairs.
Tallgrass Energy Holdings may have interests that conflict with holders of our Class A shares.
Tallgrass Energy Holdings owns our general partner and may have conflicting interests with holders of Class A shares.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Tallgrass Energy Holdings, on the other hand, concerning, among other things, a decision whether to modify or limit the IDRs in the future or potential competitive business activities or business opportunities. These conflicts of interest may not be resolved in our favor.

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Our partnership agreement replaces our general partner’s fiduciary duties to holders of our Class A shares with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our shareholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the shareholders where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our shareholders. Examples of decisions that our general partner may make in its individual capacity include:
how to allocate business opportunities among us and its affiliates;
whether to exercise its limited call right;
whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
how to exercise its voting rights with respect to the units it owns; and
whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.
In addition, our partnership agreement provides that any construction or interpretation of our partnership agreement and any action taken pursuant thereto or any determination, in each case, made by our general partner in good faith, shall be conclusive and binding on all shareholders.
By purchasing shares, you agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.
Our general partner’s affiliates and Tallgrass Energy Holdings may compete with us.
Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. The restrictions contained in our general partner’s limited liability company agreement are subject to a number of exceptions. For example, affiliates of our general partner, including Tallgrass Energy Holdings, the Exchange Right Holders, and their respective affiliates, are not prohibited from engaging in other businesses or activities that might be in direct competition with us.
Our general partner has a call right that may require you to sell your Class A shares at an undesirable time or price.
If at any time more than 80% of our outstanding shares (including Class A shares issuable upon the exchange of Class B shares) are owned by our general partner, Tallgrass Energy Holdings or their respective affiliates, our general partner has the right (which it may assign to any of its affiliates, Tallgrass Energy Holdings or us), but not the obligation, to acquire all, but not less than all, of the remaining Class A shares held by public shareholders at a price equal to the greater of (x) the highest cash price paid by our general partner, Tallgrass Energy Holdings, or their respective affiliates for any shares purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those shares and (y) the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed. As a result, you may be required to sell your Class A shares at an undesirable time or price and may not receive any return of or on your investment. The Board of Directors of Tallgrass Energy Holdings recently authorized an equity purchase program under which Tallgrass Development may initially purchase up to an aggregate of $100 million of our outstanding Class A shares. You may also incur a tax liability upon a sale of your Class A shares.
Risks Related to TEP's Business
TEP may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to its general partner and its affiliates, to enable TEP to pay the quarterly distribution at the current distribution level, or at all, to holders of TEP common units.
TEP may not have sufficient available cash from operating surplus each quarter to enable it to pay the quarterly distribution at the current distribution level, at the minimum quarterly distribution level, or at all. The amount of cash TEP can distribute on its units principally depends upon the amount of cash TEP generates from its operations, which will fluctuate from quarter to quarter based on, among other things:
the level of firm services TEP provides to customers pursuant to firm fee contracts and the volume of customer products TEP transports, stores, processes, gathers, treats and disposes using its assets;

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its ability to renew or replace expiring long-term firm fee contracts with other long-term firm fee contracts;
the creditworthiness of its customers, particularly customers who are subject to firm fee contracts;
its ability to complete and integrate acquisitions from Tallgrass Development or from third parties;
the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of natural gas, NGLs, crude oil and other hydrocarbons;
regional, domestic and foreign supply and perceptions of supply of natural gas, crude oil and other hydrocarbons;
the level of demand and perceptions of demand in end-user markets TEP directly or indirectly serves;
actual and anticipated future prices of natural gas, crude oil and other commodities (and the volatility thereof);
applicable laws and regulations affecting TEP and its customers' business, including the market for natural gas, crude oil, other hydrocarbons and water, the rates TEP can charge on its assets, how TEP contracts for services, its existing contracts, its operating costs or its operating flexibility;
prevailing economic conditions.
changes in the fees TEP charges for its services, including firm services and interruptible services;
the effect of seasonal variations in temperature and climate on the amount of customer products TEP is able to transport, store, process, gather, treat and dispose using its assets;
the realized pricing impacts on revenues and expenses that are directly related to commodity prices;
the level of competition from other midstream energy companies in its geographic markets;
the level of its operating and maintenance costs;
damage to its assets and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters or acts of terrorism;
outages in its assets;
the relationship between natural gas and NGL prices and resulting effect on processing margins; and
leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise.
In addition, the actual amount of cash TEP will have available for distribution will depend on other factors, including:
its ability to borrow funds and access capital markets;
the level, timing and characterization of capital expenditures TEP makes;
the level of its general and administrative expenses, including reimbursements to its general partner and its affiliates, including Tallgrass Development, for services provided to TEP;
the cost of pursuing and completing acquisitions, if any;
its debt service requirements and other liabilities;
fluctuations in its working capital needs;
restrictions contained in its debt agreements;
the amount of cash reserves established by its general partner; and
other business risks affecting its cash levels.
If TEP is not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, its financial condition, results of operation, cash flows and ability to make cash distributions to its unitholders will be adversely affected.
TEP transports, stores and processes a substantial majority of its customers' products, including natural gas, crude oil, and water, on its systems under long-term firm fee contracts with terms of various durations. For the year ended December 31, 2015, approximately 94% of its natural gas transportation and storage revenues were generated under firm fee transportation and storage contracts and approximately 94% of its crude oil transportation revenues were generated under firm fee transportation contracts. As of December 31, 2015, the weighted average remaining life of its long-term natural gas transportation contracts and natural gas storage contracts was approximately two and six years, respectively, the weighted

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average remaining life of its oil transportation contracts was approximately four years, and the weighted average remaining life of its natural gas processing contracts was approximately three years. As these contracts expire, TEP may be unable to obtain new contracts on terms similar to those of its existing contracts, or at all. If TEP is unable to promptly resell capacity from expiring contracts on equivalent terms, its revenues may decrease and its ability to make cash distributions to its unitholders may be materially impaired.
For example, over the past several years, a number of TEP's natural gas transportation and storage customers have opted not to renew their contracts for service on the TIGT System. We believe those non-renewals have been caused both by increased competition from large diameter long-haul pipeline systems that are more efficient and cost effective at transporting natural gas over long distances, as well as reduced drilling activity for dry gas in the Rocky Mountain region. These former customers are generally large producers that primarily used the TIGT System to access interstate pipelines for ultimate delivery to consuming markets outside TEP's areas of operations, as opposed to TEP's current customer base, which is primarily comprised of on-system regional customers, such as LDCs. The non-renewal of these transportation contracts has resulted in decreases in firm contracted capacity on the TIGT System and related decreases in total revenue. For example, TEP's average firm contracted capacity decreased from 842 MMcf/d for the year ended December 31, 2010 to 621 MMcf/d for the year ended December 31, 2015 and transportation services revenue decreased from $143.4 million to $94.9 million over the same period, primarily due to the loss of revenue from the non-renewal of transportation contracts.
TEP also may be unable to maintain the long-term nature and economic structure of its current contract portfolio over time. Depending on prevailing market conditions at the time of a contract renewal, transportation, storage and processing customers with fee-based contracts may desire to enter into contracts under different fee arrangements, and its potential customers may be generally unwilling to enter into long-term contracts. In the current commodity environment, which has included significant price reduction and volatility in crude oil, natural gas and other hydrocarbons over the past 18 months, TEP expects customers will generally be less likely to enter into long-term firm fee contracts until prices recover and stability returns to the commodity markets. To the extent TEP is unable to renew or replace its existing contracts on terms that are favorable to TEP or successfully manage the long-term nature and economic structure of its contract profile over time, its revenues and cash flows could decline and its ability to make distributions to its unitholders could be materially and adversely affected. In addition, if an existing customer terminates or breaches its long-term firm transportation, storage or processing contract, TEP may be subject to a loss of revenue if TEP is unable to promptly resell the capacity to another customer on substantially equivalent terms.
TEP's ability to renew or replace its expiring contracts on terms similar to, or more attractive than, those of its existing contracts is uncertain and depends on a number of factors beyond its control, including:
the level of existing and new competition to provide competing services to its markets;
the macroeconomic factors affecting crude oil and natural gas gathering economics for its current and potential customers;
the balance of supply and demand for natural gas, crude oil and other hydrocarbons, on a short-term, seasonal and long-term basis, in the markets TEP serves;
the extent to which the current and potential customers in its markets are willing to contract on a long-term basis; and
the effects of federal, state or local laws or regulations on the contracting practices of its customers.
TEP is exposed to the creditworthiness and performance of its customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect its financial condition, cash flows, and operating results.
Although TEP attempts to assess the creditworthiness of its customers, suppliers and contract counterparties, there can be no assurance that its assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on its business, results of operations, financial condition and ability to make cash distributions to its unitholders. TEP's long-term firm fee contracts obligate its customers to pay demand charges regardless of whether they utilize its assets, except for certain circumstances outlined in applicable customer agreements. As a result, during the term of its long-term firm fee contracts and absent an event of force majeure, its revenues will generally depend on its customers’ financial condition and their ability to pay rather than upon the amount of natural gas or crude oil transported. The recent decline in natural gas and crude oil prices has negatively impacted the financial condition of TEP's customers and further declines, sustained lower prices, or continued volatility could impact their ability to meet their financial obligations to TEP. Further, TEP's contract counterparties may not perform or adhere to TEP's existing or future contractual arrangements. To the extent one or more of TEP's contract counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material nonpayment or nonperformance by TEP's contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could have a material adverse impact on its business, results of operations, financial condition and ability to make cash distributions to its unitholders.

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The procedures and policies TEP uses to manage its exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. In accordance with FERC regulations and its own internal credit policies, counterparties with investment grade credit ratings are deemed able to meet their financial obligations to TEP without requiring credit support in the form of a letter of credit or prepayment. With the recent decline in natural gas and crude oil prices and the corresponding deterioration of the financial condition of some of its customers, it is possible that some may lose their investment grade credit rating. If this were to occur, TEP would likely ask for credit support and the customer may be unwilling or unable to provide it due to liquidity constraints. To the extent its procedures and policies prove to be inadequate or TEP is unable to obtain credit support, its financial position and results of operations may be negatively impacted.
Some of TEP's counterparties may be highly leveraged or have limited financial resources and are subject to their own operating and regulatory risks. Even if its credit review and analysis mechanisms work properly, TEP may experience financial losses in its dealings with such parties. As seen with the recent decline in crude oil prices, prices for crude oil and natural gas are subject to large fluctuations in response to changes in supply and demand, market uncertainty and a variety of other factors that are beyond its control. Such volatility in commodity prices might have an impact on many of TEP's counterparties and their ability to borrow and obtain additional capital on attractive terms, which, in turn, could have a negative impact on their ability to meet their obligations to TEP and may also increase the magnitude of these obligations.
Any material nonpayment or nonperformance by TEP's counterparties could require TEP to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.
TEP depends on certain key customers for a significant portion of its revenues and is exposed to credit risks of these customers. The loss of or material nonpayment or nonperformance by any of these key customers could adversely affect its cash flow and results of operations.
TEP relies on certain key customers for a portion of revenues. For example, for the year ended December 31, 2015, Continental Resources and Shell accounted for approximately 28% and 19% of its segment revenue in the Crude Oil Transportation & Logistics segment, respectively, and approximately 16% and 15% of its revenues on a consolidated basis, respectively. In addition, for the year ended December 31, 2015, 55% of its consolidated revenues were represented by the top ten customers on its Pony Express System.
TEP may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms. In addition, some of these key customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by its customers could limit its ability to collect amounts owed to TEP, or to enforce performance of obligations under contractual arrangements. To the extent one or more of TEP's key customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Additionally, many of its customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of TEP's customers’ liquidity and limit their ability to make payments or perform on their obligations to TEP. Furthermore, some of TEP's customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to TEP. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on its business, cash flows, ability to make distributions to its unitholders, the price of its units, its results of operations and ability to conduct its business.
The revenue in TEP's Processing and Logistics segment largely depends on the amount of natural gas that its customers actually deliver to its natural gas processing plants.
As of December 31, 2015, approximately 92% of TEP's reserved capacity at its Casper and Douglas natural gas processing plants was subject to firm or volumetric fee contracts, with the majority of the fee revenue being based on the volumes actually processed (the remaining 8% was subject to commodity sensitive contracts such as percent of proceeds or keep whole processing contracts).  On these volumetric fee contracts, TEP's revenue is largely tied to the amount of natural gas that its customers actually deliver its Casper and Douglas plants for processing.  Unlike many pipeline transportation customers, TEP's natural gas processing customers are not generally subject to "take or pay" obligations.  Thus, if its natural gas processing customers do not produce natural gas and deliver that natural gas to its processing plants to be processed, revenue for its Processing and Logistics segment will decline.  As natural gas, crude oil or NGL prices decline, which has been the case since the latter half of 2014, TEP's customers will likely make less money from the production of natural gas, crude oil or NGLs than it costs them to produce it.  If that happens, its customers may not continue to produce natural gas and its revenue will decline.  The decreased commodity prices in late 2015 and into early 2016 contributed to a significant drop in actual and anticipated volumes from several producers from which TMID receives natural gas for processing. If a gradual recovery of commodity

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prices and a corresponding increase in volumes over time to TMID does not occur, we could have an impairment of the goodwill at the TMID reporting unit, which is a component of our Processing & Logistics segment, and our revenue will decline. In addition, the fees its customers pay to reserve capacity at its processing plants may not deter those customers from processing their natural gas volumes at other facilities, with whom they may have had prior arrangements or otherwise.
TEP has only recently commenced operating its newly acquired water business services assets in Weld County, Colorado, and TEP may not achieve all the benefits anticipated.
On December 16, 2015, TEP purchased water business services assets located in Weld County, Colorado, including a gathering and disposal system for water removed from a well as a byproduct of exploration and production activities, which it generally refers to as produced water. Gathering and disposal of produced water is a new water business activity for TEP, as its water business operations was previously focused on the transportation of freshwater. Operating a produced water gathering and disposal system involves different risks and requires different operating strategies and managerial expertise than its current operations. In addition, gathering and disposing produced water is subject to more stringent laws and regulations than transporting freshwater, particularly those related to environmental matters. Failure to timely and successfully develop this new water business activity in conjunction with its existing operations could result in its failure to achieve the benefits anticipated and may have a material adverse effect on its business, financial condition and results of operations.
TEP may not be able to compete effectively in its midstream services activities and its business is subject to the risk of a capacity overbuild of midstream energy infrastructure in the areas where TEP operates.
TEP faces competition in all aspects of its business and may not be able to compete effectively against its competitors. In general, competition comes from a wide variety of players in a wide variety of contexts, including new entrants and existing players and in connection with day-to-day business, expansion capital projects, acquisitions and joint venture activities. Some of its competitors have capital resources greater than TEP's and control greater supplies of crude oil, natural gas or NGLs.
TEP's ability to renew or replace its existing contracts at rates sufficient to maintain current revenues and current cash flows could be adversely affected by the activities of its competitors. In addition, some of its competitors have assets in closer proximity to hydrocarbon supplies and have available idle capacity in existing assets that would not require new capital investments for use. For example, several pipelines access many of the same basins as its natural gas pipeline systems and transport gas to customers in the Rocky Mountain and Midwest regions of the United States. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil benchmarks (West Texas Intermediate Crude and Brent Crude). Other crude oil pipeline projects have been announced recently that would compete directly with its Pony Express System. Furthermore, Tallgrass Development and its affiliates are not limited in their ability to compete with TEP.
TEP's competitors may expand or construct new midstream services assets that would create additional competition for the services TEP provides to its customers, or its customers may develop their own facilities in lieu of using TEP's. A significant driver of competition in some of the markets where TEP operates (including, for example, the Rocky Mountain region) has seen the rapid development of new midstream energy infrastructure capacity in recent years. As a result, TEP is exposed to the risk that the areas in which TEP operates become overbuilt, resulting in an excess of midstream energy infrastructure capacity. If TEP experiences a significant capacity overbuild in one or more of the areas where TEP operates, it could have a significant adverse impact on its financial position, cash flows and ability to pay or increase distributions to its unitholders. For example, TEP's competitors in these areas could substantially decrease the prices at which they offer their services, and TEP may be unable to compete effectively. This could materially impair its cash flows and ability to make distributions to its unitholders.
Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users, including electricity, coal and other liquid fuels. Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a reduction in demand for TEP's services.
All of these competitive pressures could make it more difficult for TEP to renew its existing long-term firm fee contracts when they expire or to attract new customers as TEP seeks to expand its business, which could have a material adverse effect on its business, financial condition, results of operations and prospects. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas and crude oil in the markets TEP serves, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas or crude oil.
If TEP is unable to make acquisitions on economically acceptable terms from Tallgrass Development or third parties, its future growth will be limited, and the acquisitions TEP does make may reduce, rather than increase, its cash generated from operations on a per unit basis.
TEP's ability to grow depends, in part, on its ability to make acquisitions that increase its cash generated from operations on a per unit basis.

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The acquisition component of TEP's strategy is based, in part, on its expectation of ongoing divestitures of midstream energy assets by industry participants, including Tallgrass Development. Other than Tallgrass Development’s obligation to offer TEP certain assets (if Tallgrass Development decides to sell such assets) pursuant to the right of first offer under the TEP Omnibus Agreement, TEP has no contractual arrangement with Tallgrass Development that would require it to provide TEP with an opportunity to acquire midstream assets that it may sell. Accordingly, while we believe Tallgrass Development will be incentivized pursuant to its economic relationship with TEP to offer TEP opportunities to purchase midstream assets, there can be no assurance that any such offer will be made, and there can be no assurance TEP will reach agreement on the terms with respect to any acquisition opportunities offered to TEP by Tallgrass Development. Furthermore, many factors could impair TEP's access to future midstream assets, including a change in control of Tallgrass Development or a transfer of the IDRs by TEP's general partner to a third party. A material decrease in divestitures of midstream energy assets from Tallgrass Development or otherwise would limit TEP's opportunities for future acquisitions and could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
TEP's future growth and ability to increase distributions will be limited if TEP is unable to make accretive acquisitions from Tallgrass Development or third parties because, among other reasons, (i) Tallgrass Development elects not to sell or contribute additional assets to TEP or to offer acquisition opportunities to TEP, (ii) TEP is unable to identify attractive third-party acquisition opportunities, (iii) TEP is unable to negotiate acceptable purchase contracts with Tallgrass Development or third parties, (iv) TEP is unable to obtain financing for these acquisitions on economically acceptable terms, (v) TEP is outbid by competitors or (vi) TEP is unable to obtain necessary governmental or third-party consents. Furthermore, even if TEP does make acquisitions that TEP believes will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
Any acquisition involves potential risks, including, among other things:
mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities;
an inability to integrate successfully the assets or businesses TEP acquires;
the assumption of unknown liabilities for which TEP is not indemnified or for which its indemnity is inadequate;
the diversion of management’s and employees’ attention from other business concerns;
unforeseen difficulties operating in new geographic areas or business lines; and
a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to finance an acquisition.
If any acquisition eventually proves not to be accretive to TEP's distributable cash flow per unit, it could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
If TEP is unable to obtain needed capital or financing on satisfactory terms to fund expansions of its asset base, its ability to make quarterly cash distributions may be diminished or its financial leverage could increase.
In order to expand TEP's asset base through acquisitions or capital projects, TEP may need to make expansion capital expenditures. If TEP does not make sufficient or effective expansion capital expenditures, TEP will be unable to expand its business operations and may be unable to maintain or raise the level of its quarterly cash distributions. TEP could be required to use cash from its operations or incur borrowings or sell additional common units or other limited partner interests in order to fund its expansion capital expenditures. Using cash from operations will reduce cash available for distribution to its common unitholders. TEP's ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by its financial condition at the time of any such financing or offering as well as the covenants in its debt agreements, general economic conditions and contingencies and uncertainties that are beyond its control. The recent downturn in the energy capital markets has negatively impacted the cost at which TEP can issue public debt and equity and has altered some of its financing plans. Even if TEP is successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit its ability to pay distributions to its common unitholders. In addition, incurring additional debt may significantly increase its interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease its ability to pay distributions at the then-current distribution rate.
TEP does not currently have any commitment with its general partner or other affiliates, including Tallgrass Development, to provide any direct or indirect financial assistance to TEP.

