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xbrli:shares
utreg:acre
iso4217:USD
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tge:energy_per_duration
PART I
As used in this Annual Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TGE" and similar terms refer to Tallgrass Energy, LP, in its individual capacity or to Tallgrass Energy, LP and its consolidated subsidiaries collectively (including Tallgrass Equity, Tallgrass Energy Partners, LP and their respective subsidiaries), as the context requires. References to "Tallgrass Equity" refer to Tallgrass Equity, LLC. References to "TEP" refer to Tallgrass Energy Partners, LP. The term our "general partner" refers to Tallgrass Energy GP, LLC. References to "Tallgrass Development" or "TD" refer to Tallgrass Development, LP.
A reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8.—Financial Statements and Supplementary Data. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.
Cautionary Statement Regarding Forward-Looking Statements
This Annual Report and the documents incorporated by reference herein contain forward-looking statements concerning our operations, economic performance and financial condition. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "could," "will," "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
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whether the proposed Take-Private Merger (as defined in Item 1.—Business, "Organizational Structure;") will be consummated before the end of the second quarter of 2020 or at all;
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whether any of the conditions to the Take-Private Merger will be satisfied;
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our ability to pay dividends to our Class A shareholders, which is impacted by, among other things, our agreement pursuant to the Take-Private Merger Agreement (as defined in Item 1.—Business, "Organizational Structure;") not to pay dividends during the pendency of the transactions contemplated by the Take-Private Merger Agreement;
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our expected receipt of, and amounts of, distributions from Tallgrass Equity, which is impacted by, among other things, our agreement pursuant to the Take-Private Merger Agreement not to permit Tallgrass Equity to pay distributions on the units representing limited liability company interests in Tallgrass Equity during the pendency of the transactions contemplated by the Take-Private Merger Agreement;
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our ability to complete and integrate acquisitions, including integrating the acquisitions discussed in Item 1.—Business, "Acquisitions;"
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the demand for our services, including natural gas transportation and storage; crude oil transportation; and natural gas gathering and processing, crude oil storage and terminalling services, and water business services;
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our ability to successfully contract or re-contract our services;
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large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;
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our ability to successfully implement our business plan;
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changes in general economic conditions;
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competitive conditions in our industry;
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the effects of existing and future laws and governmental regulations;
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actions taken by governmental regulators of our assets, including the FERC;
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actions taken by third-party operators, processors and transporters;
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our ability to complete internal growth projects on time and on budget;
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the price and availability of debt and equity financing;
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the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil, natural gas, natural gas liquids, and other hydrocarbons;
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the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the price of alternative and competing fuels;
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competition from the same and alternative energy sources;
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energy efficiency and technology trends;
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operating hazards and other risks incidental to transporting, storing, and terminalling crude oil; transporting, storing, gathering and processing natural gas; and transporting, gathering and disposing of water produced in connection with hydrocarbon exploration and production activities;
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environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
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natural disasters, weather-related delays, casualty losses and other matters beyond our control;
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changes in tax laws, regulations and status;
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the effects of existing and future litigation, including litigation relating to the Take-Private Merger; and
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certain factors discussed elsewhere in this Annual Report.
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Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.
Item 1. Business
Overview
TGE is a limited partnership that owns, operates, acquires and develops midstream energy assets in North America and has elected to be treated as a corporation for U.S. federal income tax purposes.
Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity in which we directly own an approximate 63.75% membership interest as of February 12, 2020. We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations. We intend to continue to utilize the significant experience of our management team to execute our growth strategy of acquiring midstream assets, increasing utilization of our existing assets and expanding our systems through construction of additional assets.
Our reportable business segments are:
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Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facility;
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Crude Oil Transportation—the ownership and operation of FERC-regulated crude oil pipeline systems; and
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Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities; crude oil storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs.
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Our Assets
The following map shows our primary assets, which consist of natural gas transportation and storage assets; crude oil transportation assets; natural gas gathering and processing assets; crude oil storage and terminalling assets; and water business services assets. Each of these assets are described in more detail below. Connected third party refineries are also indicated on the map below.
Natural Gas Transportation Segment
Rockies Express Pipeline. We own a 75% membership interest in Rockies Express Pipeline LLC ("Rockies Express"). Rockies Express owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system with approximately 1,712 miles of transportation pipelines, including laterals, extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio (the "Rockies Express Pipeline") and consists of three zones:
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Zone 1 - 328 miles of mainline pipeline from the Meeker Hub in Northwest Colorado, across Southern Wyoming to the Cheyenne Hub in Weld County, Colorado capable of transporting 2.0 Bcf/d of natural gas from west-to-east;
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Zone 2 - 714 miles of mainline pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri capable of transporting 1.8 Bcf/d of natural gas from west-to-east; and
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Zone 3 - 643 miles of mainline pipeline from Audrain County, Missouri to Clarington, Ohio, which is bi-directional and capable of transporting 1.8 Bcf/d of natural gas from west-to-east and 2.6 Bcf/d of natural gas from east-to-west.
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For the year ended December 31, 2019, approximately 98% of Rockies Express' revenues were generated under firm fee contracts.
The following tables provide information regarding the Rockies Express Pipeline for the years ended December 31, 2019, 2018, and 2017 and as of December 31, 2019:
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Year Ended December 31,
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2019
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2018
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2017
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Approximate average daily deliveries (Bcf/d) (1)
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4.0
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4.4
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4.3
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Approximate Capacity
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Total Firm Contracted Capacity (2)
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Approximate % of Capacity Subscribed under Firm Contracts
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Weighted Average Remaining Firm Contract Life (3)
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West-to-east
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2.0 Bcf/d
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1.0 Bcf/d
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49
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%
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5 years
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East-to-west
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2.6 Bcf/d
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2.6 Bcf/d
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100
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%
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13 years
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(1)
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Reflects average total daily deliveries for the Rockies Express Pipeline, regardless of flow direction or distance traveled.
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(2)
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Reflects total capacity reserved under long-term firm fee contracts as of December 31, 2019.
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(3)
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Weighted by contracted capacity as of December 31, 2019.
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TIGT System. We own a 100% membership interest in Tallgrass Interstate Gas Transmission, LLC ("TIGT"), which owns the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system with approximately 4,580 miles of varying diameter transportation pipelines serving Wyoming, Colorado, Kansas, Missouri and Nebraska (the "TIGT System"). The TIGT System includes the Huntsman natural gas storage facility located in Cheyenne County, Nebraska. The TIGT System primarily provides transportation and storage services to on-system customers such as local distribution companies and industrial users, including ethanol plants, and irrigation and grain drying operations, which depend on the TIGT System's interconnections to their facilities to meet their demand for natural gas and a majority of whom pay FERC-approved recourse rates. For the year ended December 31, 2019, approximately 94% of the TIGT System's transportation revenue was generated from contracts with on-system customers.
Trailblazer Pipeline. We own a 100% membership interest in Trailblazer Pipeline Company LLC ("Trailblazer"), which owns the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system with approximately 465 miles of transportation pipelines, including laterals, that begins along the border of Wyoming and Colorado and extends to Beatrice, Nebraska (the "Trailblazer Pipeline"). During the year ended December 31, 2019, substantially all of the Trailblazer Pipeline's operationally available long-haul capacity was contracted under firm transportation contracts.
The following tables provide information regarding the TIGT System and Trailblazer Pipeline for the years ended December 31, 2019, 2018, and 2017 and as of December 31, 2019:
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Year Ended December 31,
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2019
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2018
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2017
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Approximate average daily deliveries (Bcf/d)
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1.3
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1.3
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1.2
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Approximate Capacity
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Total Firm Contracted Capacity (1)
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Approximate % of Capacity Subscribed under Firm Contracts
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Weighted Average Remaining Firm Contract Life (2)
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Transportation
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2.0 Bcf/d
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1.7 Bcf/d
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85
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%
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6 years
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Storage
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15.974 Bcf
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(3)
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11 Bcf
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66
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%
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4 years
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(1)
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Reflects total capacity reserved under long-term firm fee contracts, including backhaul service, as of December 31, 2019.
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(2)
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Weighted by contracted capacity as of December 31, 2019.
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(3)
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The FERC certificated working gas storage capacity.
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NatGas. We own a 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas"), which is the operator of the Rockies Express Pipeline and receives a fee from Rockies Express as compensation for its services.
Crude Oil Transportation Segment
Pony Express System. We own a 100% membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which provides crude oil transportation to customers in Wyoming, Colorado, Kansas, and the surrounding regions. Pony Express owns an approximately 870-mile crude oil pipeline commencing in both Guernsey, Wyoming and Weld County, Colorado and terminating in Cushing, Oklahoma, with delivery points at the McPherson, El Dorado and Ponca City refineries and in Cushing, Oklahoma (the "Pony Express System"). We believe the Pony Express System is positioned as a low-cost, competitive transportation system with access to Bakken Shale, DJ Basin and Powder River Basin production.
The table below sets forth certain information regarding the Pony Express System's long-haul capacity as of December 31, 2019 and for the periods indicated:
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Approximate Stated Capacity
(bbls/d) (1)
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Approximate Contractible Capacity Under Contract (1)(2)
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Weighted Average Remaining Firm Contract Life (3)
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Approximate Average Daily Throughput (bbls/d)
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Year Ended December 31,
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2019
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2018
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2017
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417,000
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80
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%
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2 years
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358,442
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336,314
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267,734
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(1)
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Includes additional capacity related to the ability to inject drag reducing agent, which is an additive that increases pipeline flow efficiency, and additional capacity related to expansion projects.
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(2)
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We are required to make no less than 10% of stated capacity available for non-contract, or "walk-up", shippers. Approximately 80% of the remaining design capacity (or available contractible capacity) is committed under contract.
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(3)
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Based on the average annual reservation capacity for each such contract's remaining life.
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Powder River Gateway. In January 2019, we completed the expansion of our existing joint venture with Silver Creek Midstream, LLC ("Silver Creek") and acquired a 51% membership interest in Powder River Gateway, LLC ("Powder River Gateway" or "PRG"). Powder River Gateway owns the (i) Powder River Express Pipeline (the "PRE Pipeline"), a 70-mile crude oil pipeline with a capacity of 90,000 barrels per day that transports crude oil from the Powder River Basin to Guernsey, Wyoming; (ii) Iron Horse Pipeline (the "Iron Horse Pipeline"), a 80-mile crude oil pipeline placed into service in May 2019 with a capacity of 100,000 barrels per day that transports crude oil from the Powder River Basin to Guernsey, Wyoming; and (iii) crude oil terminal facilities in Guernsey, Wyoming with approximately 600,000 barrels of crude oil storage.
Gathering, Processing & Terminalling Segment
Midstream Facilities. We own a 100% membership interest in Tallgrass Midstream, LLC ("TMID"), which owns and operates a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System"). TMID also owns and operates natural gas processing plants in Casper and Douglas, Wyoming and a natural gas treating facility at West Frenchie Draw, Wyoming (collectively with the Douglas Gathering System, the "Midstream Facilities"). The Casper and Douglas plants currently have combined processing capacity of approximately 190 MMcf/d. The Casper plant also has an NGL fractionator with a capacity of approximately 3,500 barrels per day. The natural gas processed and treated at these facilities primarily comes from the Wind River Basin and the Powder River Basin, both in central Wyoming. TMID also owns and operates an NGL pipeline that transports NGLs from a processing plant in Northeast Colorado to an interconnect with Overland Pass Pipeline, and an NGL pipeline that originates at our Douglas facility and interconnects with ONEOK's Bakken NGL Pipeline. Each of our NGL pipelines are supported by 10-year leases for 100% of their respective pipeline capacity, with the lease for the NGL pipeline in Northeast Colorado having commenced in October 2015, and the lease for the NGL pipeline from our Douglas facility having commenced on January 1, 2017. During the year ended December 31, 2019, approximately 12%, 54%, and 34% of TMID's Adjusted EBITDA came from firm fee, volumetric fee, and commodity sensitive contracts, respectively.
The table below sets forth certain information regarding natural gas gathering and processing at the Midstream Facilities as of December 31, 2019 and for the years ended December 31, 2019, 2018, and 2017:
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Approximate Capacity (MMcf/d)
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Approximate Average Volumes (MMcf/d)
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Year Ended December 31,
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2019
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2018
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2017
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Gathering
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75
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50
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42
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37
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(1)
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Processing
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190
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(2)
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118
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122
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109
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(1)
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Reflects approximate average gathering volumes subsequent to our acquisition of the Douglas Gathering System on June 5, 2017.
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(2)
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The West Frenchie Draw natural gas treating facility treats natural gas before it flows into the Casper and Douglas plants and therefore does not result in additional inlet capacity.
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Water Solutions. We provide water business services through our 100% membership interest in BNN Water Solutions, LLC ("Water Solutions"). Water Solutions, through its 100% membership interests in BNN Redtail, LLC ("BNN Redtail") and BNN North Dakota, LLC ("BNN North Dakota"), owns and operates a freshwater delivery and storage system and a produced water gathering and disposal system in Weld County, Colorado, a produced water disposal facility in Campbell County, Wyoming, and a produced water gathering and disposal system in North Dakota. Water Solutions is also the sole voting member and owns a 75.19% membership interest in BNN West Texas, LLC ("BNN West Texas"), which owns a produced water gathering and disposal system in Reeves and Reagan Counties, Texas that is operated by Water Solutions and owns a 63% membership interest in BNN Colorado Water, LLC ("BNN Colorado"), which owns a freshwater storage reservoir and supply pipeline in Weld County, Colorado. These systems are used to support third party exploration, development, and production of oil and natural gas. Water Solutions also sources treated wastewater from municipalities in Texas and recycles flowback water and other water produced in association with the production of oil and gas in Colorado. In April 2019, BNN Eastern, LLC ("BNN Eastern"), a newly formed subsidiary of Water Solutions, entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of K & H Partners LLC, a company doing business as Central Environmental Services ("CES"). CES owns and operates a salt water disposal facility located in the Utica and Marcellus area of Ohio. Subsequent to the closing of the CES acquisition on May 1, 2019, Water Solutions owns a 92.35% membership interest in BNN Eastern.
The table below sets forth certain information regarding the Water Solutions assets as of December 31, 2019 and for the years ended December 31, 2019, 2018, and 2017:
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Approximate Current Design Capacity (bbls/d)
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Approximate Average Volumes (bbls/d)
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Year Ended December 31,
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2019
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2018
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2017
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Freshwater
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400,000
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(1)
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52,133
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17,849
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69,139
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Gathering and Disposal
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329,000
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(2)
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182,292
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98,489
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31,511
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(1)
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Represents design capacity at our BNN Redtail and BNN Colorado freshwater storage reservoir and supply pipeline.
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(2)
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Represents the combined daily disposal well injection capacity for the BNN Redtail produced water gathering and disposal system acquired in December 2015, the BNN West Texas produced water gathering and disposal system which commenced operations by Water Solutions in March 2016, the BNN North Dakota produced water gathering and disposal system acquired in January 2018 and produced water disposal system acquired in November 2018, and the BNN Eastern produced water disposal system acquired in May 2019.
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Terminals. We provide crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals"). Terminals owns and operates several assets providing storage capacity and additional injection points for the Pony Express System, including the crude oil terminal near Sterling, Colorado with approximately 1.5 million bbls of storage capacity (the "Sterling Terminal"), the crude oil terminal in Weld County, Colorado with four truck unloading skids capable of receiving up to 42,000 bbls per day (the "Buckingham Terminal"), the crude oil terminal in the Central Kansas Uplift that can deliver upward of 20,000 bbls per day into the Pony Express System (the "Natoma Terminal"), and the crude oil terminal in Platteville, Colorado placed into service in August 2019 (the "Grasslands Terminal"), which has storage capacity of 300,000 bbls and connects to an extension of the Pony Express System originating in Platteville, Colorado (the "Platteville Extension"), enabling Pony Express to batch multiple common streams out of the Grasslands Terminal. Terminals also owns an approximate 60% membership interest in Deeprock Development, LLC ("Deeprock Development"), which owns crude oil terminals in Cushing, Oklahoma with approximately 4.0 million bbls of storage capacity (the "Cushing Terminal") and a 51% membership interest in the Pawnee, Colorado crude oil terminal ("Pawnee Terminal") with approximately 300,000 bbls of storage capacity.
Stanchion. We own a 100% membership interest in Stanchion Energy, LLC ("Stanchion"), which engages in the marketing of crude oil. Stanchion currently consists of three of our employees who primarily engage in the purchase and sale of crude oil.
Major Customers
For the year ended December 31, 2019, Continental Resources, Inc. accounted for approximately 10% of our revenues on a consolidated basis. The loss of this customer could have a material adverse effect on our financial results.
Organizational Structure
Our 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.
In March 2019, pursuant to the terms of a Purchase Agreement dated January 30, 2019 (the "Purchase Agreement"), entered into among acquisition vehicles controlled by affiliates of Blackstone Infrastructure Partners ("BIP" and, such acquisition vehicles controlled by BIP, collectively, the "March 2019 Acquirors"), affiliates of Kelso & Co. ("Kelso"), affiliates of The Energy & Minerals Group ("EMG"), Tallgrass KC, LLC, an entity owned by certain current and former members of our management ("Tallgrass KC"), and the other sellers named therein (collectively, the "Sellers"), the March 2019 Acquirors acquired from the Sellers (i) 100% of the membership interests in our general partner, (ii) 21,751,018 Class A shares representing limited partner interests ("Class A shares") in us, (iii) 100,655,121 units representing limited liability company interests in Tallgrass Equity ("TE Units"), and (iv) 100,655,121 Class B shares representing limited partner interests ("Class B shares") in us, in exchange for aggregate consideration of approximately $3.2 billion in cash, which was paid to the Sellers (the "March 2019 Blackstone Acquisition").
As a result of the March 2019 Blackstone Acquisition, BIP effectively controls our business and affairs through the exercise of the rights of the sole member of our general partner. Additionally, the March 2019 Acquirors, Prairie Secondary Acquiror LP, a Delaware limited partnership ("Prairie Secondary Acquiror 1"), and Prairie Secondary Acquiror E LP, a Delaware limited partnership ("Prairie Secondary Acquiror 2" and, together with Prairie Secondary Acquiror 1 and the March 2019 Acquirors, the "Sponsor Entities"), each of which are also controlled by BIP, collectively held an approximate 44.1% economic interest in us as of December 31, 2019.
On December 16, 2019, we and our general partner entered into a definitive Agreement and Plan of Merger (the "Take-Private Merger Agreement") with Prairie Private Acquiror LP, a Delaware limited partnership ("Buyer"), and Prairie Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of Buyer ("Buyer Sub"). Buyer is an affiliate of the Sponsor Entities. Pursuant to the Take-Private Merger Agreement and subject to the satisfaction or waiver of certain conditions therein, Buyer will merge with and into TGE, with TGE surviving the merger and continuing to exist as a Delaware limited partnership (the "Take-Private Merger"). At the effective time of the Take-Private Merger (the "Effective Time"), each issued and outstanding Class A share other than the Class A shares owned by the Sponsor Entities and certain of their permitted transferees, will be converted into the right to receive $22.45 per Class A share in cash without any interest thereon. Through the Take-Private Merger, the Sponsor Entities and the limited partners of the Buyer immediately prior to the Effective Time will become the owners of all of the outstanding Class A shares and the Class A shares will cease to be publicly traded upon closing of the Take-Private Merger. Assuming timely satisfaction of the closing conditions under the Take-Private Merger Agreement, including approval by our shareholders, the Take-Private Merger is targeted to close in the second quarter of 2020.
The holders of our outstanding Class B shares, which we refer to as the Exchange Right Holders, own an equivalent number of TE Units. The Exchange Right Holders are entitled to exercise the right to exchange their TE 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 TE Unit exchanged. As of February 12, 2020, the Exchange Right Holders consist of the Sponsor Entities and certain current and former members of our management.
While we are structured as a limited partnership, (i) we have elected to be treated as a corporation for U.S. federal income tax purposes, (ii) neither our general partner nor the holders of our Class B shares are entitled to receive any dividends from us, and (iii) our capital structure does not include incentive distribution rights. Therefore, our dividends will be made exclusively to holders of 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.
The chart below shows our organizational structure as of February 12, 2020 in a summary format.
Previous Organizational Structure
We were initially formed in 2015 as part of a reorganization involving entities that were previously controlled by Tallgrass Equity to effect our initial public offering on May 12, 2015 (the "TGE IPO"). As of the closing of the TGE IPO in May 2015, our sole cash-generating asset was a controlling membership interest in Tallgrass Equity and Tallgrass Equity's sole cash-generating assets consisted of direct and indirect partnership interests in TEP, which was a publicly traded limited partnership at the time. Prior to the March 2019 Blackstone Acquisition described above, the sole member of our general partner was Tallgrass Energy Holdings, LLC ("Tallgrass Energy Holdings"), which was primarily owned by Kelso, EMG and Tallgrass KC. Tallgrass Energy Holdings effectively controlled our business and affairs through the exercise of its rights as the sole member of our general partner until the closing of the March 2019 Blackstone Acquisition.