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Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect TEP's business and results of operations.
TEP's business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy demand and lower prices for its services and increased difficulty in collecting amounts owed to TEP by its customers which could reduce its access to credit markets, raise the cost of such access or require TEP to provide additional collateral to its counterparties. TEP's ability to access available capacity under its revolving credit facility could be impaired if one or more of its lenders fails to honor its contractual obligation to lend to TEP. If financing is not available when needed, or is available only on unfavorable terms, TEP may be unable to implement its business plans or otherwise take advantage of business opportunities or respond to competitive pressures. While the recent downturn in the energy capital markets has not changed its business plans, it has altered some of its financing strategies.
The amount of cash TEP has available for distribution to unitholders depends primarily on its cash flow rather than on its profitability, which may prevent TEP from making distributions, even during periods in which TEP records net income.
The amount of cash TEP has available for distribution depends primarily upon its cash flow and not solely on profitability, which will be affected by non-cash items. As a result, TEP may make cash distributions during periods when TEP records losses for financial accounting purposes and may not make cash distributions during periods when TEP records net earnings for financial accounting purposes.
TEP is exposed to direct commodity price risk with respect to some of its processing revenues, and its exposure to direct commodity price risk may increase in the future.
TEP's Processing & Logistics segment operates under three types of contracts, two of which directly expose its cash flows to increases and decreases in the price of natural gas and NGLs: percent of proceeds and keep whole processing contracts. As of December 31, 2015, approximately 8% of the reserved capacity in its Processing & Logistics segment was contracted under percent of proceeds or keep whole processing contracts. TEP does not currently hedge the commodity exposure inherent in these types of processing contracts, and as a result, its revenues and results of operations are impacted by fluctuations in the prices of natural gas and NGLs.
Percent of proceeds processing contracts generally provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under keep whole processing contracts, TEP's revenues and its cash flows generally increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect its profitability. When natural gas prices are low relative to NGL prices, it is more profitable for TEP to process natural gas under keep whole arrangements. When natural gas prices are high relative to NGL prices, it is less profitable for TEP and its customers to process natural gas both because of the higher value of natural gas and the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, TEP may experience periods in which higher natural gas prices relative to NGL prices reduce its processing margins or reduce the volume of natural gas processed at some of its plants. In addition, NGL prices have historically been related to the market price of oil and as a result any significant changes in oil prices could also indirectly impact its operations. Indirectly, reduced commodity prices impact TEP through reduced exploration and production activity, which results in fewer opportunities for new business to offset natural volume declines. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. In 2015 natural gas and oil prices declined substantially and these declines directly and indirectly resulted in lower processing volumes and realizations on its percent of proceeds and keep whole processing contracts.
If third-party pipelines or other facilities interconnected to TEP's systems become partially or fully unavailable, or if the volumes TEP transports do not meet the quality requirements of such pipelines or facilities, its revenues and its ability to make distributions to its unitholders could be adversely affected.
TEP's assets typically connect to other pipelines or facilities owned, leased and/or operated by unaffiliated third parties, such as Phillips 66, Deeprock Development, LLC, Whiting, and others. For example, the Powder River pipeline, owned by Phillips 66, is currently the only pipeline outlet for the NGLs that TEP produces and thus a substantial majority of the NGLs TEP produces are sold to Phillips 66 at the tailgate of the Douglas plant. Accordingly, the failure to renew its agreement (which expires on December 31, 2016) with Phillips 66 without securing another outlet for the NGLs or any downtime on this pipeline as a result of maintenance or force majeure would adversely affect TEP.
As a further example, TEP's Pony Express System connects to upstream joint tariff pipelines, including the Belle Fourche Pipeline owned by the True Companies (which also own and operate the Bridger Pipeline) and the Double H Pipeline owned by Kinder Morgan, Inc., which are responsible for delivering a substantial portion of the crude oil for transportation on the Pony Express System. In addition, nearly all of the crude oil TEP transports on the Pony Express System is either stored in crude oil tanks located on, or pumped over to downstream pipelines that interconnect through, the Deeprock Development terminal

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facility in Cushing, Oklahoma. The continuing operation of such third-party facilities and other midstream facilities is not within its control. These pipelines, plants and other midstream facilities may become unavailable to TEP for any number of reasons, including because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from weather events or other operational hazards. For example, the operations of the Bridger Pipeline’s Poplar System were down for approximately five months during the first half of 2015 due to a pipeline release. Bridger declared a force majeure as a result of this event and temporarily lacked the capacity to make up volumes on other lines that directly or indirectly deliver crude oil into designated origin points on the Pony Express System or the Belle Fourche Pipeline. The largest committed shipper on the Pony Express System also declared a force majeure as a result of this incident.
If the costs to TEP to access and transport on these third-party pipelines or any alternative pipelines significantly increase, its ability to make cash distributions to its unitholders could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport, store or process products from its assets, or if the volumes TEP transports or processes do not meet the quality requirements of such pipelines or facilities, its revenues and its ability to make quarterly cash distributions to its unitholders could be adversely affected.
TEP's success depends on the supply and demand for natural gas and crude oil.
The success of TEP's business is in many ways impacted by the supply and demand for natural gas and crude oil. For example, its business can be negatively impacted by sustained downturns in supply and demand for natural gas and crude oil in the markets that TEP serves, including reductions in its ability to renew contracts on favorable terms and to construct new infrastructure. Further, a portion of the demand for its water business services depends substantially on the level of expenditures by the oil and gas industry for the exploration, development and production of oil and natural gas reserves. These expenditures are generally dependent on the industry’s view of future oil and natural gas prices and are sensitive to the industry’s view of future economic growth and the resulting impact on demand for oil and natural gas. Declines, as well as anticipated declines, in oil and gas prices could also result in project modifications, delays or cancellations, general business disruptions, and delays in, or nonpayment of, amounts that are owed to TEP. These effects could have a material adverse effect on its financial condition, results of operations and cash flows.
One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. One of the major factors impacting domestic natural gas and crude oil supplies has been the significant growth in unconventional sources such as shale plays and the continued progression of hydraulic fracturing technology. The supply and demand for natural gas and crude oil, and therefore the future rate of growth of TEP's business, depends on these and many other factors outside of its control, including, but not limited to:
adverse changes in general global economic conditions;
adverse changes in domestic regulations;
technological advancements that may drive further increases in production and reduction in costs of developing natural gas shales;
the price and availability of other forms of energy;
prices for natural gas, crude oil and NGLs;
decisions of the members of Organization of the Petroleum Exporting Countries, or OPEC, regarding price and production controls;
increased costs to explore for, develop, produce, gather, process and transport hydrocarbons or water;
weather conditions, seasonal trends and hurricane disruptions;
the nature and extent of, and changes in, governmental regulation, for example GHG legislation, taxation and hydraulic fracturing;
perceptions of customers on the availability and price volatility of its services and natural gas and crude oil prices, particularly customers’ perceptions on the volatility of natural gas and crude oil prices over the long-term;
capacity and transportation service into, or out of, its markets; and
petrochemical demand for NGLs.

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The oil and gas industry historically has experienced periodic downturns, and is currently experiencing a period of low commodity prices. In the fourth quarter of 2014 and subsequent to December 31, 2014, the prices of crude oil, natural gas and NGLs were extremely volatile and declined significantly. Downward pressure on commodity prices continued in 2015 and the early part of 2016 and may continue for the foreseeable future. A prolonged downturn in the oil and gas industry could result in a reduction in demand for TEP's business and could adversely affect its financial condition, results of operations and cash flows.
Any significant decrease in available supplies of hydrocarbons in TEP's areas of operation, or redirection of existing hydrocarbon supplies to other markets, could adversely affect its business and operating results. If recent lower commodity prices are prolonged beyond its contract lives, TEP will likely experience lower throughput volumes and reduced cash flows.
TEP's business is dependent on the continued availability of natural gas and crude oil production and reserves. Production from existing wells and natural gas and crude oil supply basins with access to its assets will naturally decline over time. The amount of natural gas and crude oil reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the contracted capacity and/or the volume of products utilizing its assets, its customers must continually obtain adequate supplies of natural gas and crude oil.
However, the development of additional natural gas and crude oil reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, storage, transportation and other facilities that permit natural gas and crude oil to be produced and products delivered to TEP's facilities. In addition, low prices for natural gas and crude oil, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could have a material adverse effect on the development and production of additional reserves, as well as storage, pipeline transportation, and import and export of natural gas and crude oil supplies. The current volatility and historically low prices for crude oil and refined products has led to a decline in drilling activity, production and refining of crude oil, and import levels in these areas. For example, in response to recent declines in crude oil prices, a number of producers in its areas of operation significantly reduced their capital budgets and drilling plans in 2015 and have announced further reductions in their capital budget and drilling plans for 2016. In addition, production may fluctuate for other reasons, including, for example, in the case of crude oil, the decisions made by the members of OPEC regarding production controls. Furthermore, competition for natural gas and crude oil supplies to serve other markets could reduce the amount of natural gas and crude oil supply available for its customers. Accordingly, to maintain or increase the contracted capacity and/or the volume of products utilizing its assets, its customers must compete with others to obtain adequate supplies of natural gas and crude oil.
If new supplies of natural gas and crude oil are not obtained to replace the natural decline in volumes from existing supply basins, if natural gas and crude oil supplies are diverted to serve other markets, if environmental regulations restrict new natural gas and crude oil drilling or if OPEC does not agree to and maintain production controls, the overall demand for services on TEP's systems will likely decline, which could have a material adverse effect on its ability to renew or replace its current customer contracts when they expire and on its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.
TEP's natural gas and crude oil operations are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on its business, financial condition, and results of operations.
TEP provides open-access interstate transportation service on its natural gas transportation systems pursuant to tariffs approved by the FERC. TEP's natural gas transportation and storage operations are regulated by the FERC, under the NGA, the NGPA, and EPAct 2005. The TIGT System and the Trailblazer Pipeline each operates under a tariff approved by the FERC that establishes rates and terms and conditions of service to its customers. The rates and terms of service on the Pony Express System are subject to regulation by the FERC under the ICA, and the Energy Policy Act of 1992. TEP provides interstate transportation service on the Pony Express System pursuant to tariffs on file with the FERC. TEP's NGL pipeline is leased to a third party who has obtained a temporary waiver for itself from the FERC from the tariff, filing and reporting requirements of the ICA.
Generally, the FERC’s authority over natural gas facilities extends to:
rates, operating terms and conditions of service;
the form of tariffs governing service;
the types of services TEP may offer to its customers;
the certification and construction of new, or the expansion of existing, facilities;
the acquisition, extension, disposition or abandonment of facilities;

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customer creditworthiness and credit support requirements;
the maintenance of accounts and records;
relationships among affiliated companies involved in certain aspects of the natural gas business;
depreciation and amortization policies; and
the initiation and discontinuation of services.
The FERC’s authority over crude oil pipelines is less broad, extending to:
rates, rules and regulations of service;
the form of tariffs governing rates and service;
the maintenance of accounts and records; and
depreciation and amortization policies.
Interstate natural gas pipelines subject to the jurisdiction of the FERC may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust, unreasonable, unduly discriminatory, or preferential. The maximum recourse rate that TEP may charge for its natural gas transportation and storage services is established through the FERC’s ratemaking process. The maximum applicable recourse rate and terms and conditions for service are set forth in its FERC-approved tariff.
Pursuant to the NGA, existing interstate natural gas transportation and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. TEP currently holds authority from the FERC to charge and collect (i) "recourse rates" (i.e., the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its tariff); (ii) "discount rates" (i.e., rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline’s tariff); and (iii) "negotiated rates" (i.e., rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within or outside of the cost-based maximum and minimum rate levels set forth in the tariff, and which are individually filed with the FERC for review and acceptance). When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) at which such capacity is sold are subject to regulatory approval and oversight. Regulators and customers on its natural gas pipeline systems have the right to protest or otherwise challenge the rates that TEP charges under a process prescribed by applicable regulations. The FERC may also initiate reviews of its rates. Customers on its natural gas pipeline systems may also dispute terms and conditions contained in its agreements, as well as the interpretation and application of its tariffs, among other things.
Rates for crude oil transportation service must be filed as a tariff with the FERC and are subject to applicable FERC regulation. The filed tariff rates include contract rates entered into with shippers willing to make long-term commitments to the pipeline to support new pipeline capacity. Contract rates generally are not subject to regulation or change by the FERC. Non-contract "walk-up" rates are available to uncommitted non-contract shippers and generally are subject to regulation and change by the FERC. Crude oil pipelines typically must reserve at least ten percent of their capacity for walk-up shippers. Contract tariff rates may be changed by Pony Express on an annual basis to reflect annual FERC index adjustments to the extent permitted by contract. Non-contract rates may be adjusted, positively or negatively, on an annual basis pursuant to a FERC indexing procedure. A crude oil pipeline may also file new tariff rates at any time, subject to contract restrictions and provisions, and FERC regulatory procedures. The filing of any indexed rate increase or other rate increase may be protested by parties having standing, subject to applicable regulatory and contract provisions, and thereby be subjected to cost-of-service review by the FERC to determine whether the proposed new rate is just and reasonable.
Under the ICA, which applies to FERC-regulated interstate liquids pipelines such as the Pony Express System, parties having standing and not restricted by contract may protest newly filed rates and terms and conditions of service within a prescribed notice period. The FERC is authorized to suspend, subject to refund, the effectiveness of a protested rate for up to seven months while it determines if the protested rate is just and reasonable. TEP's rates may be reduced and TEP may be required to issue refunds as a result of settlement or by an order of the FERC following a hearing finding that a protested rate is unjust and unreasonable. Parties having standing and not restricted by contract may file a complaint at any time regarding existing rates and terms and conditions of service. If the complaint is not resolved by settlement, the FERC may conduct a hearing and order the crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. TEP cannot guarantee that any new or existing local or joint tariff rate for service on the Pony Express System would not be rejected or modified by the FERC, or subjected to refunds or reparations. While the FERC regulates rates and terms and conditions of service for transportation of crude oil in interstate

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commerce by pipeline, state agencies may also regulate facilities (including construction, acquisition, disposition, financing, and abandonment), rates, and terms and conditions of service for crude oil pipeline transportation in intrastate commerce. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on its business, financial condition and results of operations.
The Trailblazer Pipeline, one of TEP's interstate natural gas pipelines, uses two types of fuel to power its compressors: (1) natural gas and (2) electric power. For the natural gas compression, customers are charged a gas retainage percentage as an in-kind reimbursement for fuel. For the electric compression, customers are charged a commodity rate for the electricity used at the pipeline’s stations. The volume of gas and cost of electric power are tracked and adjusted in annual periodic rate adjustment filings made pursuant to Trailblazer's tariff. Lost and unaccounted for gas is also tracked and adjusted in annual periodic rate adjustment filings. These costs were subject to the NGA Section 4 rate case initiated by the Trailblazer Pipeline and resolved by settlement as approved by the FERC in May 2014. On TIGT, its gas compressor fuel costs and the cost of FL&U gas, together referred to as Fuel Retention Factors, are currently recovered by retaining a fixed percentage of natural gas throughput on its transportation and storage facilities. These Fuel Retention Factors were the subject of a NGA Section 5 proceeding initiated by the FERC that TEP resolved with customers by a settlement approved by the FERC in September 2011. In its NGA Section 4 proceeding that was filed on October 30, 2015, TIGT proposed to replace its fixed FL&U charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect any previous period’s under/over collection and the forecasted FL&U expense for the upcoming period. TIGT also proposed to implement a separate power cost tracker to recover the actual power costs incurred by TIGT to power its compressors. These proposals were accepted by the FERC in its Suspension Order, subject to a five-month suspension period, to be effective May 1, 2016, subject to refund and the outcome of the hearing.
The FERC’s jurisdiction over natural gas facilities extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to, acquisitions, facility maintenance, expansions, and abandonment of facilities and services. With some exceptions applicable to smaller projects, auxiliary facilities, and certain facility replacements, prior to commencing construction and/or operation of new or existing interstate natural gas transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction from, or file to amend its existing certificate with, the FERC. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any delay or refusal by an agency to issue authorizations or permits as requested for one or more of these projects may mean that they will be constructed in a manner or with capital requirements that TEP did not anticipate or that TEP will not be able to pursue these projects. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from these projects. The FERC does not regulate the construction, expansion, or abandonment of crude oil or NGL pipelines, whether interstate or intrastate, nor the initiation or discontinuation of services on those pipelines, provided that the action taken is not discriminatory or preferential among similarly situated shippers.
The FERC has the authority to conduct audits of regulated entities to assess compliance with FERC regulations and policies. The FERC also conducts audits to verify that the websites of interstate natural gas pipelines accurately provide information on the operations and availability of services on the pipeline. FERC regulations also require entities providing interstate natural gas and crude oil transportation services to comply with uniform terms and conditions for service, as set forth in publicly available tariffs or, as it concerns natural gas facilities, agreements for transportation and storage services executed between interstate pipelines and their customers. Natural gas transportation service agreements are generally required to conform, in all material respects, with the standard form of service agreements set forth in the natural gas pipeline’s FERC-approved tariff. The pipeline and a customer may choose to enter into a non-conforming service agreement so long as this agreement is filed with, and accepted by, the FERC. In the event that the FERC finds that a natural gas transportation agreement, in whole or part, is materially non-conforming, the FERC could reject the agreement or require TEP to modify the agreement, or alternatively require TEP to modify its tariff so that the non-conforming provisions are generally available to all customers. Transportation agreements entered into with crude oil shippers are generally not subject to FERC regulation or required to be available for FERC or public review, but the rates and terms and services provided to similarly situated shippers may not be unduly discriminatory or preferential.
The FERC has promulgated rules and policies covering many aspects of its natural gas pipeline business, including regulations that require TEP to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential, provide internet access to current information about its available pipeline capacity and other relevant transmission information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. FERC regulations also prevent interstate natural gas pipelines from sharing customer information with marketing affiliates, and restrict how interstate natural gas pipelines share transportation with marketing affiliates. FERC regulations require that certain transmission function personnel of interstate natural gas pipelines function independently of personnel engaged in natural gas marketing functions. Crude oil pipelines subject to the ICA must comply with FERC regulations that require the pipeline to act as a common carrier and not engage in undue discrimination or preferential treatment with respect to shippers.

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FERC policies also govern how interstate natural gas pipelines respond to interconnection requests from third party facilities, including other pipelines. Generally, an interstate natural gas pipeline must grant an interconnection request upon the satisfaction of several conditions. As a consequence, an interstate natural gas pipeline faces the risk that an interconnecting third-party pipeline may pose a risk of additional competition to serve a particular market. Failure to comply with applicable provisions of the NGA, NGPA, EPAct 2005 and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of up to $1.0 million per day, per violation. Violations of the ICA, the Energy Policy Act of 1992, or regulations and orders promulgated by the FERC are also subject to administrative and criminal penalties and remedies, including forfeiture and individual liability.
In addition, new laws or regulations or different interpretations of existing laws or regulations applicable to TEP's pipeline systems or midstream facilities could have a material adverse effect on its business, financial condition, results of operations and prospects. For example, the FERC may not continue to pursue its approach of pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. TEP may face challenges to its rates or terms of service in the future. Any successful challenge could materially and adversely affect its future earnings and cash flows.
The rates and the terms and conditions of TEP's regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
TEP's shippers or other interested stakeholders, such as state natural gas utility regulatory agencies, may challenge the rates or the terms and conditions of service applicable to its natural gas or crude oil pipeline tariffs, unless they have entered into agreements not to challenge such tariffs. The FERC has authority to investigate its rates and terms and conditions of service pursuant to NGA Section 5 for natural gas pipelines and the ICA for common carrier oil pipelines. TEP's crude oil contract shippers have generally agreed not to complain or protest rates unless they are in conflict with their contracts. FERC generally does not regulate crude oil transportation contracts, but contract rates must be filed with FERC and tariff rules and regulations generally apply to contract shippers. TEP's NGL pipeline is leased to a third party who obtained a temporary waiver for itself from the FERC from the tariff, filing and reporting requirements of the ICA, and during the term of the lease, TEP operates and maintains the pipeline at the lessee's discretion.
With regard to TEP's natural gas pipelines, Trailblazer initiated a rate proceeding with the FERC pursuant to Section 5 of the NGA on July 1, 2013 to implement a general rate increase to its recourse rates, initiate a rolled-in rate structure for expansion facilities certificated in 2001, and adopt miscellaneous other updates to its General Terms and Conditions in its tariff. On February 24, 2014, Trailblazer submitted to the FERC an uncontested offer of settlement and stipulation to resolve the proceeding by, among other things: (a) setting new maximum recourse rates based upon a "black box" cost of service of $21.1 million, (b) revising the charges and methods for recovery of fuel (natural gas and electric power used in providing service, including for operating compressors) costs such that the actual volumes of gas and cost of electric power, as well as FL&U gas, are tracked and adjusted in annual periodic rate filings made pursuant to Trailblazer's tariff (as opposed to recover), (c) providing for revenue sharing of certain interruptible and short-term firm service revenues with eligible maximum recourse rate firm service shippers, (d) establishing a rate moratorium until January 1, 2016, and (e) requiring a general rate case to be filed no later than January 1, 2019. The FERC accepted the settlement agreement by letter order on May 29, 2014. Per the terms of the settlement, Trailblazer is required to file a new general rate case by January 1, 2019, and no customer or participant who joined the settlement (defined in the settlement as a "Settling Party") was permitted to file to change the settlement rates before January 1, 2016.
On October 30, 2015, TIGT initiated a general NGA Section 4 rate proceeding with the FERC which, among other things, seeks a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT. TIGT also proposed certain changes to the transportation rate design of its system to replace the current rate zone structure with a single "postage stamp" rate. TIGT also proposed new incremental charges, including (i) a charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a CRM charge to completely or partially reimburse TIGT for certain expenses and costs it incurs to comply with anticipated new PHMSA and EPA regulations. TIGT also proposed to replace its fixed FL&U charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period’s under/over collection and the forecasted FL&U expense for the upcoming period. Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of rate and non-rate matters. The filing was protested by a number of participants. In FERC’s November 30, 2015 Suspension Order, the FERC accepted and suspended the proposed rates and a majority of the proposed tariff records to be effective May 1, 2016, subject to refund, certain modifications of TIGT’s proposed CRM charge, and the outcome of an evidentiary hearing. The FERC also accepted two tariff records related to force majeure events and reservation charge crediting to be effective December 1, 2015, subject to certain modifications. Consistent with the Suspension Order, on December 21, 2015, TIGT made a compliance filing with the FERC addressing TIGT’s proposed CRM charge and the two tariff records related to force majeure events and reservation

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charge crediting. The FERC accepted TIGT’s compliance filing on February 1, 2016. Litigation addressing the proposed rates and tariff records set for hearing is on-going.
On TEP's interstate crude oil pipeline system, the Pony Express System, shippers may generally challenge new or existing rates at any time unless they have contractually agreed not to. As a result of settlement or by order of the FERC following hearing, its rates may be reduced. If a shipper files a lawful complaint, and if the complaint is not resolved with that shipper, to the extent the FERC determines after hearing that TEP has collected payment on rates that were not just and reasonable, TEP may be required to pay reparations to that shipper for up to two years prior to the date on which a complaint was filed. Regardless of the prospective just and reasonable rate, reparations may not be required below the last rates determined by the FERC to be just and reasonable. In other words, crude oil pipelines are not required to make reparations that refund revenues collected pursuant to rates previously determined to be just and reasonable.
Successful challenges to rates charged on TEP's natural gas and crude oil pipeline systems, or to the terms and conditions of service on those systems, could have a material adverse effect on its business, results of operations, financial condition and ability to make quarterly cash distributions to its unitholders.
Constructing new assets subjects TEP to risks of project delays, cost overruns and lower-than-anticipated volumes of natural gas or crude oil once a project is completed. TEP's operating cash flows from its capital projects may not be immediate or meet its expectations.
One of the ways TEP may grow its business is by constructing additions or modifications to its existing facilities. TEP also may construct new facilities, either near its existing operations or in new areas. For example, in 2013 TEP completed an expansion of its Casper and Douglas plants to increase processing capacity and upgrade compression. Pony Express completed its approximately 698-mile crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma during 2014 and its approximately 66-mile lateral in Northeast Colorado in the first half of 2015. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of which are beyond its control. These projects also involve numerous economic uncertainties, including the impact of inflation on project costs and the availability of required resources.
TEP may be unable to complete announced construction projects on schedule, at the budgeted cost, or at all, which could have a material adverse effect on its business and results of operations. Moreover, TEP may not receive any material increase in operating cash flow from a project for some time. For instance, if TEP expands a pipeline or processing facility, the construction expenditures may occur over an extended period of time, yet TEP will not receive any material increases in cash flow until the project is completed and fully operational. In addition, its cash flow from a project may be delayed or may not meet its expectations. TEP's project specifications and expectations regarding project cost, timing, asset performance, investment returns and other matters usually rely in part on the expertise of third parties such as engineers, technical experts and construction contractors. These estimates may prove to be inaccurate because of numerous operational, technological, economic and other uncertainties.
TEP relies in part on estimates from producers regarding the timing and volume of anticipated natural gas and crude oil production. Production estimates are subject to numerous uncertainties, all of which are beyond its control. These estimates may prove to be inaccurate, and new facilities may not attract sufficient volumes to achieve its expected cash flow and investment return.
TEP is subject to numerous hazards and operational risks.
TEP's operations are subject to all the risks and hazards typically associated with transportation, storage, processing, gathering and disposing of hydrocarbons and water. These operating risks include, but are not limited to:
damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires or other adverse weather conditions and other natural disasters and acts of terrorism;
inadvertent damage from construction, vehicles, farm and utility equipment;
uncontrolled releases of crude oil, natural gas and other hydrocarbons or hazardous materials, including water from hydraulic fracturing;
leaks, migrations or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;
outages at its facilities;
ruptures, fires, leaks and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and suspension of operations.

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These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of TEP's assets, including certain segments of its pipeline systems in or near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas could increase the level of damages resulting from these risks. Despite the precautions TEP takes, events could cause considerable harm to people or property, could result in loss of service available to customers, and could have a material adverse effect on its financial condition and results of operations and ability to make distributions to unitholders. In addition, maintenance, repair and remediation activities could result in service interruptions on segments of its systems or alter the operational profile of its systems. Potential impacts arising from these service interruptions or operational profile changes on segments of its systems could include, among others, limitations on its ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new projects that would compete directly with existing services.
TEP could be required by regulatory authorities to test or undertake modifications to its systems, operations or both that could result in a material adverse impact on its business, financial condition and results of operations. For example, TEP received a Corrective Action Order from PHMSA on June 19, 2013 directing TEP to take certain investigative, testing and corrective measures with regard to the segment of the TIGT pipeline in Goshen County that failed on June 13, 2013. In August 2015, PHMSA informed TEP that TIGT had fully complied with the terms of the Corrective Action Order related to that incident and stated that no further action is contemplated. However, such actions, including those required by PHMSA, could materially and adversely impact its ability to meet contractual obligations and retain customers, with a resulting material adverse impact on its business and results of operations, and could also limit or prevent its ability to make quarterly cash distributions to its unitholders. Some or all of its costs arising from these operational risks may not be recoverable under insurance, contractual indemnification or increases in rates charged to its customers.
TEP's insurance coverage may not be adequate.
TEP is not insured or fully insured against all risks that could affect its business, including losses from environmental accidents. For example, TEP does not maintain business interruption insurance in the type and amount to cover all possible losses. In addition, TEP does not carry insurance for certain environmental exposures, including but not limited to potential environmental fines and penalties, certain business interruptions, named windstorm or hurricane exposures and, in limited circumstances, certain political risk exposures. Further, in the event there is a total or partial loss of one or more of its insured assets, any insurance proceeds that TEP may receive in respect thereof may be insufficient to effect a restoration of such asset to the condition that existed prior to such loss. In addition, TEP is either not insured or not fully insured with respect to the legal proceedings described in Note 17Legal and Environmental Matters to the consolidated financial statements and may, depending upon the circumstances, need to pay self-insured retention amounts prior to having losses covered by the insurance providers. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on its business, financial condition, results of operations and cash flows.
Furthermore, TEP may not be able to maintain or obtain insurance of the type and amount TEP desires at reasonable rates, and TEP has elected and may elect in the future to self-insure a portion of its risks of loss. As a result of market conditions, premiums and deductibles for certain types of insurance policies may substantially increase, and in some instances, certain types of insurance could become unavailable or available only for reduced amounts of coverage. Any insurance coverage TEP does obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses.
TEP's pipeline integrity program may impose significant costs and liabilities on TEP, while increased regulatory requirements relating to the integrity of its pipeline systems may require TEP to make additional capital and operating expenditures to comply with such requirements.
TEP is subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal requirements set by PHMSA for owners and operators of pipelines in the areas of pipeline design, construction, and testing, the qualification of personnel and the development of operations and emergency response plans. The rules require pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as HCAs.
TEP's pipeline operations are subject to pipeline safety regulations administered by PHMSA. These regulations, among other things, include requirements to monitor and maintain the integrity of its pipeline systems and determine the pressures at which its pipeline systems can operate. The Pipeline Safety Act of 2011 enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002 in a number of significant ways, including:
reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines;
requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote- controlled shutoff valves on new or rebuilt pipeline facilities;

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requiring operators of pipelines to verify MAOP and report exceedances within five days; and
requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those requirements to areas outside of HCAs.
In August 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties from $0.1 million to $0.2 million per violation per day of violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing PHMSA’s enforcement process.
The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs can have a significant impact on the costs to perform integrity testing and repairs. Trailblazer recently conducted smart tool surveys and preliminary analysis on segments of its natural gas pipeline to evaluate the growth rate of corrosion downstream of compressor stations. Trailblazer currently believes that approximately 25 - 35 miles of pipe will likely need to be repaired or replaced in order for the pipeline to operate at its MAOP of 1,000 pounds per square inch. Such repair or replacement will likely occur over a period of years, depending upon final assessment of corrosion growth rates and the remediation and repair plan implemented by Trailblazer. Trailblazer is currently operating at less than its current MAOP, public notice of which was first provided in June 2014. The current pressure reduction is not expected to prevent Trailblazer from fulfilling its firm service obligations at existing subscription levels and to date it has not had a material adverse financial impact on TEP.
During 2015, Trailblazer completed 32 excavation digs at an aggregate cost of approximately $1.3 million based on preliminary analysis of the smart tool surveys performed in 2014. Segments of the Trailblazer Pipeline that require full replacement are currently expected to cost in the range of approximately $2.2 million to $2.7 million per mile. Repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. Trailblazer is continuing to develop a remediation and repair plan, which involves, among other things, finalizing cost recovery options, establishing project scope and timing and setting an overall project budget. In 2016, Trailblazer intends to replace approximately 8 miles of pipe at an estimated cost of $21.5 million. Trailblazer is currently exploring all possible cost recovery options. It may not ultimately be able to recover any or all of such out of pocket costs unless and until Trailblazer recovers them through a general rate increase or other FERC-approved recovery mechanism, or through negotiated rate agreements with its customers.
In connection with TEP's acquisition of the Trailblazer Pipeline, Tallgrass Development agreed to contractually indemnify TEP for any out of pocket costs incurred between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline’s disbonded Hi-Melt CTE coating. The contractual indemnity provided by Tallgrass Development currently is capped at $20 million and is subject to an annual $1.5 million deductible. TEP will continue pipeline integrity testing programs to assess and maintain the integrity of its existing and future pipelines as required by the U.S. Department of Transportation regulations. The results of these tests could cause TEP to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines, which expenditures could be material.
Additionally, TEP had several minor incidents in 2014 and 2015 on the Pony Express System that TEP reported to PHMSA during final commissioning and since the line has been placed into commercial service. In each of these cases, which released between 0.5 and 300 bbls of crude oil, the remediation activities have been completed without material cost to the Pony Express System, and the matters have been closed by the applicable agencies. In late 2015, anomalies were detected on the portion of the Pony Express System’s pipeline that was converted from gas service.  These anomalies were reported to PHMSA on December 2, 2015. Pony Express is continuing to evaluate and remediate these issues on the converted pipeline section of the Pony Express System. Tallgrass Development has agreed to contractually indemnify TEP for out of pocket costs incurred to repair, replace or remediate anomalies in any part of the Pony Express System’s pipeline that was converted from gas service to the extent such anomalies are identified by in-line inspection tools during the period from January 1, 2015 until January 1, 2019. The contractual indemnity provided by Tallgrass Development is capped at $11 million and is subject to an annual $1 million deductible.
The Pony Express System is a newly commissioned crude oil pipeline and these integrity issues may continue for the foreseeable future. There can be no assurance as to the amount or timing of future expenditures required to remediate or resolve these issues, and actual future expenditures may be different from the amounts TEP currently anticipates. These integrity issues could have a material adverse effect on its business, financial position, results of operations and prospects.
Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. For example, PHMSA issued an Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the MAOP for each section of their pipeline and that the records must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or

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replacing facilities to meet the demands of verifiable pressures, could significantly increase its costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for MAOP. TEP is currently undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could require TEP to operate at reduced pressures, which would reduce available capacity on its natural gas pipeline systems. These specific requirements do not currently apply to crude oil pipelines, but forthcoming regulations implementing the Pipeline Safety Act of 2011 likely will expand the scope of regulation applicable to crude oil pipelines. There can be no assurance as to the amount or timing of future expenditures required to comply with pipeline integrity regulation, and actual future expenditures may be different from the amounts TEP currently anticipates. In addition, TEP may be subject to enforcement actions and penalties for failure to comply with pipeline regulations. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on its business, financial position, results of operations and prospects. In addition, TEP may be subject to enforcement actions and penalties for failure to comply with pipeline regulations.
Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for TEP and reduced demand for its services.
The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement will be open for signing on April 22, 2016 and will require countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements to include upstream petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year. Some of its facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting requirements. Furthermore, in August 2015, the EPA proposed changes to its regulations imposing more stringent controls on methane and volatile organic compounds emissions from oil and gas development, production, and transportation operations. A final rule is expected in 2016. The Administration has also announced that other federal agencies, including the BLM, the PHMSA, and the U.S. Department of Energy will impose new or more stringent regulations on the oil and gas sector that are designed to reduce methane emissions. In addition, almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.
The adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, TEP's equipment and operations could require TEP to incur additional costs to reduce emissions of GHGs associated with its operations, could adversely affect its operations in the absence of any permits that may be required to regulate emission of GHGs, or could adversely affect demand for the crude oil and natural gas TEP gathers, processes, or otherwise handles. For instance, the EPA and BLM’s recently proposed rules could result in the direct regulation of GHGs associated with its operations. TEP is not able at this time to estimate such increased costs; however, they could be significant. While TEP may be able to recover some or all of such increased costs in the rates charged by its processing facilities, such recovery of costs is uncertain and may depend on the terms of its contracts with its customers.
If new laws or regulations that significantly restrict GHGs are adopted, such laws could also make it more difficult or costly for TEP's customers to operate, which could reduce its customers’ production and therefore the demand for its services. While TEP is not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for TEP. For instance, increasing regulatory pressures as a result of the EPA’s "Clean Power Plan" rule or other initiatives could impact its customers’ operations and, therefore, the overall demand for its services. Restrictions on GHG emissions could also reduce the volume of natural gas that its customers produce, and could thereby adversely affect its revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for TEP and its customers, which could ultimately decrease end-user demand for its services and could have a material adverse effect on its business. In addition, to the extent financial markets view climate change and GHG emissions as a financial risk, this could materially and adversely impact its cost of and access to capital. Legislation or regulations that may be adopted to address climate change, or incentives to conserve energy or use alternative energy sources, could also affect the markets for its services by making natural gas and crude oil products less desirable than competing sources of energy.