Prior to the TD Merger discussed below, Tallgrass Energy Holdings was the general partner of Tallgrass Development. Historically, TEP acquired a number of its assets from Tallgrass Development. In connection with TEP's initial public offering in May 2013 (the "TEP IPO"), Tallgrass Development contributed to TEP 100% of the membership interests in TIGT and TMID. Following the TEP IPO, TEP acquired the following additional assets from Tallgrass Development: (1) in April 2014, a 100% membership interest in Trailblazer, (2) in four separate transactions, the most recent of which was effective on February 1, 2018, a 100% membership interest in Pony Express, (3) in January 2017, a 100% membership interest in NatGas and Terminals, (4) in March 2017, a 24.99% membership interest in Rockies Express, and (5) effective February 1, 2018, a 100% membership interest in Tallgrass Operations, LLC, which owned certain administrative assets consisting primarily of information technology assets. In addition, in May 2016 Tallgrass Development assigned to TEP its right to purchase a 25% membership interest in Rockies Express from a unit of Sempra U.S. Gas and Power ("Sempra") pursuant to the purchase agreement originally entered into between Tallgrass Development's wholly-owned subsidiary and Sempra in March 2016.
On February 7, 2018, Tallgrass Development merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity (the "TD Merger"). As a result of the TD Merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Equity issued 27,554,785 TGE Class B shares and TE Units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of Tallgrass Development.
On March 26, 2018, we entered into an Agreement and Plan of Merger (the "TEP Merger Agreement") with Tallgrass Equity, Tallgrass MLP GP, LLC, a Delaware limited liability company and the general partner of TEP ("TEP GP"), and Razor Merger Sub, LLC, a Delaware limited liability company. The merger transaction contemplated by the TEP Merger Agreement (the "TEP Merger") was completed effective June 30, 2018, and as a result, 47,693,097 TEP common units held by the public were converted into the right to receive Class A shares of TGE at an exchange ratio of 2.0 Class A shares for each outstanding TEP common unit, TEP's incentive distribution rights were cancelled, TEP's common units ceased being publicly traded, and 100% of TEP's equity interests are now owned by Tallgrass Equity and its subsidiaries.
Acquisitions
The acquisition of midstream assets and businesses that are strategic and complementary to our existing operations constitutes an integral component of our business strategy and growth objectives. Such assets and businesses include natural gas transportation and storage; crude oil transportation; and natural gas gathering and processing, crude oil storage and terminalling services, and water business service assets and other energy assets that have characteristics and provide opportunities similar to our existing business lines and enable us to leverage our assets, knowledge and skill sets. Below are summaries of significant acquisitions completed in 2019, as discussed in Note 3 – Acquisitions and Dispositions.
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Acquisition of CES. In April 2019, we entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of CES. On May 1, 2019, the acquisition closed for cash consideration of approximately $52 million paid at closing, and the issuance of a 7.65% membership interest in BNN Eastern to one of the sellers in the transaction.
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Joint Venture with Silver Creek. In February 2018, we entered into an agreement with Silver Creek to form a joint venture to own the Iron Horse Pipeline. Effective January 1, 2019, the joint venture between us and Silver Creek was expanded through contributions to Powder River Gateway. The expanded joint venture operates under the name Powder River Gateway, LLC and owns the Iron Horse Pipeline, the Powder River Express Pipeline, and crude oil terminal facilities in Guernsey, Wyoming. Effective January 1, 2019, we own a 51% membership interest in Powder River Gateway and operate the joint venture.
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Growth Projects
Our extensive asset base and our relationships with customers provide us with opportunities for internal growth through the construction of additional assets to build upon our existing asset base. The following growth projects are currently ongoing and will extend throughout 2020 and beyond:
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Cheyenne Connector Pipeline. In November 2019, we entered into a joint venture agreement with DCP Cheyenne Connector, LLC ("DCP") to jointly-own Cheyenne Connector, LLC ("Cheyenne Connector"). As of December 31, 2019, we own a 50% membership interest in Cheyenne Connector, which is developing the Cheyenne Connector Pipeline, a new FERC-regulated pipeline lateral in Northeast Colorado that will transport natural gas from the DJ Basin in Weld County to the Rockies Express Pipeline's Cheyenne Hub, discussed below. The Cheyenne Connector Pipeline will be a large-diameter pipeline approximately 70 miles long, with an initial capacity of at least 600 mmcf/d. The Cheyenne Connector Pipeline is expected to be in-service in the first half of 2020.
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•
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Cheyenne Hub Enhancement Project. The Rockies Express Pipeline's Cheyenne Hub is an existing natural gas facility owned and operated by Rockies Express Pipeline in northern Weld County. At the Cheyenne Hub, the existing Rockies Express Pipeline intersects and/or connects with numerous other natural gas pipelines. The Cheyenne Hub Enhancement Project consists of modifications to the Rockies Express Pipeline's Cheyenne Hub to accommodate firm receipt and delivery interconnectivity among multiple natural gas pipelines with various operating pressures and will provide customers significant diversity in terms of market access. The first phase of the Cheyenne Hub Enhancement Project is expected to be in-service in the first half of 2020.
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Plaquemines Liquids Terminal. In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly-own Plaquemines Liquids Terminal, LLC ("PLT"). PLT was formed with the intention of developing storage and terminalling facilities for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers ("VLCC") vessels for international delivery on a site located on the Mississippi River in Plaquemines Parish, Louisiana. We made an initial cash contribution of $30.7 million in exchange for a 100% preferred membership interest and a 80% common membership interest. DHIF contributed any and all assets and rights related to the project in exchange for a 20% common membership interest and the right to receive certain special distributions. Also in November 2018, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT expects to construct the facilities. The project is currently under development.
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Competition
All of our businesses face strong competition for acquisitions and development of new projects from both established and start-up companies. Competition may increase the cost to acquire existing facilities or businesses and may result in fewer commitments and lower returns for new pipelines or other development projects. Our competitors may have greater financial resources than we possess or may be willing to accept lower returns or greater risks. Competition differs by region and by the nature of the business or the project involved.
Additionally, pending and future construction projects, if and when brought online, may also compete with our natural gas transportation, storage, gathering and processing services, crude oil transportation, storage, gathering and terminalling services, and water transportation, gathering, recycling and disposal services. Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users, including electricity, coal, other liquid fuels and alternative energy. Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a reduction in demand for our services. Moreover, several other factors may influence the demand for natural gas and crude oil which in turn influences the demand for our services, including price changes, the availability of natural gas and crude oil and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, weather, and the ability to convert to alternative fuels.
Our principal competitors in our natural gas transportation and storage business include companies that own major natural gas pipelines, such as Enbridge Inc., Kinder Morgan Inc., Northern Natural Gas Company, Southern Star Central Gas Pipeline, Inc., Energy Transfer LP, and The Williams Companies Inc., some of whom also have existing storage facilities connected to their transportation systems that compete with our storage facilities.
Pony Express encounters competition in the crude oil transportation business. A number of pipeline companies compete with Pony Express to service takeaway volumes in markets that Pony Express currently serves, including pipelines owned and operated by Sinclair Oil Corporation, Plains All American Pipeline, L.P., Suncor Energy Inc., Magellan Midstream Partners, L.P., Occidental Petroleum Corporation, NGL Energy Partners LP, Energy Transfer LP, and Enbridge Inc. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil price benchmarks (West Texas Intermediate Crude and Brent Crude), and with refineries that source barrels in areas served by Pony Express.
We also experience competition in the natural gas processing business. Our principal competitors for processing business include other facilities that service its supply areas, such as the other regional processing and treating facilities in the greater Powder River Basin which include plants owned and operated by Kinder Morgan, Inc., ONEOK, Inc., Western Midstream Partners, LP, Crestwood Equity Partners, LP, and Meritage Midstream Services II, LLC. In addition, due to the competitive nature of the liquids-rich plays in the Wind River Basin and Powder River Basin, it is possible that one of our competitors could build additional processing facilities that service our supply areas. In addition, Terminals encounters competition in the crude oil storage and terminalling business from facilities owned by Magellan Midstream Partners, L.P., NGL Energy Partners LP, Plains All American, L.P., Blueknight Energy Partners, L.P., Energy Transfer, LP, and Enbridge Inc. Further, we experience competition in the water business services. Our principal competitors in such business are other midstream companies, such as NGL Energy Partners LP, Rattler Midstream LP, and Select Energy Services, Inc. who compete with Water Solutions in areas of concentrated production activity.
Regulatory Environment
Federal Energy Regulatory Commission
We provide open-access interstate transportation service on our natural gas transportation systems pursuant to tariffs approved by the FERC. As interstate transportation and storage systems, the rates, terms of service and continued operations of the Rockies Express Pipeline, the TIGT System and the Trailblazer Pipeline are subject to regulation by the FERC under, among other statutes, the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EPAct 2005. The rates and terms of service on the Pony Express System, the PRE Pipeline, and the Iron Horse Pipeline are subject to regulation by the FERC under, among other statutes, the Interstate Commerce Act, or the ICA, and the Energy Policy Act of 1992. We provide interstate transportation service on the Pony Express System, the PRE Pipeline and the Iron Horse Pipeline pursuant to tariffs on file with the FERC. Our NGL pipeline that interconnects with Overland Pass Pipeline is leased to a third party who has obtained a waiver for itself from the FERC from the tariff, filing and reporting requirements of the ICA, and our NGL pipeline that interconnects with ONEOK's Bakken NGL Pipeline is leased to a third party who is obligated to operate the leased pipeline in conformance with the ICA as a FERC regulated NGL pipeline.
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 exercises its ratemaking authority by applying cost-of-service principles to limit the maximum and minimum levels of tariff-based recourse rates; however, it also allows for discounted or negotiated rates as an alternative to cost-based rates and may grant market-based rates in certain circumstances. In addition, FERC regulations also restrict interstate natural gas pipelines from sharing certain transportation or customer information with marketing affiliates and require that the transmission function personnel of interstate natural gas pipelines operate independently of the marketing function personnel of the pipeline or its affiliates.
The FERC's authority over interstate crude oil pipelines is less broad than its authority over interstate natural gas pipelines and includes oversight of rates, rules and regulations for service, the form of tariffs governing service, the maintenance of accounts and records, and depreciation and amortization policies.
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) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act or practice that operates as a fraud or deceit upon any person.
These anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. EPAct 2005 also amended the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes of more than $1 million per day per violation. In connection with this enhanced civil penalty authority, the FERC issued policy statements on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines, including the disgorgement of unjust profits.
EPAct 2005 also amended the NGA to authorize the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. The FERC has taken steps to enhance its market oversight and monitoring of the natural gas industry by adopting rules that (1) require buyers and sellers of annual quantities of 2,200,000 MMBtu or more of gas in any year to report by May on the aggregate volumes of natural gas they purchased or sold at wholesale in the prior calendar year; (2) report whether they provide prices to any index publishers and, if so, whether their reporting complies with the FERC's policy statement on price reporting; and (3) increase the internet posting obligations of interstate pipelines.