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TEP's operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose TEP to significant costs, liabilities and expenditures that could exceed its current expectations.
Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in TEP's crude oil transportation, natural gas transportation, storage and processing, NGL transportation and water business services, and as a result, TEP may be required to make substantial expenditures that could exceed current expectations. TEP's operations are subject to extensive federal, state, and local laws and regulations governing health and safety aspects of its operations, environmental protection, including the discharge of materials into the environment, and the security of chemical and industrial facilities. These laws include, but are not limited to, the following:
CAA and analogous state and local laws, which impose obligations related to air emissions;
CWA and analogous state and local laws, which regulate discharge of pollutants (Section 402) or fill material (Section 404) from its facilities to state and federal waters, including wetlands;
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 TEP or locations to which TEP has sent wastes for disposal;
RCRA and analogous state and local laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from its facilities;
OSHA and analogous state and local laws, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
NEPA and analogous state and local laws, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;
The Migratory Bird Treaty Act, and analogous state and local laws, which implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
ESA and analogous state and local laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;
Bald and Golden Eagle Protection Act and analogous state and local laws, which prohibits anyone, without a permit issued by the Secretary of the Interior, from "taking" bald or golden eagles, including their parts, nests, or eggs, and defines "take" as "pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, molest or disturb;"
OPA and analogous state and local laws, which imposes liability for discharges of oil into waters of the United States and requires facilities which could be reasonably expected to discharge oil into waters of the United States to maintain and implement appropriate spill contingency plans; and
National Historic Preservation Act and analogous state and local laws, which is intended to preserve and protect historical and archeological sites.
Various governmental authorities, including but not limited to the EPA, the U.S. Department of the Interior, the U.S. Department of Homeland Security, and analogous federal, state and local agencies have the power to enforce compliance with these and other similar laws and regulations and the permits and related plans issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these and other similar laws, regulations, permits, plans and agreements may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of TEP's operations, and delays in granting permits.
There is inherent risk of the incurrence of environmental costs and liabilities in TEP's business, some of which may be material, due to its handling of the products TEP transports, processes and stores, air emissions related to its operations, historical industry operations, and waste disposal practices, such as the prior use of flow meters and manometers containing mercury. These activities are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact its business activities in many ways, such as restricting the way TEP handles or disposes of wastes or requiring remedial action to mitigate pollution conditions that may be

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caused by its operations or that are attributable to former operators. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including but not limited to CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with oil, natural gas and wastes on, under, or from its properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under its control. TEP is generally responsible for all liabilities associated with the environmental condition of its facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, TEP could acquire, or be required to provide indemnification against, environmental liabilities that could expose TEP to material losses, which may not be covered by insurance. In addition, the steps TEP could be required to take to bring certain facilities into compliance could be prohibitively expensive, and TEP might be required to shut down, divest or alter the operation of those facilities, which might cause TEP to incur losses. TEP is currently conducting remediation at several sites to address contamination. For 2014, TEP spent approximately $270,000, for 2015 TEP spent approximately $497,000 and for 2016 TEP has budgeted approximately $1.3 million for these ongoing environmental remediation projects.
Private parties, including but not limited to the owners of properties through which TEP's pipelines pass and facilities where its wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws, regulations and permits issued thereunder, or for personal injury or property damage arising from its operations. Some sites at which TEP operates are located near current or former third-party hydrocarbon storage, processing, operations or other facilities, and there is a risk that contamination has migrated from those sites to TEP's that could result in remedial action. In addition, increasingly strict laws, regulations and enforcement policies could materially increase its compliance costs and the cost of any remediation that may become necessary. TEP's insurance does not cover all environmental risks and costs and may not provide sufficient coverage if an environmental claim is made against TEP.
In June 2013, the EPA extended its National Enforcement Initiatives, enforcement priorities list, including an initiative related to Energy Extraction Activities, for 2014 through 2016. TEP cannot predict what the results of the current initiative or any future initiative will be, or whether federal, state or local laws or regulations will be enacted in this area. If new regulations are imposed related to oil and gas extraction, the volumes of products, including hydrocarbons and water, that TEP transports, stores, gathers, disposes and/or processes could decline and its results of operations could be materially and adversely affected.
TEP's business may be materially and adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits or plans developed thereunder. Also, TEP might not be able to obtain or maintain from time to time all required environmental regulatory approvals for its operations, or may have to implement contingencies or conditions in order to obtain such approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if TEP fails to obtain and comply with them, the operation, maintenance or construction of its facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to its business, financial condition, results of operations and cash flows. For instance, on November 25, 2014, the Wyoming Department of Environmental Quality issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Casper Gas Plant Depropanizer project. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014 and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of the CAA’s NSPS Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing. Costs associated with penalties and to comply with the terms of any consent decree or settlement, as well as with Subpart OOOO, could be material.
TEP is also generally responsible for all liabilities associated with the environmental condition of its facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, such as its recent acquisition in December 2015 of a fresh water delivery and storage system, a produced water gathering and disposal system and multiple produced water disposal wells from Whiting, TEP could acquire, or be required to provide indemnification against, environmental liabilities that could expose TEP to material losses, which may not be covered by insurance. In addition, the steps TEP could be required to take to bring certain facilities into compliance could be prohibitively expensive, and TEP might be required to shut down, divest or alter the operation of those facilities, which might cause TEP to incur losses. As another example, the Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed, and TEP has requested that the portion of the site attributable to TEP be delisted from the National Priorities List. As another example, in August 2011, the EPA and the Wyoming Department of Environmental Quality conducted an inspection of the Leak Detection and Repair Program, or LDAR, at the Casper Plant in Wyoming. In September 2011, TMID received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the CAA. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. In July 2014, the EPA provided TMID with a draft Consent Decree that has been the basis for

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subsequent settlement negotiations. Subsequently, the EPA indicated that it intends to join TIGT as a defendant in this matter based on TIGT’s ownership of the compressor station located adjacent to the Casper Gas Plant in order to address alleged LDAR issues at the compressor station. Most recently, the parties held a settlement meeting in August 2015. Following the settlement meeting, negotiations are continuing and the parties have entered into tolling agreements that have tolled the statute of limitations until April 29, 2016. TEP is not currently able to estimate the costs that may be associated with a settlement or other resolution of this matter, which could be substantial.
TEP has agreed to a number of conditions in its environmental permits and associated plans, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where TEP currently operates, and would operate if its facilities are extended or expanded, or if TEP constructs new facilities, and TEP is unable to predict the effect that any such measures would have on its business, financial position, results of operations or prospects.
Also, on June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or Corps, issued a final rule to clarify the term "waters of the United States" as it pertains to federal jurisdiction under the CWA. Many interested parties believe that the rule expands federal jurisdiction under the CWA. Although it is unclear how the Corps and the EPA will implement this rule, the rule may require additional Corps or the EPA authorizations or involvement in TEP's future operations, for instance, if TEP extends its pipelines into or across areas (such as certain ditches) newly considered "waters of the United States" under the final rule.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be materially different from the amounts TEP currently anticipates. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from its customers, could have a material adverse effect on TEP's business, financial position, results of operations and prospects.
Increased regulation of hydraulic fracturing and other oil and natural gas processing operations could affect TEP's operations and result in reductions or delays in production by its customers, which could have a material adverse impact on its revenues.
A sizeable portion of the production by TEP's customers comes from hydraulically fractured wells. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process typically involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state’s oil and gas commission. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, on May 19, 2014, the EPA published an advance notice of rulemaking under the Toxic Substances Control Act, to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. In August 2015, the EPA proposed updates to new source performance standard requirements that would impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. The EPA has also issued a proposed rule that would prevent the discharge of hydraulic fracturing wastewater into publicly owned sewage treatment plants. Also, effective June 24, 2015, the BLM adopted rules regarding well stimulation, chemical disclosures, water management, and other requirements for hydraulic fracturing on federal and Indian lands. The BLM also proposed new rules in January 2016 to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases.
Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, some states, including those in which TEP operates, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, in some cases banning hydraulic fracturing entirely. Other governmental agencies, including the U.S. Department of Energy and the EPA, have evaluated or are evaluating various other aspects of hydraulic fracturing such as the potential environmental effects of hydraulic fracturing on drinking water and groundwater.

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If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or significantly more costly for TEP's customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of crude oil, natural gas or other hydrocarbons that its customers produce, and could thereby adversely affect its revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for TEP and its customers, which could ultimately decrease end-user demand for its services and could have a material adverse effect on its business.
TEP's produced water disposal operations may be subject to additional regulation and liability or claims of environmental damages.
TEP operates produced water disposal wells and locations, which have received the necessary governmental permits for drilling a disposal well. These wells are regulated under the federal SDWA as Class II wells and under state laws. State laws and regulations that govern these operations can be more stringent than the SDWA. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase its compliance costs and the cost of any remediation that may become necessary. TEP may also incur material environmental costs and liabilities. Furthermore, its insurance may not provide sufficient coverage in the event an environmental claim is made against TEP. In addition, although the disposal wells have received certain governmental regulatory licenses, permits or approvals, this does not shield TEP from potential claims from third parties claiming contamination of their water supply or other environmental damages. Remediation of environmental contamination or damages can be extremely costly and such costs, if TEP were found liable, may have a material adverse effect on its business, financial condition and results of operations.
Produced water injection well operations and hydraulic fracturing may cause induced seismicity.
State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of produced water injection wells in the vicinity of seismic events have been ordered to reduce produced water injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado and Texas, have modified their regulations to account for induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In 2015, the United States Geological Study identified eight states, including Colorado and Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that produced water disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of produced water injection wells and hydraulic fracturing. Such regulations and restrictions could have a material adverse effect on TEP's business, financial condition and results of operations.
TEP is exposed to costs associated with lost and unaccounted for volumes.
A certain amount of natural gas and crude oil may be lost or unaccounted for in normal operations in connection with their transportation across a pipeline system. Under TEP's tariffs and contractual arrangements with its customers TEP is entitled to retain a specified volume of natural gas and crude oil in order to compensate TEP for such lost and unaccounted for volumes, as well as the natural gas used to run its natural gas compressor stations (collectively referred to as "fuel usage"). TEP's pipeline tariffs, other than the Trailblazer Pipeline's, do not currently contain fuel usage true-up mechanisms. TIGT has proposed to replace its fixed FL&U charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period’s under/over collection and the forecasted FL&U expense for the upcoming period.  The FERC accepted such proposal to be effective upon motion May 1, 2016, subject to refund. The proposal may be ultimately rejected or modified by the FERC. The use of fuel (natural gas, electric and lost and unaccounted for gas) trackers on the Trailblazer Pipeline, while minimizing risk over time, nevertheless leaves the Trailblazer Pipeline exposed to the possibility of under- or over-collections on an annual basis. While the TIGT fuel tracker mirrors the Trailblazer tracker in requiring an annual redetermination, the TIGT proposal also allows for TIGT to re-determine the fuel reimbursement percentages and lost and unaccounted for ("L&U") reimbursement percentages on a monthly basis based on updated gas fuel and/or receipt quantities. This ability would act to further minimize TIGT’s exposure to the possibility of under- or over-collections on an annual basis. The level of lost and unaccounted for volumes, and natural gas fuel usage, on its pipeline systems may exceed the natural gas and crude oil volumes retained from its customers as compensation for its lost and unaccounted for volumes, and fuel usage, pursuant to its tariffs and contractual agreements, and it may be necessary to purchase natural gas or crude oil in the market to make up for the difference, which exposes TEP to commodity price risk. Future exposure to the volatility of natural gas and crude oil prices as a result of lost and unaccounted for volume imbalances could have a material adverse effect on its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.

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TEP has certain long-term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if its costs increase, and TEP has certain crude oil transportation contracts that contain favored nation provisions that could require rate decreases if other similarly situated shippers are paying lower rates. As a result, its costs could exceed its revenues.
Approximately two-thirds of TEP's contracted natural gas transportation firm capacity is provided under long-term, fixed price "negotiated or discount rate" contracts that are not subject to adjustment, even if its cost to perform such services exceeds the revenues received from such contracts, and, as a result, its costs could exceed its revenues received under such contracts. It is possible that costs to perform services under its "negotiated or discount rate" contracts will exceed the negotiated or discounted rates. It is also possible with respect to discounted rates that if its filed "recourse rates" should ever be reduced below applicable discounted rates, TEP would only be allowed by the FERC to charge the lower recourse rates, since FERC policy does not allow discount rates to be charged to the extent that they exceed applicable recourse rates. If these events were to occur, it could decrease the cash flow realized by TEP's assets and, therefore, the cash TEP has available for distributions to its unitholders. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a "negotiated rate," which is generally fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based "recourse rates," provided that the affected customer is willing to agree to such rates and that the FERC has accepted the negotiated rate agreement. These "negotiated or discount rate" contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between "recourse rates" (if higher) and negotiated or discounted rates, under current FERC policy, may be recoverable from other shippers in certain circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case. However, if the FERC were to disallow the recovery of such costs from other customers, it could decrease the cash flow realized by its assets and, therefore, the cash TEP has available for distributions to its unitholders.
Approximately 90% of the Pony Express System's current available capacity is provided to committed shippers under long-term "Throughput and Deficiency Agreements" or "TDAs". Rates under the TDAs are typically subject to change only per contract terms and conditions, including Pony Express’s right to file changes to contract rates to reflect annual index percentage adjustments published by the FERC. TEP generally cannot file for rate increases with respect to committed shippers who have signed TDAs, other than to reflect annual index adjustments or to recover compliance costs imposed by governmental actions. Some of the TDAs also contain favored nations provisions which could result in lower rates being charged to certain committed shippers to ensure that the rates such shippers are paying are no greater than ninety to one hundred percent of the rates being charged to other similarly situated shippers for similar service at similar volumes and terms.
The TDAs for the Pony Express System and some of TEP's service agreements with respect to its water business services contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.
The TDAs for the Pony Express System and some of TEP's service agreements with respect to its water services business are firm fee contracts with minimum volume commitments that are designed to generate stable cash flows and minimize direct commodity price risk. Under these minimum volume commitments, its customers agree to ship a minimum volume of crude oil or to have a minimum volume of water serviced, as the case may be, over certain periods during the term of the applicable agreement.
If a customer's actual throughput volumes or volumes serviced are less than its minimum volume commitment for the applicable period, it must make a deficiency payment at the end of the applicable period based upon the difference between the minimum volume commitment and the actual amounts serviced. A customer may apply any deficiency payments it makes as a credit against payment for volumes transported or serviced by TEP in excess of its minimum volume commitment in future periods. Upon termination of the Pony Express TDAs, customers may continue to use any remaining deficiency credits against any volumes serviced by TEP even though such customers may no longer have a minimum volume commitment.
To the extent that a customer's actual throughput volumes or volumes serviced are above its minimum volume commitment for the applicable period, the customer may use the excess volumes to credit against future deficiency payments in subsequent periods. Some or all of these provisions can apply in combination with one another. As a result, in the future TEP may not receive any cash payments for volumes shipped or serviced by TEP, and TEP may not receive deficiency payments as a result of excess volumes shipped in prior periods. This would result in reduced revenue and cash flows to TEP.
Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on TEP's natural gas storage business.
Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for TEP's storage services. The natural gas storage business has benefited from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for its services and the rates TEP is able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the

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market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, then demand for its storage services and the prices that TEP will be able to charge for those services may decline.
In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and likely place upward pressure on the costs of associated storage expansion activities. Alternatively, an extended period of low seasonal volatility in natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on TEP's business, financial condition, results of operations and ability to make distributions.
Certain portions of TEP's transportation, storage and processing facilities have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with its facilities that could have a material adverse effect on its business and results of operations.
Significant portions of TEP's transportation, storage and processing systems have been in service for several decades. The age and condition of its facilities could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce its revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of its facilities could adversely affect its business and results of operations and its ability to make cash distributions to its unitholders.
TEP's revolving credit facility could adversely affect its business, financial condition, results of operations and ability to make quarterly cash distributions to its unitholders.
TEP's revolving credit facility limits its ability to, among other things:
incur or guarantee additional debt;
redeem or repurchase units or make distributions under certain circumstances;
make certain investments and acquisitions;
incur certain liens or permit them to exist;
enter into certain types of transactions with affiliates;
merge or consolidate with another company; and
transfer, sell or otherwise dispose of assets.
TEP's revolving credit facility also contains covenants requiring TEP to maintain certain financial ratios. TEP's ability to meet those financial ratios and tests can be affected by events beyond its control, and TEP cannot assure you that it will meet those ratios and tests.
Further, TEP's obligations under the revolving credit facility are (i) guaranteed by TEP and each of its existing and subsequently acquired or organized direct or indirect wholly-owned domestic subsidiaries, subject to its ability to designate certain subsidiaries as "Unrestricted Subsidiaries," and (ii) secured by a first priority lien on substantially all of the present and after acquired property owned by TEP and each guarantor (other than real property interests related to its pipelines).
The provisions of TEP's revolving credit facility may affect TEP's ability to obtain future financing and pursue attractive business opportunities and its flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of its revolving credit facility, including a failure to meet the required financial ratios and tests, could result in a default or an event of default that could enable its lenders to restrict or prohibit its ability to make quarterly distributions and declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of its debt is accelerated and TEP is unable to repay the debt in full, its lenders could foreclose on the assets pledged by TEP and the guarantors under the revolving credit facility. In that case, its assets may be insufficient to repay such debt in full, and its unitholders could experience a partial or total loss of their investment.
Tallgrass Equity’s ownership in TEP’s IDRs, TEP’s common units and TEP’s general partner interest, are pledged under Tallgrass Equity’s revolving credit facility.
Tallgrass Equity’s direct ownership of 20,000,000 TEP common units and its direct ownership of its general partner (which owns TEP's IDRs and general partner interest), are pledged as security under Tallgrass Equity’s revolving credit facility. Tallgrass Equity’s revolving credit facility contains customary and other events of default. Upon an event of default, the lenders under Tallgrass Equity’s revolving credit facility could foreclose on Tallgrass Equity's ownership interest in TEP GP and the 20,000,000 TEP common units owned by Tallgrass Equity. This could ultimately result in a change in control of TEP GP, which would constitute an immediate event of default under TEP's credit facility. This would have a material adverse effect on TEP's business, financial condition and results of operations.

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TEP's future debt levels may limit its flexibility to obtain financing and to pursue other business opportunities.
TEP's level of debt could have important consequences to TEP, including the following:
its 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;
its funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of its cash flow required to make interest payments on its debt;
TEP may be more vulnerable to competitive pressures or a downturn in its business or the economy generally; and
its flexibility in responding to changing business and economic conditions may be limited.
TEP's ability to service its debt depends upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond its control. If its operating results are not sufficient to service its current or future indebtedness, TEP will be forced to take actions such as reducing distributions, reducing or delaying its business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. Taking any of these actions is likely to reduce the value of an investment in TEP. Plus, TEP may not be able to effect any of these actions on satisfactory terms or at all.
Increases in interest rates could adversely impact demand for TEP's storage capacity, its unit price, its ability to issue equity or incur debt for acquisitions or other purposes and its ability to make cash distributions at its intended levels.
There is a financing cost for TEP's customers to store natural gas in its storage facilities. That financing cost is impacted by the cost of capital or interest rate incurred by the customer in addition to the commodity cost of the natural gas in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas for future sale. As a result, a significant increase in interest rates could adversely affect the demand for its storage capacity independent of other market factors.
The interest rate on borrowings under TEP's revolving credit facility float based upon one or more of the prime rate, the U.S. federal funds rate or LIBOR. As a result, those borrowings, as well as borrowings under its possible future credit facilities or debt offerings, could be higher than current levels, causing its financing costs to increase accordingly. TEP does not currently hedge the interest rate risk on borrowings under its revolving credit facility.
As with other yield-oriented securities, TEP's unit price is impacted by the level of its cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in its units, and a rising interest rate environment could have an adverse impact on its unit price, its ability to issue equity or incur debt for acquisitions or other purposes and its ability to make cash distributions at its intended levels.
The lack of diversification of TEP's assets and geographic locations could adversely affect its ability to make distributions to its common unitholders.
TEP relies on revenues generated from its assets, which are primarily located in the Rocky Mountain and Midwest regions of the United States. Revenues on its assets primarily depend on exploration and production activities of its customers located in these regions. Due to its lack of diversification in assets and geographic location, an adverse development in these businesses or its customers' areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in supply or demand for hydrocarbons, could have a significantly greater impact on its results of operations and cash available for distribution to its common unitholders than if TEP maintained more diverse assets and locations. For example, its water business services is concentrated in a limited number of assets and primarily consists of its water business operations in Weld County, Colorado. Thus, the growth and profitability of its water business services will be especially vulnerable to conditions and fluctuations in the local Weld County economy and subject to changes in local government regulations and priorities.
TEP does not own most of the land on which its assets are located, which could disrupt its operations and subject TEP to increased costs.
TEP does not own in fee but rather have leases, easements, rights-of-way, permits and licenses for most of the land on which its assets are located, and TEP is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if TEP does not have valid interests in the land, if such interests in the land lapse or terminate or if its facilities are not properly located within the boundaries of such interests in the land. For example, the West Frenchie Draw treating facility is located on land leased from the Wyoming Board of Land Commissioners pursuant to a contract that can be terminated at any time. Although many of these rights are perpetual in nature, TEP occasionally obtains the right to construct and operate pipelines on other owners’ land for a specific period of time. If TEP was to be unsuccessful in renegotiating its leases, easements, rights-of-way, permits and licenses, TEP might incur increased costs to maintain its assets, which could have

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a material adverse effect on its business, results of operations, financial condition and ability to make distributions to its unitholders. In addition, TEP is subject to the possibility of increased costs under its rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
Some leases, easements, rights-of-way, permits and licenses for TEP's assets are shared with other pipeline systems and other assets owned by third parties. TEP or owners of the other pipeline systems or assets may not have commenced or concluded eminent domain proceedings for some rights-of-way. In some instances, lands over which leases, easements, rights-of-way, permits and licenses have been obtained are subject to prior liens which have not been subordinated to the grants to TEP.
TEP's interstate natural gas pipeline systems have federal eminent domain authority. Whether TEP has the power of eminent domain for the Pony Express crude oil pipeline varies from state to state, depending upon the laws of the particular state. Regardless, TEP must compensate landowners for the use of their property, which may include any loss of value to the remainder of their property not being used by TEP, which are sometimes referred to as "severance damages." Severance damages are often difficult to quantify and their amount can be significant. In eminent domain actions, such compensation may be determined by a court. TEP's inability to exercise the power of eminent domain could negatively affect its business if TEP was to lose the right to use or occupy the property on which its crude oil or natural gas pipeline systems are located.
TEP's operations are dependent on its rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.
Performance of TEP's operations requires that TEP obtains and maintains numerous environmental and land use permits and other approvals authorizing its business activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on its ability to initiate or continue operations at the affected location or facility. Expansion of its existing operations is also predicated on securing the necessary environmental or land use permits and other approvals, which TEP may not receive in a timely manner or at all.
In order to obtain permits and renewals of permits and other approvals in the future, TEP may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is sometimes delayed or prevented due to community opposition and other factors beyond its control. The denial of a permit or other approval essential to its operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impair or prevent its ability to develop or expand a property or right-of-way. Significant opposition to a permit or other approval by neighboring property owners, members of the public or non-governmental organizations, or other third parties or delay in the environmental review and permitting process also could impair or delay its ability to develop or expand a property or right-of-way. New legal requirements, including those related to the protection of the environment, could be adopted at the federal, state and local levels that could materially adversely affect its operations, its cost structure or its customers’ ability to use its services. Such current or future regulations could have a material adverse effect on its business and TEP may not be able to obtain or renew permits or other approvals in the future.
A shortage of skilled labor in the midstream industry could reduce labor productivity and increase costs, which could have a material adverse effect on TEP's business and results of operations.
The transportation, storage and processing of natural gas, the transportation of crude oil and water and the fractionation of NGLs requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. If TEP experiences shortages of skilled labor in the future, its labor and overall productivity or costs could be materially and adversely affected. If its labor prices increase or if TEP experiences materially increased health and benefit costs for employees, its results of operations could be materially and adversely affected.
If TEP fails to develop or maintain an effective system of internal controls, TEP may not be able to report its financial results accurately or prevent fraud, which would likely have a negative impact on the market price of its common units.
Upon the completion of the TEP IPO, TEP became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. Effective internal controls are necessary for TEP to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. TEP's efforts to develop and maintain its internal controls may not be successful, and TEP may be unable to maintain effective controls over its financial processes and reporting in the future or to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, or Section 404. For example, Section 404 requires TEP, among other things, to annually review and report on, and its independent registered public accounting firm to attest to, the effectiveness of its internal controls over financial reporting. Any failure to develop, implement or maintain

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effective internal controls or to improve its internal controls could harm its operating results or cause TEP to fail to meet its reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, TEP can provide no assurance as to its, or TEP's independent registered public accounting firm's, conclusions about the effectiveness of its internal controls, and TEP may incur significant costs in its efforts to comply with Section 404. Ineffective internal controls will subject TEP to regulatory scrutiny and a loss of confidence in its reported financial information, which could have an adverse effect on its business and would likely have a negative effect on the trading price of its common units.
The outcome of future rate cases will determine the amount of income taxes that TEP will be allowed to recover.
In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. The extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established. An adverse determination by the FERC with respect to this issue could have a material adverse effect on TEP's revenues, earnings and cash flows.
New technology, including those involving recycling of produced water or the replacement of water in fracturing fluid, may adversely affect TEP's future results of operations and financial condition.
The produced water disposal industry is subject to the introduction of new waste treatment and disposal techniques and services using new technologies including those involving recycling of produced water, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to TEP's water business services in the future, TEP may lose market share or be placed at a competitive disadvantage. For example, some companies have successfully used propane as the fracturing fluid instead of water. Further, TEP may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of its competitors may have greater financial, technical and personnel resources than TEP does, which may allow them to gain technological advantages or implement new technologies before TEP can. Additionally, TEP may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. New technology could also make it easier for TEP's customers to vertically integrate their operations or reduce the amount of waste produced in oil and natural gas drilling and production activities, thereby reducing or eliminating the need for third-party disposal. Limits on its ability to effectively use or implement new technologies in its water business services may have a material adverse effect on its business, financial condition and results of operations.
TEP's business could be negatively impacted by security threats, including cyber security threats, and related disruptions.
TEP relies on its information technology infrastructure to process, transmit and store electronic information, including information TEP uses to safely operate its assets. TEP may face cyber security and other security threats to its information technology infrastructure, which could include threats to its operational and safety systems that operate its pipelines, plants and assets. TEP could face unlawful attempts to gain access to its information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, "hacktivists," or private individuals. The age, operating systems or condition of its current information technology infrastructure and software assets and its ability to maintain and upgrade such assets could affect its ability to resist cyber security threats. TEP could also face attempts to gain access to information related to its assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information, otherwise known as "social engineering."
TEP's information technology infrastructure is critical to the efficient operation of its business and essential to its ability to perform day-to-day operations. Breaches in its information technology infrastructure or physical facilities, or other disruptions, could result in damage to its assets, service interruptions, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on its operations, financial position, results of operations and prospects.
If TEP is unable to protect its information and telecommunication systems against disruptions or failures, its operations could be disrupted.
TEP relies extensively on computer systems to process transactions, maintain information and manage its business. Disruptions in the availability of its computer systems could impact its ability to service its customers and adversely affect its sales and results of operations. TEP is dependent on internal and third-party information technology networks and systems, including the Internet and wireless communications, to process, transmit and store electronic information. TEP's computer systems are subject to damage or interruption due to system replacements, implementations and conversions, power outages, computer or telecommunication failures, computer viruses, security breaches, catastrophic events such as fires, tornadoes, snowstorms and floods and usage errors by its employees. If its computer systems are damaged or cease to function properly, TEP may have to make a significant investment to fix or replace them, and TEP may have interruptions in its ability to service its customers. Although TEP attempts to eliminate or reduce these risks by using redundant systems, this disruption caused by

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the unavailability of TEP's computer systems could nevertheless significantly disrupt its operations or may result in financial damage or loss due to, among other things, lost or misappropriated information.
Tax Risks
As our only cash-generating assets consist of our membership interest in Tallgrass Equity and its related direct and indirect interests in TEP, our tax risks are primarily derivative of the tax risks associated with an investment in TEP.
The tax treatment of TEP depends on its status as a partnership for U.S. federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat TEP as a corporation for U.S. federal income tax purposes, or TEP becomes subject to material additional amounts of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to us and increase the portion of our distributions treated as taxable dividends.
We own a 30.35% membership interest in Tallgrass Equity, which directly owns the Acquired TEP Units and indirectly owns all of TEP’s IDRs and TEP’s general partner interest (which was approximately 1.23% as of February 17, 2016). Accordingly, the value of our indirect investment in TEP, as well as the anticipated after-tax economic benefit of an investment in our Class A shares, depends largely on TEP being treated as a partnership for federal income tax purposes, which requires that 90% or more of TEP’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code of 1986, as amended (the "Code").
Despite the fact that TEP is a limited partnership under Delaware law and, unlike us, has not elected to be treated as a corporation for federal income tax purposes, it is possible, under certain circumstances, for a publicly traded partnership such as TEP to be treated as a corporation for U.S. federal income tax purposes. Although we do not believe based upon TEP's current operations that TEP is so treated, a change in TEP’s business could cause it to be treated as a corporation for federal income tax purposes or otherwise subject it to federal income taxation as an entity. For example, TEP would be treated as a corporation if less than 90% of its gross income for any taxable year consists of "qualifying income" within the meaning of Section 7704 of the Code.
If TEP were treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income taxes at varying rates. Distributions to TEP’s partners, including Tallgrass Equity, would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to TEP’s partners. Because a tax would be imposed upon TEP as a corporation, its cash available for distribution would be substantially reduced. Therefore, treatment of TEP as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to us, likely causing a substantial reduction in the value of our Class A shares.
At the state level, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.  Imposition of such a tax on TEP by any state will reduce the cash available for distributions to TEP unitholders, likely causing a substantial reduction in the value of our Class A shares.
TEP’s partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects TEP to taxation as a corporation or otherwise subjects TEP to entity-level taxation for federal income tax purposes, TEP’s minimum quarterly distribution and target distribution amounts will be adjusted to reflect the impact of that law on TEP. If this were to happen, the amount of distributions Tallgrass Equity receives from TEP and our resulting cash flows could be reduced substantially, which would adversely affect our ability to pay distributions.
Moreover, if TEP were treated as a corporation we would not be entitled to the deductions associated with our initial acquisition of interests in Tallgrass Equity or subsequent exchanges of retained Tallgrass Equity interests and Class B shares for our Class A shares. As a result, if TEP were treated as a corporation, (i) our liability for taxes would likely be higher, further reducing our cash available for distribution and (ii) a greater portion of the cash we are able to distribute would be treated as a taxable dividend.
We may incur substantial corporate income tax liabilities on our allocable share of TEP income.
We are classified as a corporation for U.S. federal income tax purposes and, in most states in which TEP does business, for state income tax purposes. To the extent that TEP allocates to us net taxable income in any year, current law provides that we will be subject to U.S. federal income tax at rates of up to 35% (and a 20% alternative minimum tax in certain cases), and to state income tax at rates that vary from state to state. The amount of cash available for distribution to you will be reduced by the amount of any such income taxes payable by us for which we establish reserves.

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The tax treatment of publicly traded partnerships such as TEP could be subject to potential legislative, judicial, or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including TEP, may be modified by legislative, judicial, or administrative changes, or interpretations of applicable law at any time. Any modifications to the U.S. federal income tax laws that may be applied retroactively or prospectively could make it more difficult or impossible to meet the expectation of future cash distributions or reduce the cash available for distributions to our shareholders. For example, from time to time, the President or members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such recent legislative proposal would have eliminated, and the President proposed in his recently issued budget proposal to eliminate, the qualifying income exception upon which TEP relies for its treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or any other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of our indirect investment in TEP. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
The sale or exchange of 50% or more of TEP’s capital and profits interests during any twelve-month period will result in its termination as a partnership for federal income tax purposes.
TEP will be considered to have technically terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a twelve-month period. Tallgrass Development and its direct and indirect owners own a substantial interest in the capital and profits of TEP. Therefore, a transfer by them of all or a portion of their interests in TEP could result in a termination of TEP for U.S. federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. TEP’s termination would, among other things, result in a deferral of depreciation deductions allowable in computing TEP’s taxable income. A deferral of depreciation deductions could increase the amount of taxable income allocated to us from TEP which could increase our tax liabilities and thereby reduce the amount of cash available for distribution. TEP’s termination currently would not affect its classification as a partnership for federal income tax purposes, but could cause it to be subject to penalties if it were unable to determine that a termination occurred.
If the IRS makes audit adjustments to TEP's income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from TEP, in which case TEP's cash available for distribution to TEP's unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to TEP's income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from TEP. TEP will generally have the ability to shift any such tax liability to its general partner and its unitholders in accordance with their interests in TEP during the year under audit, but there can be no assurance that TEP will be able to (or will choose to) do so under all circumstances. If TEP is required to make payments of taxes, penalties and interest resulting from audit adjustments, its cash available for distribution to its unitholders might be substantially reduced.
Taxable gain or loss on the sale of our Class A shares could be more or less than expected.
If a holder sells our Class A shares, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in those Class A shares. To the extent that the amount of our distributions exceeds our current and accumulated earnings and profits, the distributions will be treated as a tax free return of capital and will reduce a holder’s tax basis in the Class A shares. Because our distributions in excess of our earnings and profits decrease a holder’s tax basis in Class A shares, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A shares.
Our current tax treatment may change, which could affect the value of our Class A shares or reduce our cash available for distribution.
Changes in federal income tax law relating to such tax treatment could result in (i) our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution and (ii) a greater portion of our distributions being treated as taxable dividends. Moreover, we are subject to tax in numerous jurisdictions. Changes in current law in these jurisdictions, particularly relating to the treatment of deductions attributable to acquisitions of interests in Tallgrass Equity, could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution.

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Any decrease in our Class A share price could adversely affect our amount of cash available for distribution.
Changes in certain market conditions may cause our Class A share price to decrease. If the Exchange Right Holders exercise their Exchange Right when our Class A share price is less than the price at which the Class A shares were sold in the Offering, the ratio of our income tax deductions to gross income would decline. This decline could result in our being subject to tax sooner than expected, our tax liability being greater than expected, or a greater portion of our distributions being treated as taxable dividends.
The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income with respect to our shares for U.S. federal income tax purposes, and failure to report your dividend income in a manner consistent with the IRS Form 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your U.S. federal income tax return. If you are a non-U.S. holder of our shares, your broker or other withholding agent may overwithhold taxes from dividends paid to you, in which case you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to claim a refund of the overwithheld taxes.
Distributions we pay with respect to our shares will constitute "dividends" for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits will not be treated as "dividends" for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of your tax basis in your shares and then as capital gain realized on the sale or exchange of such shares. We may be unable to timely determine the portion of our distributions that is a "dividend" for U.S. federal income tax purposes.
If you are a U.S. holder of our Class A shares, the IRS Form 1099-DIV may not be consistent with our determination of the amount that constitutes a "dividend" to you for U.S. federal income tax purposes or you may receive a corrected IRS Form 1099-DIV (and you may therefore need to file an amended federal, state or local income tax return). We will attempt to timely notify you of available information to assist you with your income tax reporting (such as posting the correct information on our website). However, the information that we provide to you may be inconsistent with the amounts reported to you by your broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your tax return.
If you are a non-U.S. holder of our Class A shares, "dividends" for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with your conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributions that is a "dividend" for U.S. federal income tax purposes, or your broker or withholding agent chooses to withhold taxes from distributions in a manner inconsistent with our determination of the amount that constitutes a "dividend" for such purposes, your broker or other withholding agent may overwithhold taxes from distributions paid to you. In such a case, you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
A description of our properties is contained in Item 1.—Business, "Our Assets" of this Annual Report.
Our principal executive offices are located at 4200 W. 115th Street, Suite 350, Leawood, KS 66211 and our telephone number is 913-928-6060.
We own two office buildings in Lakewood, Colorado, with a portion being leased to a third party pursuant to a lease with an initial term through 2020. In addition, we lease our principal executive offices in Leawood, Kansas. Tallgrass Development pays a proportionate share of the costs to occupy the building to us pursuant to the TEP Omnibus Agreement.
Item 3. Legal Proceedings
See Note 18Legal and Environmental Matters to the consolidated financial statements included in Part II—Item 8.—Financial Statements and Supplementary Data of this Annual Report, which is incorporated by reference into this Part I—Item 3 of this Annual Report.
Item 4. Mine Safety Disclosures
Not applicable.