In addition, the Commodity Futures Trading Commission, or CFTC, is directed under the Commodities Exchange Act, or CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of more than $1 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.
Further, the Federal Trade Commission, or FTC, has the authority under the Federal Trade Commission Act, or FTCA, and the Energy Independence and Security Act of 2007, or EISA, to regulate wholesale petroleum markets. The FTC has adopted anti-market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of more than $1 million per violation per day.
The FERC also has the authority under the ICA to regulate the interstate transportation of petroleum on common carrier pipelines, including whether a pipeline's rates or rules and regulations for service are "just and reasonable." Among other enforcement powers, the FERC can order prospective rate changes, suspend the effectiveness of rates, and order reparations for damages. In addition, the ICA imposes potential criminal liability for certain violations of the statute.
Certain Outstanding Notices Issued by the FERC
FERC Advanced Notice of Proposed Rulemaking, Revisions to Indexing Policies and Page 700 of FERC Form No. 6, Docket No. RM17-1-000
On November 2, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking, under which the FERC is proposing changes to its regulation of oil pipelines in two different areas: (1) its policies regarding the permissible scope of rate increases based on its annual issuance of changes to the generic oil pipeline index, based on specific pipelines' earnings or their specific changes to costs; and (2) the reporting requirements for page 700 of FERC Form No. 6, Annual Report of Oil Pipeline Companies. The FERC's Advanced Notice of Proposed Rulemaking does not propose specific regulations, and may be followed by a Notice of Proposed Rulemaking proposing specific regulations or a Policy Statement announcing new or changed policies. Comments have been filed with the FERC by interested parties and the proceeding is pending before the FERC.
Notice of Inquiry on FERC's Pipeline Certificate Policy Statement, PL18-1-000
On April 19, 2018, the FERC issued a Notice of Inquiry regarding whether it should revise its current policy statement on its review and authorization of natural gas pipelines under Section 7 of the Natural Gas Act. The current policy statement, "Certification of New Interstate Natural Gas Pipeline Facilities - Statement of Policy," was issued in 1999. The Notice of Inquiry requested comments in four general areas: (1) the reliance on precedent agreements to demonstrate need for a proposed project; (2) the potential exercise of eminent domain and landowner interests; (3) the FERC's evaluation of alternatives and environmental effects under the National Environmental Policy Act and the Natural Gas Act; and (4) the efficiency and effectiveness of the FERC's certificate processes. Comments have been filed by interested parties and the proceeding is pending before the FERC.
Examples of Our Dockets at the FERC
TIGT 2019 Pre-Filing Settlement
On May 1, 2019, TIGT filed with the FERC a pre-filing settlement in Docket No. RP19-423-001 that establishes, among other things, settlement rates reflecting an overall decrease to recourse rates, contract extensions for maximum recourse rate firm contracts through May 31, 2023, and a rate moratorium period through May 31, 2023. The settlement also requires that TIGT file a new NGA Section 4 general rate case on June 1, 2023, provided that TIGT has not preempted this mandatory filing requirement by filing on or before June 1, 2023 for approval of a new pre-filing settlement. The settlement also provided for contract extensions for maximum recourse rate firm contracts through May 31, 2023 and established a rate moratorium that will result in TIGT filing a new rate case or pre-filing settlement on or before June 1, 2023. TIGT's settlement was approved on November 8, 2019 in an order issued by the FERC.
Trailblazer 2018 General Rate Case Filing
On June 29, 2018, the Trailblazer Pipeline filed a general rate case with the FERC pursuant to Section 4 of the NGA in Docket No. RP18-922-000. Trailblazer and its customers reached a settlement in principle on October 2, 2019. The settlement continues the bifurcated rate treatment for Trailblazer's "Existing System" and "Expansion System" and maintains the existing fuel retainage and revenue crediting mechanisms. Shippers with firm contracts on the Existing System were given the opportunity to convert their contracts to negotiated rate agreements that would terminate no earlier than December 31, 2026. A rate moratorium will be in effect through December 31, 2025. The settlement was filed with the FERC on December 20, 2019 and is currently awaiting approval from the FERC.
Cheyenne Hub Enhancement Project
On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub which we refer to as the Cheyenne Hub Enhancement Project. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector for the Cheyenne Connector Pipeline further described below. On September 20, 2019, the FERC issued an order approving the application. A notice to proceed with construction was issued on October 8, 2019.
Cheyenne Connector Pipeline
On March 2, 2018, Cheyenne Connector submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity to construct and operate a 70-mile, 36-inch pipeline to transport natural gas from multiple gas processing plants in Weld County, Colorado to Rockies Express' Cheyenne Hub, which we refer to as the Cheyenne Connector Pipeline. On September 20, 2019, the FERC issued an order approving the application. A notice to proceed with construction was issued on October 8, 2019.
For additional information regarding our regulatory filings with the FERC, see Note 19 – Regulatory Matters.
Pipeline and Hazardous Materials Safety Administration
We are also subject to safety regulations imposed by PHMSA, including those regulations requiring us to develop and maintain integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional measures to protect pipeline segments located in areas, which are referred to as high consequence areas, or HCAs, where a leak or rupture could potentially do the most harm.
In January 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or The Pipeline Safety Act of 2011, which amended the Pipeline Safety Improvement Act of 2002, increased penalties for violations of safety laws and rules, among other matters, and may result in the imposition of more stringent regulations in the next few years. This legislation also requires the U.S. Department of Transportation to study and report to Congress on other areas of pipeline safety, including expanding the reach of the integrity management regulations beyond high consequence areas, but restricts the U.S. Department of Transportation from promulgating expanded integrity management rules during the review period and for a period following submission of its report to Congress unless the rulemaking is needed to address a present condition that poses a risk to public safety, property or the environment. PHMSA issued a final rule effective October 25, 2013 that implemented aspects of the 2011 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. PHMSA's maximum civil penalties were most recently increased in July and October, 2019. In October 2019, PHMSA also issued two final rules, effective July 1, 2020, to implement other aspects of the 2011 legislation related to the safety and integrity management of hazardous materials pipelines and onshore gas pipelines. In addition, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, or PIPES Act, reauthorized PHMSA's oil and gas pipeline programs through 2019 and gave PHMSA power to issue emergency orders upon finding an imminent hazard, required PHMSA to issue safety standards for underground natural gas storage facilities, set deadlines for conducting post-inspection briefings and making findings, required liquid pipeline operators to undertake new safety measures, and required certain updates to the PHMSA website. As of the end of 2019, PHMSA had not yet been reauthorized for funding through 2023, but PHMSA indicates that its pipeline safety functions can continue to function, subject to restrictions in an appropriations act.
PHMSA is also currently considering changes to its regulations. On December 14, 2016, PHMSA issued an interim final rule, or IFR, that addresses safety issues related to downhole facilities, including well integrity, well bore tubing, and casing at underground natural gas storage facilities. The IFR incorporates by reference two of the American Petroleum Institute's Recommended Practice standards and mandates certain reporting requirements for operators of underground natural gas storage facilities. Operators of natural gas storage facilities were given one year from January 18, 2017, the effective date of the IFR, to
implement this first set of PHMSA regulations governing underground storage fields. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule. On October 1, 2019, PHMSA finalized new hazardous liquid pipeline safety regulations, effective July 1, 2020. The rule applies to hazardous liquid gathering (including oil) pipelines, except transportation-related flow lines. Among other things, the final rule requires additional event-driven and periodic inspections, requires the use of leak detection systems on all hazardous liquid pipelines, modifies repair criteria, and requires certain pipelines to eventually accommodate in-line inspection tools.
Also, on April 8, 2016, PHMSA published a notice of proposed rule-making, or NPRM, addressing natural gas transmission and gathering lines. The proposed rule would include changes to existing integrity management requirements and would expand assessment and repair requirements to pipelines in areas with medium population densities (referred to as Moderate Consequence Areas or MCAs), along with other changes. This NPRM builds on an Advisory Bulletin PHMSA issued in May 2012, which advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for maximum allowable operating pressure, or MAOP. We are currently undertaking an extensive internal record review in view of the anticipated PHMSA annual reporting requirements. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. On October 1, 2019, PHMSA issued a final rule, effective July 1, 2020, that puts in place the first third of the regulations contemplated by the 2016 NPRM; two other phases of rulemaking are expected to address the remainder of items proposed in the 2016 NPRM. The October 2019 final rule requires the completion of periodic integrity reassessments, ordinarily required once every seven years, within six months of written notice from PHMSA; requires operators to consider and account for seismicity in identifying potential threats; requires the reporting of MAOP exceedances of gas transition pipelines; and imposes the proposed record-keeping requirements to confirm MAOP. In addition, the final rule requires operators to perform integrity assessments in MCAs and Class 3 and 4 areas (involving either high density or high consequence structures) at least once by October 1, 2033, and at least once every 10 years thereafter. The final rule also sets specific standards for pressure-relief safety devices on in-line pipeline inspection tools. At the state level, several states have also passed legislation or promulgated rulemaking dealing with pipeline safety. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures.
Pipeline Integrity Issues
The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs can have a significant impact on the costs to perform integrity testing and repairs. In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. The associated NPRM is expected in April 2020. We will continue pipeline integrity testing programs to assess and maintain the integrity of its existing and future pipelines as required by the U.S. Department of Transportation regulations. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines, which expenditures could be material.
From time to time, our pipelines may experience integrity issues. These integrity issues may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties and we may also be subject to private civil liability for such matters.
Trailblazer
Starting in 2014 Trailblazer's operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing
subscription levels or had a material adverse financial impact on us. However, Trailblazer continued performing remediation to increase and maximize its operating capacity over the long-term and spent approximately $21 million during 2018 for this pipe replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating capacity.
In connection with TEP's acquisition of Trailblazer in April 2014, TD agreed to indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline. The contractual indemnity was capped at $20 million and subject to an annual $1.5 million deductible. TEP has received the entirety of the $20 million from TD pursuant to the contractual indemnity as of December 31, 2017.
Pony Express
In connection with certain crack tool runs on the Pony Express System completed in 2015, 2016 and 2017, Pony Express completed approximately $18 million of remediation for anomalies identified on the Pony Express System associated with portions of the pipeline that were converted from natural gas to crude oil service. Remediation work was substantially complete as of March 1, 2018.