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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our Class A shares have been listed and traded on the NYSE under the symbol "TEGP" since the completion of the Offering on May 12, 2015. Our Class B shares are not listed or traded on any stock exchange. The following table sets forth the high and low sales prices of the Class A shares, as reported by the NYSE, as well as the amount of cash distributions per share declared for the periods indicated:
Quarter Ended
 
High
 
Low
 
Distribution per Class A Share
December 31, 2015
 
$
26.10

 
$
13.30

 
$
0.1730

 
September 30, 2015
 
$
32.18

 
$
17.67

 
$
0.1440

 
June 30, 2015
 
$
34.98

 
$
30.08

 
$
0.0730

(1) 
(1)
The first quarterly distribution declared on July 15, 2015 was prorated for the number of days between the closing of TEGP’s initial public offering on May 12, 2015 and the end of the second quarter.
Holders
As of February 17, 2016, there was one shareholder of record of our Class A shares. This number does not include shareholders whose shares are held in trust by other entities. The actual number of beneficial shareholders is greater than the number of holders of record. In addition, as of February 17, 2016, 6 shareholders of record owned all 109,504,440 of our Class B shares.
Equity Compensation Plan
See Item 12.—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding our Equity Compensation Plan.
Distributions of Available Cash
General. Our partnership agreement requires that, within 55 days after the end of each quarter beginning with the quarter ending June 30, 2015, we distribute our available cash to Class A Shareholders of record on the applicable record date.
Definition of Available Cash. Available cash is defined in our partnership agreement and generally means, with respect to any calendar quarter, all cash on hand at the date of determination of available cash for the distribution in respect of such quarter (including expected distributions from Tallgrass Equity in respect of such quarter), less the amount of cash reserves established by our general partner, which will not be subject to a cap, to:
comply with applicable law;
comply with any agreement binding upon us or our subsidiaries (exclusive of TEP and its subsidiaries);
provide for future capital expenditures, debt service and other credit needs as well as any federal, state, provincial or other income tax that may affect us in the future;
permit us to pay a ratable amount to Tallgrass Equity as necessary to permit Tallgrass Equity to make capital contributions to TEP GP for it to maintain or attain up to a 2.0% general partner interest in TEP; or
otherwise provide for the proper conduct of our business.
Our available cash includes cash on hand resulting from borrowings made after the end of the quarter.
Our Sources of Available Cash. Our only cash-generating assets consist of our indirect partnership interests in TEP through our 30.35% membership interest in Tallgrass Equity. Therefore, our cash flow and resulting ability to make distributions will be completely dependent upon the ability of TEP to make distributions.
The actual amount of cash that TEP, and correspondingly Tallgrass Equity, will have available for distribution will primarily depend on the amount of cash TEP generates from its operations. For a description of factors that may impact our results and TEP’s results, please read "Item 1A.—Risk Factors."

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In addition, the actual amount of cash that TEP and Tallgrass Equity will have available for distribution will depend on other factors, some of which are beyond our control, including:
the level of revenue TEP and Tallgrass Equity are able to generate from their respective businesses;
the level of capital expenditures TEP or Tallgrass Equity makes;
the level of TEP’s and Tallgrass Equity’s operating, maintenance and general and administrative expenses or related obligations;
the cost of acquisitions, if any;
TEP’s and Tallgrass Equity’s debt service requirements and other liabilities;
TEP’s and Tallgrass Equity’s working capital needs;
restrictions on distributions contained in TEP’s or Tallgrass Equity’s debt agreements and any future debt agreements;
TEP’s and Tallgrass Equity’s ability to borrow under their respective revolving credit agreements to make distributions; and
the amount, if any, of cash reserves established by each of TEP GP and our general partner, in their sole discretion, for the proper conduct of TEP’s and our business.
Performance Graph
The following performance graph compares the performance of our Class A shares with the NYSE Composite Index Total Return and the Alerian Total Return MLP Index during the period beginning on May 12, 2015, and ending on December 31, 2015. The graph assumes a $100 investment in our Class A shares and in each of the indices at the beginning of the period and a reinvestment of distributions/dividends paid on such investments throughout the period.
Recent Sales of Unregistered Equity Securities
None.
Repurchase of Equity by Tallgrass Energy GP, LP or Affiliated Purchasers
None.

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Item 6. Selected Financial Data
The historical financial statements included in this Annual Report reflect the consolidated results of operations of TEGP's 30.35% interest in Tallgrass Equity, Tallgrass Equity's 100% membership interest in TEP GP, which owns all of the IDRs, and all of the outstanding general partner units in TEP, and Tallgrass Equity's 20 million TEP common units it acquired at the closing of the Offering. In connection with the closing of the Offering on May 12, 2015, the following transactions (the "Reorganization Transactions") occurred (i) Tallgrass Equity distributed its interests in Tallgrass Energy Holdings and Tallgrass Energy Holdings distributed its existing limited partner interest in TEGP, respectively, to the Exchange Right Holders that also collectively own 100% of the voting power of Tallgrass Energy Holdings; (ii) TEGP issued 47,725,000 Class A shares to the public (including 6,225,000 Class A shares issued in connection with the underwriters' exercise of the overallotment option) for net proceeds of approximately $1.3 billion; (iii) the existing limited partner interests in TEGP held by the Exchange Right Holders were converted into 115,729,440 Class B shares, 6,225,000 of which were automatically cancelled in connection with the underwriters’ exercise of its overallotment option; (iv) Tallgrass Equity issued 41,500,000 Tallgrass Equity units to TEGP in exchange for approximately $1.1 billion in net proceeds from the issuance of TEGP’s Class A shares to the public and amended the limited liability company agreement of Tallgrass Equity to, among other things, provide that TEGP is the managing member of Tallgrass Equity; (v) TEGP used the net proceeds from the purchase of the 6,225,000 overallotment option shares to purchase a like amount of Tallgrass Equity units from the Exchange Right Holders; and (vi) Tallgrass Equity entered into a $150 million revolving credit facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings, together with the net proceeds from the Offering that Tallgrass Equity received from TEGP, to purchase 20 million TEP common units from Tallgrass Development, LP at $47.68 per TEP common unit (the "Acquired TEP Units") and pay offering expenses and other transaction costs. Tallgrass Equity distributed the remaining proceeds (the "Excess Proceeds") to the Exchange Right Holders. The following discussion analyzes the financial condition and results of operations of TEGP, which for periods prior to the completion of the Offering on May 12, 2015 includes the financial condition and results of operations of TEGP Predecessor, which refers to TEGP as recast to show the effects of the Reorganization Transactions.
In certain circumstances and for ease of reading we discuss the financial results of these entities prior to their respective acquisitions as being "our" financial results during historic periods, although Trailblazer was owned by TD from November 13, 2012 to March 31, 2014, and Pony Express was wholly-owned by TD from November 13, 2012 to August 31, 2014. As used in this Annual Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEGP" and similar terms refer to Tallgrass Energy GP, LP, together with its consolidated subsidiaries (including Tallgrass Equity, TEP and their respective subsidiaries). The term our "general partner" refers to TEGP Management, LLC. References to "Tallgrass Development" or "TD" refer to Tallgrass Development, LP.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes thereto included elsewhere in this Annual Report. A reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8.Financial Statements. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.
The following table shows selected historical financial and operating data of TEGP for the periods and as of the dates indicated. The selected historical financial data for periods prior to the completion of the Offering on May 12, 2015 includes the financial condition and results of operations of TEGP Predecessor, which refers to TEGP as recast to show the effects of the Reorganization Transactions.
We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the consolidated financial statements and the accompanying notes included elsewhere in this Annual Report.

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Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data included herein to not be indicative of our future financial condition or results of operations. A discussion of our critical accounting estimates is included in "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in Item 7.
 
Year Ended December 31,
 
Period from November 13 to December 31, 2012
 
2015
 
2014
 
2013
 
 
(in thousands, except per unit amounts)
Statement of operations data:
 
 
 
 
 
 
 
Revenue
$
536,197

 
$
371,556

 
$
290,526

 
$
38,572

Operating income
$
196,631

 
$
53,413

 
$
33,999

 
$
69

Net income (loss) before tax
$
180,714

 
$
59,329

 
$
7,624

 
$
(2,618
)
Net income
$
187,991

 
$
59,329

 
$
7,624

 
$
(2,618
)
Net income (loss) attributable to TEGP
$
31,956

 
$
10,914

 
$
1,501

 
$
(362
)
Basic net income per Class A share
$
0.51

 
N/A

 
N/A

 
N/A

Diluted net income per Class A share
$
0.51

 
N/A

 
N/A

 
N/A

Balance sheet data (at end of period):
 
 
 
 
 
 
 
Property, plant and equipment, net
$
2,025,018

 
$
1,853,081

 
$
1,116,806

 
$
726,754

Total assets
$
3,016,660

 
$
2,457,197

 
$
1,631,413

 
$
1,238,598

Long-term debt
$
901,000

 
$
559,000

 
$
135,000

 
$
390,491

Other:
 
 
 
 
 
 
 
Distributions declared per Class A share
$
0.39

 
N/A

 
N/A

 
N/A

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
TEGP is a limited partnership that has elected to be treated as a corporation for U.S. federal income tax purposes. We were formed as part of a reorganization involving entities that were previously controlled by Tallgrass Equity in order to effect the initial public offering of our Class A shares (the "Offering"). The Offering was completed on May 12, 2015.
Our sole cash-generating asset is an approximate 30.35% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of the direct and indirect partnership interests in Tallgrass Energy Partners, LP, a Delaware limited partnership ("TEP"), described below:
We own 100% of the outstanding membership interests in TEP GP, which owns all of the general partner interest in TEP and all of TEP's IDRs. The general partner interest in TEP is represented by 834,391 general partner units, representing an approximate 1.23% general partner interest in TEP at February 17, 2016.
We own 20,000,000 TEP common units, representing an approximately 29.41% limited partner interest in TEP at February 17, 2016.
TEP is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. We currently provide crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Pony Express, which owns the Pony Express System, a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado. We provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through the TIGT System, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming, and the Trailblazer Pipeline, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska. We also provide services for customers at our Midstream Facilities located in Wyoming, and NGL transportation services in Northeast Colorado. We perform water business services in Colorado and Texas through Water Solutions. Our operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations.

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We intend to continue to leverage our relationship with TD and utilize the significant experience of our management team to execute our growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of our existing assets and expanding our systems through construction of additional assets. Our reportable business segments are:
Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system;
Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and
Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, the provision of water business services primarily to the oil and gas exploration and production industry and the transportation of NGLs.
Financial Presentation
TEGP has no operations outside of its indirect ownership interests in TEP. TEGP is the managing member of and therefore controls Tallgrass Equity. Tallgrass Equity, in turn, controls TEP through the direct ownership of 100% of TEP GP, TEP’s general partner. As a result, under generally accepted accounting principles, TEGP consolidates Tallgrass Equity, TEP GP, TEP, and TEP's subsidiaries. As such, TEGP's results of operations will not differ materially from the results of operations of TEP. The most noteworthy reconciling items between TEGP's consolidated financial statements and TEP's consolidated financial statements primarily relate to (i) the inclusion of the Tallgrass Equity revolving credit facility, (ii) the impact of TEGP's election to be treated as a corporation for U.S. federal income tax purposes and (iii) the presentation of noncontrolling interests in Tallgrass Equity and TEP. The interests in Tallgrass Equity and TEP that are not directly or indirectly owned by TEGP will be reflected as attributable to noncontrolling interests in TEGP's consolidated financial statements.
In addition, TEP’s historical results of operations do not reflect TEGP's incremental general and administrative costs associated with becoming a separate publicly traded entity, including expenses associated with (i) compensation for new directors, (ii) incremental director and officer liability insurance, (iii) listing on the NYSE, (iv) investor relations, (v) legal, (vi) tax and (vii) accounting.
Summary of Results for the Year Ended December 31, 2015
On May 12, 2015, we completed our initial public offering of 47,725,000 Class A shares to the public for net proceeds of approximately $1.3 billion, including 6,225,000 Class A shares issued in connection with the underwriters' exercise of the overallotment option, and entered into a $150 million revolving credit facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings together with the net proceeds from the Offering that Tallgrass Equity received from TEGP, to purchase 20,000,000 common units, representing limited partner interests in TEP, from TD.
During 2015, TEP completed the acquisitions of an additional 33.3% membership interest in Pony Express and a 100% membership interest in Western, which owns water business services assets located in Weld County, Colorado. In addition, Pony Express placed into commercial service its lateral in Northeast Colorado during the second quarter of 2015.
Net income attributable to TEGP for the year ended December 31, 2015 was $32.0 million, compared to net income attributable to TEGP for the year ended December 31, 2014 of $10.9 million. The increase in net income attributable to TEGP was largely driven by the ramping up of commercial operations at Pony Express and the lateral in Northeast Colorado and TEP's acquisition of an additional 33.3% membership interest in Pony Express on March 1, 2015, as discussed further under "Results of Operations" below.
Recent Developments
TEGP Distribution Declared
On January 4, 2016, the Board of Directors of our general partner declared a cash distribution for the quarter ended December 31, 2015 of $0.173 per Class A share. The distribution was paid on February 12, 2016, to Class A shareholders of record on January 29, 2016.
TEP Distribution Declared
On January 4, 2016, the Board of Directors of TEP's general partner declared a cash distribution for the quarter ended December 31, 2015 of $0.64 per common unit. The distribution was paid on February 12, 2016, to unitholders of record on January 29, 2016.

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Acquisition of an Additional 31.3% of Pony Express
Effective January 1, 2016, TEP acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of TEP’s common units) issued to TD for total consideration of approximately $743.6 million. The transaction increases TEP’s aggregate membership interest in Pony Express to 98.0%. As part of the transaction, TD granted TEP an 18 month call option to repurchase the newly issued 6,518,000 common units at a price of $42.50.
TEP Revolving Credit Facility
In connection with the acquisition of an additional 31.3% membership interest in Pony Express as discussed above, TEP exercised its option to increase the commitment under its existing revolving credit facility from $1.1 billion to $1.5 billion effective January 4, 2016. As of January 31, 2016, TEP had approximately $1.2 billion of outstanding borrowings under its revolving credit facility.
Tallgrass Development Purchase Program
On February 17, 2016, TEP and TEGP announced that the Board of Directors of Tallgrass Energy Holdings, the sole member of TEGP’s general partner and the general partner of TD, has authorized an equity purchase program under which TD may initially purchase up to an aggregate of $100 million of the outstanding Class A shares of TEGP or the outstanding common units of TEP. TD may purchase Class A shares or Common Units from time to time on the open market or in negotiated purchases. The timing and amounts of any such purchases will be subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The purchase plan does not obligate TD to acquire any specific number of Class A shares or Common Units and may be discontinued at any time.
Factors and Trends Impacting Our Business
We expect to continue to be affected by certain key factors and trends described below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. See also Item 1A.Risk Factors.
Long Term U.S. Crude Oil and Natural Gas Prospects
Crude oil, natural gas and products derived from both continue to be critical components of energy supply and demand in the United States. Although crude oil and natural gas prices have declined significantly in the latter part of 2014 and throughout 2015 and early 2016, and may experience further declines or remain at or near current levels for the foreseeable future, we nevertheless believe that the long-term prospects for continued crude oil and natural gas production increases are favorable.
We believe long-term growth will be driven, in part, by a combination of increased domestic demand resulting from population and economic growth, higher industrial consumption in the U.S., and a desire to reduce domestic reliance on imports. One example is that we expect natural gas to gradually displace coal-fired electricity generation due to the low prices of natural gas and stricter environmental regulations on the mining and burning of coal. We expect productivity of oil and natural gas wells to continue increasing over the long-term in some basins across the United States because of the increasing precision and efficiency of horizontal drilling and hydraulic fracturing in oil and natural gas extraction. We also believe there is a substantial inventory of drilled but uncompleted wells in the basins we serve, including the Bakken shale, that is likely to be completed and turned into production once commodity prices recover and volatility decreases.
Current Commodity Environment
Starting in 2014, the prices of crude oil, natural gas, and NGLs were extremely volatile and declined significantly. Downward pressure on commodity prices continued in 2015 and the early part of 2016 and may continue for the foreseeable future. This could impact our business in several ways.
Demand for our services depends, in part, on the development of additional natural gas and crude oil reserves by third parties. This requires significant capital expenditures by others to install facilities that extract natural gas and crude oil. However, low commodity prices result in a lack of available capital for these types of expenditures. To the extent our customers cannot finance these activities, we also expect they will be less likely to enter into demand based, long-term firm fee contracts until commodity prices recover and pricing stability returns to the commodity markets. The recent commodity price declines may also negatively impact the financial condition of our customers and could impact their ability to meet their financial obligations to us.

59




Additionally, lower commodity prices generally lead to reduced utilization of our assets. For example, reduced utilization could result in increased deficiency balances held by customers of our Pony Express System. For additional information see"Risk FactorsThe TDAs for the Pony Express System and some of TEP's service agreements with respect to its water business services contain provisions that can reduce the cash flow stability that the agreements were designed to achieve." In addition, declining drilling activity by producers and other factors within the region served by our Midstream Facilities has led to an average quarterly decrease in our natural gas processing inlet volumes at our natural gas processing and treating plants of 11% over the year ended December 31, 2015. We expect further volumetric decreases in 2016. As a result, management identified a potential impairment trigger with respect to the goodwill allocated to the TMID reporting unit. As discussed further under "Critical Accounting Policies and Estimates" below, we tested the goodwill for impairment as of December 31, 2015 and noted that no impairment exists at this time.
Growth Associated with Acquisitions and Expansion Projects
Growth associated with acquisitions
We believe that we are well-positioned to grow through accretive acquisitions. We intend to pursue acquisition opportunities from third parties as they become available and expect to continue to acquire assets from TD’s portfolio of midstream assets, which include TD’s 50% interest in, and operation of, the REX Pipeline, and 100% ownership interest in Terminals. We expect TD to retain its 2% ownership interest in Pony Express for the foreseeable future. Pursuant to the TEP Omnibus Agreement, TD granted us the right of first offer to acquire each of the remaining Retained Assets if TD decides to sell those assets. Terminals is not a Retained Asset. Other than its obligations under the TEP Omnibus Agreement, TD is under no obligation to offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any assets from TD or pursue any such joint acquisitions. However, given the significant economic interest in us held by TD and its affiliates, we believe TD will be incentivized to offer us the opportunity to acquire its assets as each matures into an operating profile more conducive to our principal business objective of increasing the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business.
Growth associated with expansion projects
We also believe that we are well positioned to increase volumes to our systems through cost-effective capacity expansions and other methods for improving efficiency, such as the use of drag reducing agents in our crude oil pipelines. For example, in 2014, Pony Express completed the conversion and construction of its approximately 698-mile crude oil pipeline commencing in Guernsey, Wyoming, and terminating in Cushing, Oklahoma. In 2015, Pony Express completed the construction of an approximately 66-mile lateral in Northeast Colorado commencing in Weld County, Colorado, and interconnecting with the pipeline just east of Sterling, Colorado.
Energy Capital Markets and Interest Rates
During the second half of 2015 the energy credit markets experienced a material increase in the yields for long term debt, causing an issuance of senior unsecured notes to be a less attractive financing option. At the same time, the downturn in commodity prices has also generally limited the availability of capital through traditional public issuances of common units. While this downturn has not changed our business plans, including our continued intent to grow through acquisitions and expansion projects, it has altered some of our financing strategies.
In addition, the Federal Reserve increased short-term interest rates which marginally impacted the rates on our floating rate revolving credit facility. If the economy continues to strengthen, it is likely that monetary policy will continue to tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on our floating rate credit facilities and future offerings in the debt capital markets could be at higher rates, causing our financing costs to increase accordingly. For additional information, please read Item 7A.—Quantitative and Qualitative Disclosures About Market Risk.
How We Evaluate Our Operations
We evaluate our results using, among other measures, cash distributions received from Tallgrass Equity, TEP's contract profile and volumes, and operating costs and expenses of TEGP and its consolidated subsidiaries.
Cash Distributions Received from Tallgrass Equity
TEGP's cash flow is currently generated solely by distributions received from Tallgrass Equity. Tallgrass Equity currently receives all of its cash flows from distributions on its direct and indirect partnership interests in TEP. Tallgrass Equity is therefore entirely dependent upon the ability of TEP to make cash distributions to its partners.