Environmental, Health and Safety Matters
General
The ownership, operation and expansion of our assets are subject to federal, state and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health. These laws and regulations can restrict or impact our business activities in many ways, such as restricting the way we can handle or dispose of our wastes, requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operations, regulating future construction activities to mitigate harm to threatened or endangered species, wetlands and migratory birds, and requiring the installation and operation of pollution control or seismic monitoring equipment. The cost of complying with these laws and regulations can be significant, and we expect to incur significant compliance costs in the future as new, more stringent requirements are adopted and implemented.
Failure to comply with existing environmental laws, regulations, permits, approvals or authorizations or to meet the requirements of new environmental laws, regulations or permits, approvals and authorizations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and/or temporary or permanent interruptions in our operations that could influence our business, financial position, results of operations and prospects. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. The costs and liabilities resulting from a failure to comply with environmental laws and regulations could negatively affect our business, financial position, results of operations and prospects. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
In addition, we have agreed to a number of conditions in our environmental permits, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where we currently operate, and would operate in the future, and we are unable to predict the effect that any such measures would have on our business, financial position, results of operations or prospects.
We are also subject to the requirements of the Occupational Health and Safety Act, or OSHA, the Pipeline Safety Act and other comparable federal and state statutes. In general, we expect that it may have to increase expenditures in the future to comply with higher industry and regulatory safety standards. Such increases in expenditures could become significant over time.
Historically, our total expenditures for environmental control measures and for remediation have not been significant in relation to our consolidated financial position or results of operations. It is reasonably likely, however, that the long-term trend in environmental legislation and regulations will eventually move towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business.
For additional information regarding Environmental, Health and Safety Matters, please read Item 1A.—Risk Factors.
Air Emissions
Our operations are subject to the federal Clean Air Act, or CAA, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require
that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions (including GHG emissions, as discussed below), obtain and strictly comply with air permits containing various emissions and operational limitations and/or install emission control equipment. We may be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.
The EPA finalized a rule, effective August 2, 2016, under the New Source Performance Standard Program, or NSPS Program, to limit methane emissions from the oil and gas and transmission sectors. The rule sets additional emissions limits for volatile organic compounds, or VOCs, and regulates methane emissions for new and modified sources in the oil and gas industry. In September 2019, the EPA proposed a rule to reconsider, rescind, and amend various requirements of the NSPS standard, including removing sources in the transmission and storage segment from the regulated source category, rescinding the NSPS (including both VOC and methane requirements) applicable to those sources, and rescinding the methane-specific requirements of the NSPS applicable to sources in the production and processing segments. Alternatively, the EPA proposes to rescind the methane requirements of the NSPS applicable to all oil and natural gas sources, without removing any sources from the source category. However, the NSPS rule currently remains in effect. The EPA also finalized a rule effective August 2, 2016 regarding the alternative criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes. EPA draft guidance issued in September 2018 clarified that this rule pertains to the oil and gas industry. Also, effective January 17, 2017, the Bureau of Land Management of the U.S. Department of the Interior, or BLM, imposed new rules to reduce venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian lands. This rule was suspended, stayed, and reinstated before the BLM issued a final rule in September 2018 that rescinds and revises many of the requirements of the 2017 rule. The revision rule is being challenged in the U.S. District Court for the Northern District of California but currently remains in effect.
Developments in GHG Regulations
Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and products produced from crude oil, are examples of GHGs. The EPA has determined that the emission of GHGs presents an endangerment to public health and the environment because emissions of such gases contribute to the warming of the Earth's atmosphere and other climatic changes. Various laws and regulations exist or are under development that seek to regulate the emission of such GHGs, including the EPA programs to control GHG emissions and state actions to develop statewide or regional programs. In recent years, the U.S. Congress has considered, but not adopted, legislation to reduce emissions of GHGs. There have also been efforts to regulate GHGs at an international level, most recently in the Paris Agreement, which was signed on April 22, 2016 by 175 countries, including the United States. The Paris Agreement will require countries to review and "represent a progression" in their intended, nationally-determined contributions, which set GHG emission reduction goals every five years beginning in 2020. However, in November 2019, the United States formally initiated its year-long withdrawal from the Paris Agreement, which will result in an effective exit as early as November 2020.
Because our operations, including our compressor stations, emit various types of GHGs, primarily methane and carbon dioxide, such new legislation or regulation could increase our costs related to operating and maintaining our facilities. Depending on the particular new law, regulation or program adopted, we could be required to incur capital expenditures for installing new emission controls on our facilities, acquire permits or other authorizations for emissions of GHGs from our facilities, acquire and surrender allowances for our GHG emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or other regulations. Similarly, while we may be able to recover some or all of such increased costs in the rates charged by our processing facilities, such recovery of costs is uncertain and may depend on the terms of our contracts with our customers. In addition, new laws, regulations, or programs adopted could also impact our customers' operations or the overall demand for fossil fuels. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects.
Regulation of Hydraulic Fracturing
A sizeable portion of the hydrocarbons we transport, process, and store comes from hydraulically fractured wells. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process typically involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state's oil and gas commission; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act, or SDWA, and has released draft permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where the EPA is the permitting authority. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to
review, a variety of environmental issues associated with hydraulic fracturing. In addition, some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Other states, including states in which we operate, have restrictions on produced water storage from hydraulic fracturing operations and the operation of produced water disposal wells. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, and in some cases, may seek to ban hydraulic fracturing entirely. Some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including temporary or permanent bans, additional permit requirements, operational restrictions and chemical disclosure obligations on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of crude oil, natural gas, and NGLs that our customers produce, and could thereby adversely affect our revenues and results of operations.
Hazardous Substances and Waste
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, nonhazardous and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of nonhazardous and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release or threatened release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or analogous state laws, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released or threatened to be released into the environment.
We also generate wastes that are subject to the Resource Conservation and Recovery Act, or RCRA, and comparable state laws. RCRA regulates both nonhazardous and hazardous solid wastes, but it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. It is possible that wastes resulting from our operations that are currently treated as non-hazardous wastes could be designated as "hazardous wastes" in the future, subjecting us to more rigorous and costly management and disposal requirements. It is also possible that federal or state regulatory agencies will adopt stricter management or disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our business, financial position, results of operations and prospects or otherwise impose limits or restrictions on our operations or those of our customers.
In some cases, we own or lease properties where hydrocarbons are being or have been handled for many years. Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the locations where these hydrocarbons and wastes have been transported for treatment or disposal. We could also have liability for releases or disposal on properties owned or leased by others. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners and operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.
Our produced water disposal operations require compliance with the Class II well standards under the federal SDWA. The SDWA imposes requirements on owners and operators of Class II wells through the EPA's Underground Injection Control program, including construction, operating, monitoring and testing, reporting and closure requirements. Our disposal wells are also subject to comparable state laws and regulations. Compliance with current and future laws and regulations regarding our produced water disposal wells may impose substantial costs and restrictions on our produced water disposal operations, as well as adversely affect demand for our produced water disposal services. State and federal regulatory agencies recently have focused on a possible connection between the operation of produced water injection wells used for oil and gas waste disposal and seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In some instances, operators of produced water injection wells in the vicinity of minor seismic events have been ordered to reduce produced water injection volumes or suspend operations. Regulatory agencies are continuing to study possible linkage between produced water injection activity and induced seismicity. These developments could result in additional regulation of produced water injection wells, such regulations could impose additional costs and restrictions on our produced water disposal operations.
Federal and State Waters
The Federal Water Pollution Control Act, also known as the Clean Water Act, or the CWA, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including petroleum products, into state waters or waters of the United States. In January 2020, the EPA and the U.S. Army Corps of Engineers adopted a rule to clarify the
meaning of the term "waters of the United States" with respect to federal jurisdiction, in direct response to a 2015 final rule that many interested parties believed expanded federal jurisdiction under the CWA. The 2015 rule was heavily litigated in federal courts at both the appellate and district court levels. It is anticipated that the 2020 rule defining "waters of the United States" will also be subject to court challenge.
Regulations promulgated pursuant to the CWA and analogous state laws require that entities that discharge into federal and/or state waters obtain National Pollutant Discharge Elimination System, or NPDES, permits and/or state permits authorizing these discharges. The CWA and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the CWA and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater. We believe that we are in substantial compliance with the CWA permitting requirements as well as the conditions imposed thereunder and that continued compliance with such existing permit conditions will not have a material effect on our results of operations.
The primary federal law related to oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the CWA and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. Spill prevention, control and countermeasure requirements of federal laws and analogous state laws require us to maintain spill prevention control and countermeasure plans. These laws also require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. Regulations promulgated pursuant to OPA further require certain facilities to maintain oil spill prevention and oil spill contingency plans. A liable "responsible party" includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.
Endangered Species
The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unlisted endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development in the affected areas.
National Environmental Policy Act
The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC or other federal approval must undergo a NEPA review. A NEPA review can create delays and increased costs that could materially adversely affect our operations.
Employee Safety
We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Seasonality
Weather generally impacts natural gas demand for power generation, heating purposes and other natural gas usages, which in turn influences the value of transportation and storage. Price volatility also affects gas prices, which in turn influences drilling and production. Peak demand for natural gas typically occurs during the winter months, caused by heating demand. Nevertheless, because a high percentage of our natural gas transportation and storage and crude oil transportation revenues are derived from firm capacity reservation fees under long-term firm fee contracts, our revenues attributable to those segments are not generally seasonal in nature. We experience some seasonality in our processing segment, as volumes at our processing facilities are slightly higher in the summer months. We also experience some seasonality in our maintenance, repair, overhaul, integrity, and other projects, as warm weather months are most conducive to efficient execution of these activities.
Title to Properties and Rights-of-Way
Our real property generally falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits, surface use agreements, or licenses from landowners or governmental authorities, permitting the use of such land for our operations. We believe that we have satisfactory title to the material portions of the land on which our pipelines and facilities are owned by us in fee title. The remainder of the land on which our pipelines and facilities are located are held by us pursuant primarily to leases, easements, rights-of-way, permits, surface use agreements or licenses between us, as grantee, and a third party, as grantor. We believe that we have satisfactory rights to all of the material parcels in which our interest derives from leases, easements, rights-of-way, permits, surface use agreements, and licenses.
Insurance
Our general partner obtains insurance coverage for us and our subsidiaries. This insurance program includes general and excess liability insurance, auto liability insurance, workers' compensation insurance, pollution, cyber security, business interruption and property and director and officer liability insurance. All insurance coverage is in amounts which management believes are reasonable and appropriate.
Employees
We are managed and operated by the board of directors and executive officers of our general partner. As of December 31, 2019, we employed approximately 800 full-time employees through Tallgrass Management, LLC ("Tallgrass Management"), which is a wholly-owned subsidiary of Tallgrass Equity.
Available Information
We make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website, www.tallgrassenergy.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC's website, www.sec.gov. Our press releases and recent presentations are also available on our website.