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Contract Profile and Volumes
Our results are driven primarily by the volume of crude oil transportation capacity, natural gas transportation and storage capacity, NGL transportation capacity, and water transportation, gathering and disposal capacity under firm contracts, as well as the volume of natural gas that we process and the fees assessed for such services.
Operating Costs and Expenses
The primary components of our operating costs and expenses that we evaluate include cost of sales, cost of transportation services, operations and maintenance and general and administrative costs. Our operating expenses are driven primarily by expenses related to the operation, maintenance and growth of our asset base.

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Results of Operations
The following provides a summary of our consolidated results of operations for the periods indicated:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands, except operating data)
Revenues:
 
 
 
 
 
Crude oil transportation services
$
300,436

 
$
28,343

 
$

Natural gas transportation services
119,895

 
126,733

 
120,025

Sales of natural gas, NGLs, and crude oil
82,133

 
181,249

 
155,700

Processing and other revenues
33,733

 
35,231

 
14,801

Total Revenues
536,197

 
371,556

 
290,526

Operating Costs and Expenses:
 
 
 
 
 
Cost of sales (exclusive of depreciation and amortization shown below)
75,285

 
167,545

 
131,095

Cost of transportation services (exclusive of depreciation and amortization shown below)
53,597

 
24,109

 
15,059

Operations and maintenance
49,138

 
39,577

 
35,404

Depreciation and amortization
83,476

 
47,048

 
39,917

General and administrative
51,479

 
33,160

 
27,651

Taxes, other than income taxes
21,796

 
6,704

 
7,401

Loss on sale of assets
4,795

 

 

Total Operating Costs and Expenses
339,566

 
318,143

 
256,527

Operating Income
196,631

 
53,413

 
33,999

Other (Expense) Income:
 
 
 
 
 
Interest expense, net
(18,330
)
 
(7,292
)
 
(11,054
)
Gain on remeasurement of unconsolidated investment

 
9,388

 

Loss on extinguishment of debt
(226
)
 

 
(17,526
)
Equity in earnings of unconsolidated investment

 
717

 

Other income, net
2,639

 
3,103

 
2,205

Total Other (Expense) Income
(15,917
)
 
5,916

 
(26,375
)
Net income before tax
180,714

 
59,329

 
7,624

Deferred income tax benefit
7,277

 

 

Net income
187,991

 
59,329

 
7,624

Net income attributable to noncontrolling interests
(156,035
)
 
(48,415
)
 
(6,123
)
Net income attributable to TEGP
$
31,956

 
$
10,914

 
$
1,501

Operating Data:
 
 
 
 
 
Crude oil transportation average throughput (Bbls/d) (1)
236,256

 
85,229

 
N/A

Gas transportation firm contracted capacity (MMcf/d)
1,517

 
1,537

 
1,411

Natural gas processing inlet volumes (MMcf/d)
122

 
152

 
133

(1) 
Approximate average daily throughput for the year ended December 31, 2014 is reflective of the volumetric ramp up due to commercial in-service of the Pony Express System beginning in October 2014, including the lateral in Northeast Colorado in the second quarter of 2015, and delays in the construction and expansion efforts of third-party pipelines with which Pony Express shares joint tariffs.

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Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Revenues. Total revenues were $536.2 million for the year ended December 31, 2015, compared to $371.6 million for the year ended December 31, 2014, which represents an increase of $164.6 million, or 44%, in total revenues. The overall increase in revenues was primarily driven by increased revenue of $275.9 million in the Crude Oil Transportation & Logistics segment, partially offset by decreases in revenues of $102.7 million and $8.4 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, as discussed further below.
Operating costs and expenses. Operating costs and expenses were $339.6 million for the year ended December 31, 2015 compared to $318.1 million for the year ended December 31, 2014, which represents an increase of $21.4 million, or 7%. The overall increase in operating costs and expenses is primarily driven by increased operating costs and expenses of $120.0 million in the Crude Oil Transportation & Logistics segment, partially offset by decreases in operating costs and expenses of $86.8 million and $9.3 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively, as discussed further below.
Interest expense, net. Interest expense of $18.3 million for the year ended December 31, 2015 was primarily composed of interest and fees associated with TEP’s and Tallgrass Equity's revolving credit facilities, partially offset by interest income of $0.4 million on the cash balance swept to TD under the Pony Express cash management agreement. Interest expense of $7.3 million for the year ended December 31, 2014 was primarily composed of interest and fees associated with TEP’s revolving credit facility, partially offset by interest income of $1.5 million on the cash balance swept to TD under the Pony Express cash management agreement. The increase in interest and fees in 2015 was driven by borrowings under Tallgrass Equity's revolving credit facility as part of the Reorganization Transactions and increased borrowings under TEP's revolving credit facility throughout 2014 and 2015 to fund the acquisitions of Trailblazer and our 66.7% membership interest in Pony Express.
Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.4 million for the year ended December 31, 2014 was related to the remeasurement to fair value of our original 50% equity investment in Grasslands Water Services I, LLC ("GWSI") in connection with TEP's consolidation of the Water Solutions business on May 13, 2014.
Loss on extinguishment of debt. Loss on extinguishment of debt of $0.2 million for the year ended December 31, 2015 represents the loss associated with the write off of deferred financing costs associated with the reassignment of a single lender's commitment under TEP's revolving credit facility.
Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.7 million for the year ended December 31, 2014 was related to our investment in GWSI prior to TEP's consolidation of the Water Solutions business on May 13, 2014.
Other income, net. Other income, net typically includes rental income, income earned from certain customers related to the capital costs we incurred to connect these customers to our system, and the allowance for funds used during construction at our regulated entities. Other income for the year ended December 31, 2015 was $2.6 million compared to $3.1 million for the year ended December 31, 2014.
Deferred income tax benefit. Deferred income tax benefit for the year ended December 31, 2015 was $7.3 million, and represents a $13.8 million deferred income tax benefit associated with a change in applicable state apportionment percentages, which increased the value of expected future state tax benefits attributable to the excess tax basis of our investment in Tallgrass Equity, partially offset by deferred income tax expense of $6.5 million related to our income for the period from May 12, 2015 to December 31, 2015.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Revenues. Total revenues were $371.6 million for the year ended December 31, 2014, compared to $290.5 million for the year ended December 31, 2013, which represents an increase of $81.0 million, or 28%, in total revenues. The overall increase in revenues is primarily driven by increased revenues of $43.8 million in the Processing & Logistics segment and $12.2 million in the Natural Gas Transportation & Logistics segment. Additionally, there were revenues of $28.3 million in the Crude Oil Transportation & Logistics segment for the year ended December 31, 2014, but no revenues in that segment for the year ended December 31, 2013 as Pony Express had not yet commenced commercial operations.
Operating costs and expenses. Operating costs and expenses were $318.1 million for the year ended December 31, 2014 compared to $256.5 million for the year ended December 31, 2013, which represents an increase of $61.6 million, or 24%. The overall increase in operating costs and expenses is primarily driven by increased operating costs and expenses of $39.7 million in the Processing & Logistics segment and increased operating costs and expenses of $21.6 million in the Crude Oil & Logistics segment due to the start of commercial operations at the mainline portion of the Pony Express System in October 2014. The increased costs in the Processing & Logistics and Crude Oil & Logistics segments were partially offset by decreased costs of $4.6 million in the Natural Gas Transportation & Logistics segment.

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Interest expense, net. Interest expense of $7.3 million for the year ended December 31, 2014 was primarily composed of interest and fees associated with TEP’s revolving credit facility, partially offset by interest income of $1.5 million on the cash balance swept to TD under the Pony Express cash management agreement. Interest expense of $11.1 million for the year ended December 31, 2013 primarily represents the interest expense related to the $400 million term loan allocated from TD, which was legally assumed by TEP and repaid upon closing of the TEP IPO on May 17, 2013, as well as interest and fees associated with TEP's revolving credit facility.
Gain on remeasurement of unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.4 million for the year ended December 31, 2014 was related to the remeasurement to fair value of our original 50% equity investment in Grasslands Water Services I, LLC ("GWSI") in connection with TEP's consolidation of the Water Solutions business on May 13, 2014.
Loss on extinguishment of debt. Loss on extinguishment of debt of $17.5 million for the year ended December 31, 2013 represents the loss associated with the write off of deferred financing costs and unamortized discounts associated with the repayment of debt allocated from TD.
Equity in earnings of unconsolidated investment. Equity in earnings of unconsolidated investment of $0.7 million for the year ended December 31, 2014 was related to our investment in GWSI prior to TEP's consolidation of the Water Solutions business on May 13, 2014.
Other income, net. Other income, net typically includes rental income, income earned from certain customers related to the capital costs we incurred to connect these customers to our system, and the allowance for funds used during construction at our regulated entities. Other income for the year ended December 31, 2014 was $3.1 million compared to $2.2 million for the year ended December 31, 2013.
The following provides a summary of our Crude Oil Transportation & Logistics segment results of operations for the periods indicated:
 
Year Ended December 31,
Segment Financial Data - Crude Oil Transportation & Logistics (1)
2015
 
2014
 
2013
 
(in thousands)
Revenues:
 
 
 
 
 
Crude Oil transportation services
$
300,436

 
$
28,343

 
$

Sales of natural gas, NGLs, and crude oil
3,791

 

 

Total revenues
304,227

 
28,343

 

Operating costs and expenses:
 
 
 
 
 
Cost of sales
4,257

 

 

Cost of transportation services
47,367

 
7,025

 

Operations and maintenance
8,795

 
717

 

Depreciation and amortization
47,168

 
12,067

 
3,028

General and administrative
20,620

 
4,683

 
128

Taxes, other than income taxes
16,553

 
250

 

Total operating costs and expenses
144,760

 
24,742

 
3,156

Operating income (loss)
$
159,467

 
$
3,601

 
$
(3,156
)
(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 19Reporting Segments to the accompanying consolidated financial statements.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Revenues. Crude Oil Transportation & Logistics segment revenues were $304.2 million for the year ended December 31, 2015, compared to $28.3 million for the year ended December 31, 2014. Revenue for the year ended December 31, 2015 represents a full year of operations at Pony Express, including approximately $62.6 million of revenue from a partial year of operations on the lateral in Northeast Colorado, which began commercial operations during the second quarter of 2015, and approximately $32.8 million related to the activation of one of our joint tariffs in the second quarter of 2015. Revenue for the year ended December 31, 2014 represents a partial year of operations at the mainline portion of the Pony Express System, which began commercial operations in October 2014.

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Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were $144.8 million for the year ended December 31, 2015 compared to $24.7 million for the year ended December 31, 2014. Operating costs and expenses for the year ended December 31, 2015 represents a full year of operations at Pony Express as well as a partial year of operations on the lateral in Northeast Colorado, which began commercial operations during the second quarter of 2015. Operating costs and expenses for the year ended December 31, 2014 represents a partial year of operations at the mainline portion of the Pony Express System, which began commercial operations in October 2014.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Revenues. Crude Oil Transportation & Logistics segment revenues of $28.3 million for the year ended December 31, 2014 represents transportation revenue on the mainline portion of the Pony Express System, which was placed in service in October 2014. There were no revenues for the year ended December 31, 2013.
Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation & Logistics segment were $24.7 million for the year ended December 31, 2014 compared to $3.2 million for the year ended December 31, 2013. Operating costs and expenses for the year ended December 31, 2014 include costs associated with the start of commercial operations in October 2014 as well as the amortization of the Pony Express oil conversion use rights as discussed further in Note 8 – Goodwill and Other Intangible Assets. For the year ended December 31, 2013, operating costs and expenses consisted primarily of the amortization of the Pony Express oil conversion use rights.
The following provides a summary of our Natural Gas Transportation & Logistics segment results of operations for the periods indicated:
 
Year Ended December 31,
Segment Financial Data - Natural Gas Transportation & Logistics (1)
2015
 
2014
 
2013
 
(in thousands)
Revenues:
 
 
 
 
 
Natural gas transportation services
$
125,279

 
$
131,990

 
$
121,945

Sales of natural gas, NGLs, and crude oil
6,346

 
7,868

 
5,906

Processing and other revenues
32

 
222

 
26

Total revenues
131,657

 
140,080

 
127,877

Operating costs and expenses:
 
 
 
 
 
Cost of sales
6,342

 
7,025

 
4,234

Cost of transportation services
10,927

 
18,090

 
15,059

Operations and maintenance
27,767

 
27,422

 
26,682

Depreciation and amortization
22,927

 
23,788

 
30,169

General and administrative
17,052

 
16,767

 
20,604

Taxes, other than income taxes
4,840

 
6,101

 
7,089

Total operating costs and expenses
89,855

 
99,193

 
103,837

Operating income
$
41,802

 
$
40,887

 
$
24,040

(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 19Reporting Segments to the accompanying consolidated financial statements.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Revenues. Natural Gas Transportation & Logistics segment revenues were $131.7 million for the year ended December 31, 2015, compared to $140.1 million for the year ended December 31, 2014, which represents an $8.4 million, or 6%, decrease in segment revenues primarily due to a $6.7 million decrease in natural gas transportation services revenue driven by lower fuel reimbursements as a result of decreased prices and a $1.5 million decrease in revenue from the sales of natural gas, NGLs, and crude oil as a result of a 46% decrease in natural gas prices, partially offset by favorable hedge settlements and increased volumes sold.

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Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $89.9 million for the year ended December 31, 2015 compared to $99.2 million for the year ended December 31, 2014, which represents a decrease of $9.3 million, or 9%. The overall decrease in operating costs and expenses was primarily driven by a $7.2 million decrease in the cost of transportation services, due to lower fuel reimbursements as a result of decreased prices, a $1.3 million decrease in taxes, other than income taxes, due to revised property tax estimates as a result of successful appeals with state taxing authorities on the assessed value of property, a $0.9 million decrease in depreciation and amortization driven by a change in rates at Trailblazer as a result of the rate case settlement in 2014, and a $0.7 million decrease in cost of sales, due to a 51% decrease in natural gas prices, partially offset by increased volumes sold.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Revenues. Natural Gas Transportation & Logistics segment revenues were $140.1 million for the year ended December 31, 2014, compared to $127.9 million for the year ended December 31, 2013, which represents a $12.2 million, or 10% increase in segment revenues. The increase in segment revenues was driven by a $10.0 million increase in transportation services revenue primarily due to increased transportation volumes at Trailblazer and increased fuel reimbursements as a result of higher prices at TIGT, and a $2.0 million increase in natural gas sales primarily due to 38% higher prices, partially offset by decreased volumes sold.
Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation & Logistics segment were $99.2 million for the year ended December 31, 2014 compared to $103.8 million for the year ended December 31, 2013, which represents a decrease of $4.6 million, or 4%. The overall decrease in operating costs and expenses was primarily driven by a $6.4 million decrease in depreciation and amortization primarily driven by the sale of the Pony Express Assets in the fourth quarter of 2013 and the decreased depreciation rates included in the Trailblazer rate case settlement in the second quarter of 2014 and a $3.8 million decrease in general and administrative costs, due to the decrease in costs allocated to Trailblazer by TEP in periods subsequent to our acquisition of Trailblazer on April 1, 2014 as compared to the costs allocated to Trailblazer by TD prior to April 1, 2014. These decreases were partially offset by a $2.8 million increase in cost of sales due to increased volumes of natural gas sold and a $3.0 million increase in cost of transportation services due to increased costs at TIGT, primarily driven by increased fuel reimbursements and gas purchases, partially offset by decreased costs at Trailblazer driven by lower fuel costs in 2014 as a result of the Trailblazer rate case settlement.
The following provides a summary of our Processing & Logistics segment results of operations for the periods indicated:
 
Year Ended December 31,
Segment Financial Data - Processing & Logistics (1)
2015
 
2014
 
2013
 
(in thousands)
Revenues:
 
 
 
 
 
Sales of natural gas, NGLs, and crude oil
$
71,996

 
$
173,381

 
$
149,794

Processing and other revenues
33,701

 
35,009

 
14,775

Total revenues
105,697

 
208,390

 
164,569

Operating costs and expenses:
 
 
 
 
 
Cost of sales
64,686

 
160,520

 
128,781

Cost of transportation services
687

 
236

 

Operations and maintenance
12,576

 
11,438

 
8,722

Depreciation and amortization
13,381

 
11,193

 
6,720

General and administrative
4,441

 
4,073

 
3,562

Taxes, other than income taxes
403

 
353

 
312

Loss on sale of assets
4,795

 

 

Total operating costs and expenses
100,969

 
187,813

 
148,097

Operating income
$
4,728

 
$
20,577

 
$
16,472

(1) 
Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 19Reporting Segments to the accompanying consolidated financial statements.