Item 1A. Risk Factors
Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay quarterly cash dividends on our Class A shares at the current dividend level, or pay any dividend at all, and the trading price of our Class A shares could decline.
Risk Factors Related to the Take-Private Merger
Failure to complete, or significant delays in completing, the Take-Private Merger could negatively affect the trading price of our Class A shares and our future business and financial results.
Completion of the Take-Private Merger is not assured and is subject to risks, including the risks that approval of the Take-Private Merger by our shareholders is not obtained or that other closing conditions are not satisfied. If the Take-Private Merger is not completed, or if there are significant delays in completing the Take-Private Merger, we would be subject to several risks, including the following:
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a decline in the price of our Class A shares due to the fact that the current price reflects a market assumption that the Take-Private Merger will be completed;
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we may owe the Buyer a termination fee of $70 million under the terms and conditions of the Take-Private Merger Agreement;
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we will have incurred certain significant costs relating to the Take-Private Merger; and
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the attention of our management will have been diverted to the Take-Private Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.
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Class A shareholders will not receive dividends with respect to their Class A shares during the pendency of the transactions contemplated by the Take-Private Merger Agreement.
Pursuant to the Take-Private Merger Agreement, we have agreed to not pay dividends with respect to our Class A shares and to not permit Tallgrass Equity to pay any distributions on its TE Units during the pendency of the transactions contemplated by the Take-Private Merger Agreement, in each case, without the prior written consent of Buyer. In the event the Take-Private Merger Agreement is terminated, the board of directors of our general partner will promptly fix a record date and declare and pay a dividend
to the holders of Class A shares in an amount equal to the amount of dividends that the board determines would have otherwise been paid during the pendency of the transactions contemplated by the Take-Private Merger Agreement, all in accordance with our partnership agreement.
Lawsuits have been filed against TGE and the board of directors of our general partner challenging the Take-Private Merger, and any injunctive relief or adverse judgment for monetary damages could prevent the Take-Private Merger from occurring or could materially adversely affect our business, financial condition and operating results.
As of February 7, 2020, TGE and the board of directors of our general partner are named defendants in three purported class action lawsuits brought by Class A shareholders and three lawsuits brought by Class A shareholders only on behalf of the named plaintiff, each of which have been filed in U.S. federal district court, challenging under the federal securities laws the sufficiency of the disclosures made in the preliminary proxy statement filed with the SEC on January 21, 2020 regarding the Take-Private Merger. The plaintiffs in each lawsuit seek to enjoin the defendants from proceeding with or consummating the Take-Private Merger and, to the extent that the Merger is implemented before relief is granted, the plaintiff in one of the lawsuits seeks to have the Take-Private Merger rescinded. The plaintiffs in each lawsuit also seek money damages and an award of costs and attorneys' and experts' fees. Class action lawsuits are very common in connection with acquisitions of public companies, regardless of any merits related to the underlying transaction, and additional similar lawsuits may be filed.
One of the conditions to consummating the Take-Private Merger is that no injunction or other order prohibiting or otherwise preventing the consummation of the Take-Private Merger shall have been issued by any governmental authority. Consequently, if any lawsuit is successful in obtaining an injunction preventing the parties to the Take-Private Merger Agreement from consummating the Take-Private Merger, such injunction may prevent the Take-Private Merger from being completed in the expected time frame, or at all, which will delay or prevent the holders of Class A shares from receiving the merger consideration. An adverse judgment, as well as the costs of the defense of such lawsuits and other effects of such litigation, could have a material adverse effect on our business, financial condition and operating results.
While the Take-Private Merger Agreement is in effect, we may be limited in our ability to pursue other business opportunities, and our business may be otherwise adversely affected.
Pursuant to the Take-Private Merger Agreement, we have agreed to refrain from taking certain actions with respect to our business and financial affairs pending completion of the Take-Private Merger or termination of the Take-Private Merger Agreement, including (i) certain restrictions on our ability to enter into transactions and capital projects involving costs in excess of $50 million and (ii) certain restrictions on our ability to incur indebtedness in excess of $25 million. These restrictions could be in effect for an extended period of time.
In addition to the economic costs associated with pursuing a merger, our management continues to devote substantial time and other resources to the proposed transaction and related matters, which could limit our ability to pursue other business opportunities, including potential expansion capital projects, acquisitions, joint venture activities and other transactions. If we are unable to pursue such other business opportunities, our growth prospects and the long-term strategic position of our business could be adversely affected.
It is possible that some customers, suppliers and other persons with whom we have business relationships may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with us in connection with the pending Take-Private Merger, which could negatively affect our revenues, earnings and cash available for distribution, as well as the market price of our Class A shares, regardless of whether the Take-Private Merger is completed.
Furthermore, the uncertainty surrounding the approval of the Take-Private Merger proposal may adversely affect our ability to attract and retain qualified personnel. We operate in an industry that currently experiences a high level of competition among different companies for qualified and experienced personnel. The uncertainty relating to the consummation of the Take-Private Merger may increase the risk that we could experience higher than normal rates of attrition or that we could experience increased difficulty in attracting qualified personnel or incur higher expenses to do so. High levels of attrition among the management and employee personnel necessary to operate our business or difficulties or increased expense incurred to replace any personnel who leave, could materially adversely affect our business or results of operations.
The Take-Private Merger may not be consummated even if our shareholders approve the Take-Private Merger proposal.
The Take-Private Merger Agreement contains conditions that, if not satisfied or waived, may prevent, delay or otherwise result in the Take-Private Merger not occurring, even if our shareholders have voted to approve the Take-Private Merger proposal. We cannot predict with certainty whether and when any of the conditions to the completion of the Take-Private Merger will be satisfied. In addition, the conflicts committee of the board of directors of our general partner can agree with Buyer not to consummate the Take-Private Merger even if our shareholders approve the Take-Private Merger proposal and the conditions to the closing of the Take-Private Merger are otherwise satisfied.
If the Take-Private Merger does not occur, neither we nor our shareholders will benefit from the expenses we have incurred in the pursuit of the Take-Private Merger.
The Take-Private Merger may not be completed. If the Take-Private Merger is not completed, and the reasons for such failure to complete the transaction do not obligate the Buyer to pay us a termination fee pursuant to the Take-Private Merger Agreement, we will have incurred substantial expenses for which no ultimate benefit will have been received by us. In connection with the Take-Private Merger, we have paid expenses of approximately $2.8 million through January 31, 2020 and will continue to incur expenses consisting of independent advisory, accounting and legal fees, and financial printing and other related charges, much of which will be incurred even if the Take-Private Merger is not completed. In addition, if the Take-Private Merger Agreement is terminated by the Buyer under certain circumstances specified in the Take-Private Merger Agreement, we will be required to pay a $70 million termination fee.
The Take-Private Merger is a taxable transaction for U.S. federal income tax purposes, and the U.S. federal income tax consequences to our shareholders will depend on each shareholder's particular situation.
The receipt of cash in exchange for our Class A shares in the Take-Private Merger will be a taxable transaction for U.S. federal income tax purposes. The U.S. federal income tax consequences of the Take-Private Merger, including whether a shareholder will be subject to U.S. federal income tax and, if subject to U.S. federal income tax, the applicable tax rate and the amount and character of any gain or loss recognized, will vary depending on each shareholder's particular circumstances. These circumstances include, among many others, the U.S. federal income tax classification of the shareholder, whether the shareholder is a "United States person" (as defined in the Internal Revenue Code of 1986, as amended (the "Code")) or has certain other relationships with the United States, whether the Class A shares were held as "capital assets" within the meaning of the Code, the amount of cash received, the adjusted tax basis of the Class A shares exchanged, and how long the shareholder owned the Class A shares prior to the exchange.
Risks Related to Our Business
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the quarterly cash dividend at the current dividend level, or at all, to holders of our Class A shares.
We may not have sufficient available cash each quarter to enable us to pay the quarterly cash dividend at the current dividend level or at all, including, in the event the Take-Private Merger Agreement is terminated, in respect of quarters during which the transactions contemplated by the Take-Private Merger Agreement were pending. The amount of cash we have available for dividends on our Class A shares principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
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the level of firm services we provide to customers pursuant to firm fee contracts and the volume of customer products we transport, store, process, gather, treat and dispose using our assets;
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our ability to renew or replace expiring long-term firm fee contracts with other long-term firm fee contracts;
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the creditworthiness of our customers, particularly customers who are subject to firm fee contracts;
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our ability to source, complete and integrate acquisitions;
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the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of natural gas, NGLs, crude oil and other hydrocarbons;
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the actual and anticipated future prices, and the volatility thereof, of natural gas, crude oil and other commodities;
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changes in the fees we charge for our services, including firm services and interruptible services;
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our ability to identify, develop, and complete internal growth projects or expansion capital expenditures on favorable terms to improve optimization of our current assets;
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regional, domestic and foreign supply and perceptions of supply of natural gas, crude oil and other hydrocarbons;
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the level of demand and perceptions of demand in end-user markets we directly or indirectly serve;
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applicable laws and regulations affecting our and our customers' business, including the market for natural gas, crude oil, other hydrocarbons and water, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility;
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the effect of worldwide energy conservation measures;
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prevailing economic conditions;
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the effect of seasonal variations in temperature and climate on the amount of customer products we are able to transport, store, process, gather, treat and dispose using our assets;
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the realized pricing impacts on revenues and expenses that are directly related to commodity prices;
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the level of competition from other midstream energy companies in our geographic markets;
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the level of our operating and maintenance costs;
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damage to our assets and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters or acts of terrorism;
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the relationship between natural gas and NGL prices and resulting effect on processing margins; and
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leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise.
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In addition, the actual amount of cash we will have available for dividends will depend on other factors, including:
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our ability to borrow funds and access capital markets;
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the level, timing and characterization of capital expenditures we make;
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the level of our general and administrative expenses, including reimbursements to our general partner and its affiliates, for services provided to us;
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the cost of pursuing and completing acquisitions and capital expansion projects, if any;
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our debt service requirements and other liabilities;
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fluctuations in our working capital needs;
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restrictions contained in our debt agreements;
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the amount of cash reserves established by our general partner; and
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other business risks affecting our cash levels.
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If we are not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, our financial condition, results of operations, cash flows and ability to make quarterly cash dividends to our Class A shareholders will be adversely affected.
A substantial majority of our contracts for transporting, storing, and processing our customers' products on our systems are long-term firm fee contracts with terms of various durations. For the year ended December 31, 2019, approximately 86% of our natural gas transportation and storage revenues were generated under long-term firm fee transportation and storage contracts and approximately 81% of our crude oil transportation revenues were generated under long-term firm fee transportation contracts. As of December 31, 2019, the weighted average remaining life of our long-term natural gas transportation contracts and natural gas storage contracts at TIGT and Trailblazer was approximately six years and four years, respectively, and the weighted average remaining life of our crude oil transportation contracts at Pony Express was approximately two years.
A significant amount of Rockies Express' revenue in 2018 and 2019 was generated by long-term west-to-east contracts that have expired in 2019. The re-contracting of the capacity made available from these expirations has been at lower rates than those expiring contracts and we expect the re-contracting of any remaining capacity for west-to-east transport will also be at lower rates. In addition, a significant portion of the long-term contracts for the Pony Express Pipeline expired in 2019 or will expire in 2020. As a result, we have been subject to prevailing market rates when contracting the capacity utilized under these expiring contracts.
We may be unable to maintain the long-term nature and economic structure of our current contract portfolio over time. Depending on prevailing market conditions at the time of a contract renewal, our transportation, storage and processing customers with long-term fee-based contracts may desire to enter into contracts with reduced fees, and may be unwilling to enter into long-term contracts at all.
Our ability to renew or replace our expiring contracts on terms similar to, or more attractive than, those of our existing contracts is uncertain and depends on a number of factors beyond our control, including:
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the level of existing and new competition to provide competing services to our markets;
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the macroeconomic factors affecting crude oil and natural gas economics for our current and potential customers;
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the balance of supply and demand for natural gas, crude oil and other hydrocarbons, on a short-term, seasonal and long-term basis, in the markets we directly and indirectly serve;
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the extent to which the current and potential customers in our markets are willing to provide firm fee commitments on a long-term basis;
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significant, prolonged low natural gas, crude oil, or other commodity prices, which could affect supply and demand for natural gas, crude oil and other hydrocarbons; and
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the effects of federal, state or local laws or regulations on the contracting practices of us and our customers.
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During periods of price reduction and high volatility in the commodity markets, we expect customers will generally be less likely to enter into long-term firm fee contracts, and even if they enter into long-term contracts, customers may only be willing to provide acreage dedications to our assets rather than firm fee commitments. Acreage dedications typically do not require our customers to pay us unless they utilize our assets, and they could be vulnerable to challenge in bankruptcy proceedings.
To the extent we are unable to renew or replace our existing contracts on terms that are favorable to us or successfully manage the long-term nature and economic structure of our contract profile over time, our revenues and cash flows could decline and our ability to make quarterly cash dividends to our Class A shareholders could be materially and adversely affected.
We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial condition, cash flows, and operating results.
Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders. Our long-term firm fee contracts obligate our customers to pay demand charges regardless of whether they utilize our assets, except for certain circumstances outlined in applicable customer agreements. As a result, during the term of our long-term firm fee contracts and absent an event of force majeure, our revenues will generally depend on our customers' financial condition and their ability to pay rather than upon the extent to which our customers actually utilize our assets. Periods of price reduction and high volatility in the commodity markets could impact their ability to meet their financial obligations to us. Further, our contract counterparties may not perform or adhere to existing or future contractual arrangements. To the extent one or more of our contract counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material nonpayment or nonperformance by our contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could have a material adverse impact on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders.
For example, in May 2019, EM Energy Ohio, LLC, or EM Energy, and certain of its affiliates filed for bankruptcy protection. EM Energy had a firm transportation service agreement with Rockies Express for 50,000 Dth/d through January 5, 2032. Rockies Express and EM Energy have stipulated in the bankruptcy proceeding that the termination date of the firm transportation service agreement is June 13, 2019. Following the termination, Rockies Express made a drawing equal to the outstanding face amount on the letter of credit supporting EM Energy's obligations under the firm transportation service agreement and received approximately $16.2 million in June 2019. While we intend to pursue our claim against the bankruptcy estate of EM Energy for damages of approximately $89 million, we may ultimately not recover any of these damages in the bankruptcy litigation. Further, we will attempt to remarket the capacity resulting from the termination of EM Energy's firm transportation service agreement, but any new contracts may not provide the same level of revenue we received under the terminated agreement.
In addition, Ultra Resources, Inc., or Ultra, defaulted on its firm transportation service agreement with Rockies Express in 2016 for approximately 200,000 Dth/d through November 11, 2019, and as a result, Rockies Express filed a lawsuit seeking approximately $303 million in damages and other relief. Approximately 13% of Rockies Express' revenue in 2015 was derived from the Ultra contract. In April 2016, Ultra filed for bankruptcy protection and in January 2017, Rockies Express and Ultra agreed to settle Rockies Express' claim against Ultra's bankruptcy estate. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation service agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 200,000 Dth/d at a rate of approximately $0.37/Dth, or approximately $26.8 million annually. Although the Ultra claim was ultimately settled, and on terms we view as favorable, other bankruptcy proceedings with a counterparty may not result in a favorable settlement for us. In September 2019, Ultra Petroleum Corp, the parent company of Ultra, announced it had entered into an amendment to its credit facility that, among things, established a reduced borrowing base of $1.175 billion, automatically reduced the credit facility commitment to $120 million in February 2020, eliminated all financial maintenance covenants and established maximum capital expenditures of $65 million, $10 million and $5 million for the quarters ended September 30, 2019, December 31, 2019 and quarterly thereafter. In the same announcement, Ultra Petroleum Corp. also stated it was suspending drilling activity by the end of the September 2019 and it provided a preliminary outlook for 2020 assuming no
additional drilling next year. These changes in Ultra Petroleum Corp.'s liquidity and production could potentially affect Ultra's ability to make payments under its firm transportation service agreement that only recently commenced on December 1, 2019 and result in Ultra filing for bankruptcy protection.
The procedures and policies we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. In accordance with FERC regulations and our own internal credit policies, counterparties with investment grade credit ratings are deemed able to meet their financial obligations to us without requiring credit support in the form of a letter of credit, prepayment, guarantees or other forms of credit support. Although we may require credit support from our transportation customers we deem to not be creditworthy or upon a deterioration of the financial condition of an existing customer, some customers may not comply with such requirements, especially when experiencing financial distress. To the extent our procedures and policies prove to be inadequate or we are unable to obtain credit support, our financial position and results of operations may be negatively impacted.
Some of our counterparties may be highly leveraged or have limited financial resources and are subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. As seen with the decline and volatility in crude oil prices from the second half of 2014 through the first half of 2016 and in the second half of 2018, prices for crude oil and natural gas are subject to large fluctuations in response to changes in supply and demand, market uncertainty and a variety of other factors that are beyond our control. Such volatility in commodity prices might have an impact on many of our counterparties and their ability to borrow and obtain additional capital on attractive terms, which, in turn, could have a negative impact on their ability to meet their obligations to us.
In addition, in response to concerns related to climate change, there have been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuels. For example, officials in New York state and New York City have announced their intent to divest the state and city pension funds' holdings in fossil fuel companies, and the World Bank has announced that it will no longer finance upstream oil and gas after 2019, except in "exceptional circumstances." Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our customers' business activities, operations and costs of access to capital, which, in turn, could adversely impact their ability to meet their obligations to us.
Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.
We depend on certain key customers for a significant portion of our revenues and are exposed to credit risks of these customers. The loss of or material nonpayment or nonperformance by any of these key customers could adversely affect our cash flow and results of operations.
We rely on certain key customers for a portion of revenues. For example, for the year ended December 31, 2019, Continental Resources accounted for approximately 10% of our revenues on a consolidated basis. In addition, for the year ended December 31, 2019, approximately 45% of our consolidated revenues were represented by the top ten customers on our Pony Express System. We own a 75% membership interest in Rockies Express, which is not consolidated for financial reporting purposes. Approximately 16%, 16%, 13%, and 13% respectively, of Rockies Express' total revenues for the year ended December 31, 2019 were represented by Rockies Express' four largest non-affiliated shippers, and the firm contract with Rockies Express' largest non-affiliated shipper by total revenues expired in November 2019.
We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms. For additional detail, see "—If we are not able to renew or replace expiring customer contracts at favorable rates or on a long-term basis, our financial condition, results of operations, cash flows and ability to make quarterly cash dividends to our Class A shareholders will be adversely affected."
In addition, some of these key customers may experience financial problems that could have a significant effect on their creditworthiness. For example, Rockies Express terminated its contract with its third largest non-affiliated shipper by total 2015 revenue, Ultra, in March 2016. For more detail regarding Ultra, see "—We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial condition, cash flows, and operating results."
Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. To the extent one or more of our key customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Additionally, many of our customers finance their activities through cash flow from operations, the incurrence of indebtedness or the issuance of equity. The combination of
reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers' liquidity and limit their ability to make payments or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our business, cash flows, ability to make quarterly cash dividends to our Class A shareholders, the price of our Class A shares, our results of operations and ability to conduct our business.
If we are unable to make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per share basis.
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per share basis.
The acquisition component of our strategy is based, in part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. Many factors could impair our ability to acquire additional midstream assets in the future. A material decrease in divestitures of midstream energy assets by industry participants would limit our opportunities for future acquisitions and could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders. Prior to February 7, 2018, Tallgrass Development was our primary source of acquisitions. Now that Tallgrass Development has divested its entire asset portfolio and merged out of existence, our growth through acquisitions will rely almost exclusively on buying assets or businesses from third parties.
Our future growth and ability to maintain or increase dividends will be limited if we are unable to make accretive acquisitions because, among other reasons, (i) we are unable to identify attractive acquisition opportunities, (ii) we are unable to negotiate acceptable purchase contracts, (iii) we are unable to obtain financing for these acquisitions on economically acceptable terms, (iv) we are outbid by competitors or (v) we are unable to obtain necessary governmental or third-party consents. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per share basis. For example, we completed a number of acquisitions in 2018 and 2019, including the acquisition of 100% of the outstanding membership interest of CES, an additional 25.01% membership interest in Rockies Express from Tallgrass Development, a 100% membership interest in NGL Water Solutions Bakken, LLC from NGL Energy Partners, a 51% membership interest in Pawnee Terminal from Zenith Energy, and a 38% membership interest in Deeprock North from Kinder Morgan. If certain risks or unanticipated liabilities were to arise, the desired benefits of these acquisition may not be fully realized and our future financial performance and results of operations could be negatively impacted.
Any acquisition involves potential risks, including, among other things:
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mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;
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an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities;
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an inability to successfully integrate the assets or businesses we acquire;
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the assumption of unknown liabilities for which we are not indemnified or for which its indemnity is inadequate;
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the diversion of management's and employees' attention from other business concerns;
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unforeseen difficulties operating in new geographic areas or business lines; and
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a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to finance an acquisition.
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If any acquisition eventually proves not to be accretive to our cash available for dividend per share, it could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders.