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Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Revenues. Processing & Logistics segment revenues were $105.7 million for the year ended December 31, 2015, compared to $208.4 million for the year ended December 31, 2014, which represents a $102.7 million, or 49%, decrease in segment revenues. The decrease in segment revenues was primarily due to a $101.4 million decrease in the sales of natural gas, NGLs, and crude oil driven by a 58% decrease in NGL prices and lower volumes processed, and a $1.3 million decrease in processing and other revenues driven by lower processing fees at TMID due to decreased volumes processed under a large, fee-based contract, partially offset by increased revenue at Water Solutions, including water transportation services and revenue associated with a contract to construct a water pipeline for a customer during the year ended December 31, 2015. Prior to its consolidation in May 2014, TEP's investment in Water Solutions was accounted for under the equity method of accounting and as a result TEP recognized no revenues from Water Solutions for the period from January 1, 2014 to May 13, 2014.
Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $101.0 million for the year ended December 31, 2015 compared to $187.8 million for the year ended December 31, 2014, which represents a decrease of $86.8 million, or 46%. The decrease in operating costs and expenses was driven by a decrease of $95.8 million in cost of sales, primarily due to decreased NGL prices and volumes processed as discussed above. The decrease in cost of sales was partially offset by $4.8 million of non-cash losses recognized on the sale of compressor and other assets in 2015, and overall increases in the cost of transportation services, operations and maintenance costs, depreciation and amortization, and general and administrative costs, all primarily driven by the costs associated with Water Solutions, which was consolidated in May 2014.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Revenues. Processing & Logistics segment revenues were $208.4 million for the year ended December 31, 2014, compared to $164.6 million for the year ended December 31, 2013, which represents a $43.8 million, or 27%increase in segment revenues. The increase in segment revenues was primarily due to a $23.6 million increase in sales of natural gas, NGLs, and crude oil driven by increased volumes processed partially offset by a 7% decrease in average NGL prices, a $20.2 million increase in processing fees driven by the conversion of two significant customers from percent of proceeds or keep whole processing contracts to fee-based processing contracts and revenue of $5.0 million from Water Solutions, which was consolidated in May 2014.
Operating costs and expenses. Operating costs and expenses in the Processing & Logistics segment were $187.8 million for the year ended December 31, 2014 compared to $148.1 million for the year ended December 31, 2013, which represents an increase of $39.7 million, or 27%. The increase in operating costs and expenses was driven by an increase of $31.7 million in cost of sales, primarily driven by an increase in NGL producer settlements as a result of increased volumes processed under contracts converted to fee-based as discussed above and an overall increase in volumes processed, partially offset by decreased NGL prices. The overall increases in the cost of transportation services, operations and maintenance costs, depreciation and amortization, and general and administrative costs are all primarily driven by the costs associated with Water Solutions, which was consolidated in May 2014.
Liquidity and Capital Resources Overview
Our primary sources of liquidity for the year ended December 31, 2015 were proceeds from the completion of the Offering, cash generated from our operations, and borrowings under our revolving credit facilities. We expect our sources of liquidity in the future to include cash generated from our operations and borrowing capacity available under our revolving credit facilities.
We believe that cash on hand, cash generated from operations, and availability under our revolving credit facilities will be adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements, and our planned cash distributions to shareholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of borrowings under TEP's revolving credit facility and issuances of debt and/or equity securities at TEP.
Our total liquidity as of December 31, 2015 and 2014 was as follows:
 
December 31, 2015
 
December 31, 2014
 
(in thousands)
Cash on hand
$
2,234

 
$
867

 
 
 
 
Total capacity under the TEP revolving credit facility
1,100,000

 
850,000

Less: Outstanding borrowings under the TEP revolving credit facility
(753,000
)
 
(559,000
)
Available capacity under the TEP revolving credit facility
347,000

 
291,000

Total capacity under Tallgrass Equity revolving credit facility
$
150,000

 
$

Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility
$
(148,000
)
 

Available capacity under the Tallgrass Equity revolving credit facility
$
2,000

 

Total liquidity
$
351,234

 
$
291,867

TEP Revolving Credit Facility
TEP has a senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders (the "Credit Agreement") which will mature on May 17, 2018. On June 25, 2014, TEP and certain of its subsidiaries entered into Amendment No. 1 to the Credit Agreement. On November 24, 2015, TEP and certain of its subsidiaries entered into Amendment No. 2 to the Credit Agreement, which modified certain provisions of the Credit Agreement to increase the amount of the revolving credit facility from $850 million to $1.1 billion and provide for a committed accordion in an amount up to an additional $400 million, subject to the satisfaction of certain other conditions. The revolving credit facility includes a $75 million sublimit for letters of credit and a $60 million sublimit for swing line loans. Effective January 4, 2016, in conjunction with the acquisition of an additional 31.3% interest in Pony Express, TEP exercised the committed accordion feature to increase the total capacity of the revolving credit facility to $1.5 billion. As of January 31, 2016, TEP had approximately $1.2 billion of outstanding borrowings under its revolving credit facility.
The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP's ability (as well as the ability of its restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of TEP's business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of December 31, 2015, TEP was in compliance with the covenants required under the revolving credit facility.
The unused portion of the revolving credit facility is subject to a commitment fee, which which ranges from 0.300% to 0.500%, based on our total leverage ratio. As of December 31, 2015, the weighted average interest rate on outstanding borrowings was 2.08%.
Tallgrass Equity Revolving Credit Facility
In connection with the Offering, Tallgrass Equity entered into a new $150 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 12, 2020. The Tallgrass Equity credit facility includes a $10 million sublimit for letters of credit and a $10 million sublimit for swing line loans. The Tallgrass Equity revolving credit facility may be used (i) to pay transaction costs and any fees and expenses incurred in connection with the revolving credit facility and certain transactions relating to the Offering, (ii) to fund the purchase of the Acquired TEP Units and (iii) for general company purposes, including distributions. The Tallgrass Equity revolving credit facility also contains an accordion feature whereby Tallgrass Equity can increase the size of the credit facility to an aggregate of $200 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. In addition, Tallgrass Equity is required to maintain a total leverage ratio of not more than 3.00 to 1.00. As of December 31, 2015, Tallgrass Equity was in compliance with the covenants required under the revolving credit facility.
Upon the close of the Offering, Tallgrass Equity had $150 million in outstanding borrowings under the credit facility, of which $3 million was subsequently repaid using proceeds from the Offering retained from the distribution of Excess Proceeds to the Exchange Right Holders for short term working capital needs, which will ultimately be distributed to the Exchange Right Holders to the extent not used to pay offering expenses and other transaction costs. An additional $1.0 million was borrowed during the year ended December 31, 2015, leaving $2.0 million in remaining capacity available for future borrowings or letter of credit issuances as of December 31, 2015. The initial borrowings under the credit facility were used to fund a portion of the purchase of the Acquired TEP Units and to pay origination and arrangement fees associated with the new revolving credit facility and transaction costs associated with the Offering. Tallgrass Equity’s obligations under the revolving credit facility are secured by a first priority lien on all of the present and after acquired equity interests held by Tallgrass Equity in TEP GP and TEP. Borrowings under the credit facility bear interest, at Tallgrass Equity’s option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin is 1.50%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is 2.50%.
The unused portion of the revolving credit facility is subject to a commitment fee of 0.50% per annum on the daily unused amount of the revolving credit commitment reduced by the face amount of the letters of credit issued and outstanding. As of December 31, 2015, the weighted average interest rate on outstanding borrowings was 2.84%.
TEP Public Offerings
On February 27, 2015, TEP sold 10,000,000 common units representing limited partner interests in an underwritten public offering at a price of $50.82 per unit, or $49.29 per unit net of the underwriter's discount, for net proceeds of approximately $492.4 million after deducting the underwriter's discount and offering expenses. TEP used the net proceeds from the offering to fund a portion of the consideration for the acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4Acquisitions. Pursuant to the underwriters' option to purchase additional units, TEP sold an additional 1,200,000 common units representing limited partner interests to the underwriters at a price of $50.82 per unit, or $49.29 per unit net of the underwriter’s discount, for net proceeds of approximately $59.3 million after deducting the underwriter’s discount and offering expenses. TEP used the net proceeds from this additional purchase of common units to reduce borrowings under its revolving credit facility, a portion of which were used to fund the March 2015 acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4Acquisitions    .
TEP Equity Distribution Agreement
On October 31, 2014, TEP entered into an equity distribution agreement pursuant to which TEP may sell from time to time through a group of managers, as its sales agents, common units representing limited partner interests having an aggregate offering price of up to $200 million, referred to as TEP's At-The-Market Offering Program, or the TEP ATM Program. On May 13, 2015, TEP amended the agreement to reduce the aggregate offering price to $100.2 million in order to account for follow-on equity offerings under TEP's S-3 shelf registration statement. Sales of the common units, if any, will be made by means of ordinary brokers’ transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by TEP and one or more of the managers. TEP intends to use the net proceeds from any sale of the units for general partnership purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
During the year ended December 31, 2015, TEP issued and sold 65,744 common units with a weighted average sales price of $45.58 per unit under its equity distribution agreement for net proceeds of approximately $3.0 million (net of approximately $30,000 in commissions and professional service expenses). TEP used the net proceeds for general partnership purposes. At December 31, 2015, approximately $95.9 million in aggregate offering price remained available to be issued and sold under the equity distribution agreement.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. While various other factors may impact our working capital requirements from period to period, our working capital requirements have typically been, and we expect will continue to be, driven by changes in accounts receivable and accounts payable. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, and the level of spending for capital expenditures. Changes in the market prices of energy commodities, primarily NGLs, that we buy and sell in the normal course of business can also impact the timing of changes in accounts receivable and accounts payable.

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As of December 31, 2015, we had a working capital deficit of $11.2 million compared to a working capital surplus of $35.7 million at December 31, 2014, which represents a decrease in working capital of $46.9 million. The overall decrease in working capital was primarily attributable to the following:
a decrease of $73.4 million in receivables from related parties due to the utilization of the Pony Express cash balance swept to TD under the cash management agreement;
an increase in deferred revenue of $21.0 million from deficiency payments collected by Pony Express; and
an increase in accrued taxes of $9.9 million as a result of placing the mainline portion of the Pony Express System into commercial service in October 2014.
These working capital decreases were partially offset by:
a decrease of $40.1 million in accounts payable, primarily driven by the timing of project invoices and payment of contractor retainages related to the construction of the Pony Express lateral in Northeast Colorado placed in service in April 2015 and lower producer settlements at TMID; and
an increase of $18.0 million in accounts receivable primarily driven by the start of commercial operations at the Pony Express lateral in Northeast Colorado and the activation of the Hiland Pipeline Company joint tariff at Pony Express.
A material adverse change in operations, available financing under our revolving credit facility, or available financing from the equity or debt capital markets could impact our ability to fund our requirements for liquidity and capital resources in the future.
Cash Flows
The following table and discussion presents a summary of our cash flow for the periods indicated:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
285,859

 
$
79,444

 
$
82,482

Investing activities
$
(845,270
)
 
$
(1,102,729
)
 
$
(347,610
)
Financing activities
$
560,778

 
$
1,024,152

 
$
265,128

Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Operating Activities. Cash flows provided by operating activities were $285.9 million and $79.4 million for the years ended December 31, 2015 and 2014, respectively. The increase in net cash flows provided by operating activities of $206.4 million was primarily driven by the increase in operating results and a net increase in cash inflows from changes in working capital, primarily driven by a $31.7 million decrease in net cash outflows from accounts payable and accrued liabilities due to increased property tax accruals and related party payables and a $14.0 million increase in net cash inflows from deficiency payments received by Pony Express, partially offset by a decrease in net cash inflows of $15.2 million from accounts receivable, due to increased receivables at Pony Express.
Investing Activities. Cash flows used in investing activities were $845.3 million and $1.1 billion for the years ended December 31, 2015 and 2014, respectively. During the year ended December 31, 2015, net cash used in investing activities were driven by the $700.0 million cash outflow for TEP's acquisition of an additional 33.3% membership interest in Pony Express, which allowed TD to continue funding the construction at Pony Express, including the lateral in Northeast Colorado, $75.0 million for the acquisition of Western, and capital expenditures of $65.4 million, primarily related to the construction at Pony Express, including the lateral in Northeast Colorado. During the year ended December 31, 2014, net cash used in investing activities was driven by capital expenditures of $665.7 million, primarily due to construction at Pony Express, including the lateral in Northeast Colorado, as well as the capacity expansion projects at TMID and other expansion projects at Trailblazer, cash outflows of $270.0 million associated with the related party loan to TD under the Pony Express cash management agreement, and cash outflows of $150.0 million, $27.0 million, and $7.6 million for the acquisitions of Trailblazer, Pony Express, and Water Solutions, respectively. These cash outflows were partially offset by cash inflows of $20.0 million from the return of funds deposited with Shell in support of the crude oil resale obligation of Pony Express.

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Financing Activities. Cash flows provided by financing activities were $560.8 million and $1.0 billion for the years ended December 31, 2015 and 2014, respectively. Financing cash inflows for the year ended December 31, 2015 were primarily driven by cash inflows of $1.3 billion from the issuance of TEGP Class A Shares in the Offering that closed on May 12, 2015, $554.1 million from the issuance of 11,200,000 TEP common units in a public offering which closed on February 27, 2015 and TEP common units issued under the TEP ATM Program during 2015, and $342.0 million net borrowings under the TEP and Tallgrass Equity revolving credit facilities. These financing cash inflows were partially offset by cash outflows of $953.6 million for Tallgrass Equity's acquisition of the Acquired TEP Units, a $334.1 million distribution of excess proceeds from the Offering to the Exchange Right Holders, $171.9 million for the additional Tallgrass Equity units acquired as part of the Reorganization Transactions, $99.2 million for distributions to TEP unitholders, $28.7 million in Tallgrass Equity distributions to Exchange Right Holders, $25.1 million for distributions to noncontrolling interests, primarily driven by Pony Express distributions to TD, $13.5 million for distributions to the TEGP Predecessor Member associated with the period prior to the closing of the Offering on May 12, 2015, $10.4 million for distributions to TEGP Class A shareholders, and $7.5 million for distributions to the TEP GP Predecessor Member associated with the period prior to the closing of the Offering on May 12, 2015. Cash flows provided by financing activities for the year ended December 31, 2014 were primarily driven by the proceeds from net borrowings under the TEP revolving credit facility of $424.0 million, net proceeds of $320.4 million from the issuance of 8,050,000 TEP common units in a public offering which closed on July 25, 2014 and TEP common units issued under the TEP ATM Program in the fourth quarter of 2014, net contributions from the TEGP Predecessor Member of $279.5 million, and a contribution from TD of $27.5 million representing the difference between the carrying amount of the Replacement Gas Facilities and the proceeds received from TD. These cash inflows were partially offset by distributions to TEP unitholders of $35.5 million.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Operating Activities. Cash flows provided by operating activities were $79.4 million and $82.5 million for the years ended December 31, 2014 and 2013, respectively. The decrease in net cash flows provided by operating activities of $3.0 million was primarily driven by the increase in net cash outflows for changes in working capital, primarily due to the timing of payments and a decrease in producer settlements at TMID as a result of lower NGL prices, partially offset by the increase in operating results in the year ended December 31, 2014 compared to the year ended December 31, 2013.
Investing Activities. Cash flows used in investing activities were $1.1 billion and $347.6 million for the years ended December 31, 2014 and 2013, respectively. During the year ended December 31, 2014, net cash used in investing activities was driven by capital expenditures of $665.7 million, primarily due to construction of the Pony Express System, including the lateral in Northeast Colorado, as well as the capacity expansion projects at TMID and other expansion projects at Trailblazer, cash outflows of $270.0 million associated with the related party loan to TD under the Pony Express cash management agreement, and cash outflows of $150.0 million, $27.0 million, and $7.6 million for TEP's acquisitions of Trailblazer, Pony Express, and Water Solutions, respectively. These cash outflows were partially offset by cash inflows of $20.0 million from the return of funds deposited with Shell in support of the crude oil resale obligation of Pony Express. During the year ended December 31, 2013, net cash used in investing activities was driven by $346.0 million in capital expenditures, consisting primarily of spending on the conversion and construction of the Pony Express System and capacity expansion and efficiency upgrade projects at TMID, and to a lesser extent, capital expenditures at TIGT.
Financing Activities. Cash flows provided by financing activities were $1.0 billion and $265.1 million for the years ended December 31, 2014 and 2013, respectively. Financing cash inflows for the year ended December 31, 2014 were primarily driven by the proceeds from net borrowings under the TEP revolving credit facility of $424.0 million, net proceeds of $320.4 million from the issuance of 8,050,000 TEP common units in a public offering which closed on July 25, 2014 and TEP common units issued under the TEP ATM Program in the fourth quarter of 2014, net contributions from the TEGP Predecessor Member of $279.5 million, and a contribution from TD of $27.5 million representing the difference between the carrying amount of the Replacement Gas Facilities and the proceeds received from TD. These cash inflows were partially offset by distributions to TEP unitholders of $35.5 million. Cash flows provided by financing activities for the year ended December 31, 2013 consisted primarily of net cash inflows of $290.5 million from the completion of TEP's IPO on May 17, 2013, net contributions from the TEGP Predecessor Member of $252.2 million, and net borrowings under TEP's revolving credit facility of $135.0 million. These cash inflows were partially offset by the repayment of $400.0 million of debt assumed from TD and distributions to TEP unitholders of $9.0 million.

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Distributions
Distributions to our Class A shareholders. We distribute 100% of our available cash at the end of each quarter to Class A shareholders of record beginning with the quarter ended June 30, 2015. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Our distribution for the three months ended December 31, 2015, in the amount of $0.173 per Class A share, or $8.3 million in the aggregate, was declared on January 4, 2016 and paid on February 12, 2016 to Class A shareholders of record on January 29, 2016.
Capital Requirements
The midstream energy business can be capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist, of the following:
maintenance capital expenditures, which are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements; and
expansion capital expenditures, which are cash expenditures to increase our operating income or operating capacity over the long-term. Expansion capital expenditures include acquisitions or capital improvements (such as additions to or improvements on the capital assets owned, or acquisition or construction of new capital assets).
We expect to incur approximately $27 million for capital expenditures in 2016, of which approximately $15 million is expected for expansion projects and approximately $12 million, net of anticipated reimbursements from affiliates, is expected for maintenance capital expenditures.
The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in thousands)
Maintenance capital expenditures
$
12,140

 
$
9,913

 
$
15,951

Expansion capital expenditures
155,795

 
762,073

 
422,981

Total capital expenditures incurred
$
167,935

 
$
771,986

 
$
438,932

Capital expenditures incurred represent capital expenditures paid and accrued during the period, inclusive of Pony Express capital expenditures paid by TD on behalf of Pony Express and settled via the cash management agreement. The increase in maintenance capital expenditures to $12.1 million for the year ended December 31, 2015 from $9.9 million for the year ended December 31, 2014 is primarily driven by increased maintenance capital expenditures in the Natural Gas Transportation & Logistics and Processing & Logistics segments. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. The decrease in expansion capital expenditures to $155.8 million for the year ended December 31, 2015 from $762.1 million for the year ended December 31, 2014 is primarily driven by the significant spending on the Pony Express System prior to commencement of commercial operations at the mainline portion in October 2014. Expansion capital expenditures of $155.8 million for the year ended December 31, 2015 consisted primarily of spending on the Pony Express System, including the lateral in Northeast Colorado.
The decrease in maintenance capital expenditures to $9.9 million for the year ended December 31, 2014 from $16.0 million for the year ended December 31, 2013 is primarily driven by a decrease in maintenance capital expenditures in the Natural Gas Transportation & Logistics segment due to certain compressor and pipeline integrity projects during the year ended December 31, 2013. The increase in expansion capital expenditures to $762.1 million for the year ended December 31, 2014 from $423.0 million for the year ended December 31, 2013 is primarily driven by increased expenditures associated with the conversion and construction of the mainline portion of the Pony Express System, which was placed in commercial service in October 2014, and spending on the Pony Express System, lateral in Northeast Colorado.
In addition, we invested cash in unconsolidated affiliates of $2.0 million and $1.3 million during the years ended December 31, 2014 and 2013, respectively, to fund our share of capital expansion projects. There were no investments in unconsolidated affiliates during the year ended December 31, 2015.

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We intend to make cash distributions to our Class A shareholders. Due to our cash distribution policy, we expect that we will distribute available cash to our Class A shareholders on a quarterly basis. We expect TEP to fund future capital expenditures with funds generated from its operations, borrowings under its revolving credit facility, the issuance of additional partnership units and/or the issuance of long-term debt. If these sources are not sufficient, TEP may reduce its discretionary spending.
Contractual Obligations
Following is a summary of our contractual cash obligations in future periods, representing amounts that were fixed and determinable as of December 31, 2015:
 
 
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)
 
$
901,000

 
$

 
$
753,000

 
$
148,000

 
$

Interest on debt obligations (2)
 
55,888