Constructing new assets subjects us to risks of project delays, cost overruns and lower-than-anticipated volumes of natural gas or crude oil once a project is completed. Our operating cash flows from our capital projects may not be immediate or meet our expectations.
One of the ways we may grow our business is by constructing additions or modifications to our existing facilities. We also may construct new facilities, either near our existing operations or in new areas. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of which are beyond our control. We may be unable to complete announced construction projects on schedule, at the budgeted cost, or at all, which could have a material adverse effect on our business and results of operations. For example, we announced
the Cheyenne Hub Enhancement Project and the Cheyenne Connector Pipeline in September 2017 and submitted applications for the FERC's issuance of a certificate of public convenience and necessity pursuant to section 7(c) of the NGA with respect to these projects in March 2018. However, the FERC did not issue an order approving the applications until September 2019. As a result, the expected in-service date of the Cheyenne Hub Enhancement Project and the Cheyenne Connector Pipeline was delayed to the first half of 2020. In addition, in June 2014, Michels Corporation, or Michels, filed a complaint and request for relief against Rockies Express as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit, and also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. In February 2017, Rockies Express and Michels resolved the claims brought by Michels in exchange for a $10 million cash payment by Rockies Express.
Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:
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denial or delay in issuing requisite regulatory approvals and/or permits, which for many of our projects includes a requirement to obtain a certificate from the FERC authorizing the project before construction can commence;
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unplanned increases in the cost of construction materials or labor;
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disruptions in transportation of modular components and/or construction materials;
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adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires, releases) out of our control that result in construction delays;
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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
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changes in market conditions impacting long lead-time projects;
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market-related increases in a project's debt or equity financing costs; and
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nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.
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These projects also involve numerous economic uncertainties and the cash flow generated from these projects may not meet expectations or project estimates. Moreover, we may not receive any material increase in operating cash flow from a project for some time or at all. For instance, we began incurring construction costs for the Iron Horse Pipeline, the Cheyenne Connector Pipeline and the Cheyenne Hub Enhancement Project shortly after these projects were announced. However, we do not receive any increases in cash flow from these projects until such projects are completed and placed in-service.
The project specifications and expectations regarding project cost, timing, asset performance, investment returns and other matters usually rely in part on the expertise of third parties such as engineers, technical experts and construction contractors. These estimates may prove to be inaccurate because of numerous operational, technological, economic and other uncertainties. We also rely in part on estimates from producers regarding the timing and volume of anticipated natural gas and crude oil production. Production estimates are subject to numerous uncertainties, nearly all of which are beyond our control. These estimates may prove to be inaccurate, and new facilities may not attract sufficient volumes to achieve our expected cash flow and investment return.
If we are unable to obtain needed capital or financing on satisfactory terms our ability to make quarterly cash dividends may be diminished or our financial leverage could increase.
In order to expand our asset base through acquisitions or capital projects, we may need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash dividends. We could be required to use cash from our operations or incur borrowings or sell additional Class A shares or other limited partner interests in order to fund our expansion capital expenditures. Using cash from operations will reduce cash available for dividends to our Class A shareholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. For example, in response to concerns related to climate change, there have been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuels. Such efforts directed at midstream companies such as ours could adversely impact our future access to capital markets. In addition, the limited partnership structure for public companies has been criticized by investors as lacking transparency and accountability as compared to publicly traded corporations, which has reduced demand for investments in publicly traded limited partnerships.
Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay quarterly cash dividends to our Class A shareholders. In addition, incurring
additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant dilution of Class A shareholders and increase the aggregate amount of cash required to maintain the then-current dividend rate, which could materially decrease our ability to pay quarterly cash dividends at the then-current dividend rate. We do not currently have any commitment with our general partner or other affiliates, including the Sponsor Entities, for them to provide any direct or indirect financial assistance to us.
The Throughput and Deficiency Agreements for the Pony Express System and some of our service agreements with respect to our water business services contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.
The Throughput and Deficiency Agreements, or TDAs, for the Pony Express System and some of our service agreements with respect to our water services business are firm fee contracts with minimum volume commitments that are designed to generate stable cash flows and minimize direct commodity price risk. Under these minimum volume commitments, our customers agree to ship a minimum volume of crude oil or to have a minimum volume of water serviced, as the case may be, over certain periods during the term of the applicable agreement.
If a customer's actual throughput volumes or volumes serviced are less than its minimum volume commitment for the applicable period, it must make a deficiency payment at the end of the applicable period based upon the difference between the minimum volume commitment and the actual amounts serviced. A customer may apply any deficiency payments it makes as a credit against payment for volumes transported or serviced by us in excess of its minimum volume commitment in future periods. Upon termination of the Pony Express TDAs, customers may continue to use any remaining deficiency credits against any volumes serviced by us for a period of six months following termination, even though such customers may no longer have a minimum volume commitment.
To the extent that a customer's actual throughput volumes or volumes serviced are above its minimum volume commitment for the applicable period, the customer may use the excess volumes to credit against future deficiency payments in subsequent periods. As of December 31, 2019, Pony Express had a cumulative net deficiency balance of $106.9 million and a cumulative shipper incremental balance of $6.0 million.
Some or all of these provisions can apply in combination with one another. As a result, in the future we may not receive any cash payments for volumes shipped or serviced by us, and we may not receive deficiency payments as a result of excess volumes shipped in prior periods. This would result in reduced revenue and cash flows to us and could have a material adverse effect on our ability to make quarterly cash dividends to our Class A shareholders.
We may not be able to compete effectively in our midstream services activities and our business is subject to the risk of a capacity overbuild of midstream energy infrastructure in the areas where we operate.
We face competition in all aspects of our business and may not be able to compete effectively against our competitors. In general, competition comes from a wide variety of players in a wide variety of contexts, including new entrants and existing players and in connection with day-to-day business, expansion capital projects, acquisitions and joint venture activities. Some of our competitors have capital resources greater than ours and control greater supplies of crude oil, natural gas or NGLs.
Our ability to renew or replace our existing contracts at rates sufficient to maintain current revenues and current cash flows could be adversely affected by the activities of our competitors. Some of our competitors have assets in closer proximity to certain hydrocarbon supplies and have available idle capacity in existing assets that may require no or minimal capital investments for use. For example, several pipelines access many of the same basins as our assets and provide transport to customers in the Rocky Mountain, Appalachian Mountain and Midwest regions of the United States, such as the Dakota Access Pipeline, Saddlehorn-Grand Mesa Pipeline and White Cliffs Pipeline that compete with the Pony Express Pipeline. Pony Express also competes with rail facilities, which can provide more delivery optionality to crude oil producers and marketers looking to capitalize on basis differentials between two primary crude oil benchmarks (West Texas Intermediate Crude and Brent Crude). Furthermore, the Sponsor Entities and their affiliates and owners are not limited in their ability to compete with us.
Our competitors may expand or construct new midstream services assets that would create additional competition for the services we provide to our customers, or our customers may develop their own facilities in lieu of using ours. A significant driver of competition in some of the markets where we operate (including, for example, the Rocky Mountain and Appalachian Mountain regions) has been the rapid development of new midstream energy infrastructure capacity in recent years. As a result, we are exposed to the risk that the areas in which we operate become overbuilt, resulting in an excess of midstream energy infrastructure capacity. For example, Phillips 66 and Bridger Pipeline LLC announced in June 2019 that they had formed a 50/50 joint venture to construct the Liberty Pipeline. Per the announcement, the Liberty Pipeline would consist of a 24-inch pipeline to provide crude oil transportation service from the Rockies and Bakken production areas to Cushing, Oklahoma, with a targeted initial service date as early as the first quarter of 2021. Once constructed, the Liberty Pipeline will directly compete with the Pony Express Pipeline. If we experience a significant capacity overbuild in one or more of the areas where we operate,
it could have a significant adverse impact on our financial position, cash flows and ability to maintain or increase dividends to our Class A shareholders. In particular, our competitors in these areas could substantially decrease the prices at which they offer their services, and we may be unable to compete effectively without also substantially lowering the price for our services. This could materially impair our cash flows and ability to make quarterly cash dividends to our Class A shareholders.
Further, natural gas as a fuel, and fuels derived from crude oil, compete with other forms of energy available to users, including electricity, coal, other fuels and alternative energy. Increased demand for such forms of energy at the expense of natural gas or fuels derived from crude oil could lead to a reduction in demand for our services.
All of these competitive pressures could make it more difficult for us to renew our existing long-term firm fee contracts when they expire or to attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas and crude oil in the markets we serve, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions decreasing demand.
Certain of the contracts on the Pony Express System contain most favored nations rights, limiting flexibility to offer certain capacity to new shippers.
As of December 31, 2019, approximately 22% of the available contractible capacity on the Pony Express System is subject to contracts that contain most favored nations rights, or MFNs, and additional contracts on the Pony Express System that begin service in May 2020 also contain MFNs. The MFNs grant a shipper the right to a rate reduction in certain instances, which effectively limits our flexibility in negotiating rates for some of the services with other shippers on the Pony Express System to avoid triggering the MFNs. Further, if we do trigger an MFN, the revenue generated by Pony Express from these contracts would be reduced, which could have a material adverse effect on our revenues, cash flow, results of operations, and our ability to make quarterly cash dividends to our Class A shareholders.
If third-party pipelines or other facilities interconnected to our systems become partially or fully unavailable, if the volumes we transport do not meet the quality requirements of such pipelines or facilities, or if claims are made against us for events that occur downstream of our interconnection with third-party facilities, our revenues and our ability to make quarterly cash dividends to our Class A shareholders could be adversely affected.
Our assets typically connect to other pipelines or facilities owned, leased and/or operated by unaffiliated third parties, such as ONEOK Bakken Pipeline, L.L.C., Whiting Petroleum, and others. For example, our Pony Express System connects to upstream joint tariff pipelines, including the Belle Fourche Pipeline owned by the True Companies (which also own and operate the Bridger Pipeline upstream of the Belle Fourche Pipeline) and the Double H Pipeline owned by Kinder Morgan, which are responsible for delivering a substantial portion of the crude oil for transportation on the Pony Express System. In addition, part of the crude oil we transport on the Pony Express System is either stored in crude oil tanks located on, or pumped over to downstream pipelines that interconnect through, the Cushing Terminal, which we do not operate.
The continuing operation of such third-party facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable to us for any number of reasons, including because of testing, turnarounds, line repair, extended unscheduled maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements, conversion to another form of commodity transportation service, cessation of operations, curtailments of receipt or deliveries due to insufficient capacity or because of damage from weather events or other operational hazards. For example, the operations of the Bridger Pipeline's Poplar System were down for approximately five months during the first half of 2015 due to a pipeline release. Bridger declared a force majeure as a result of this event and temporarily lacked the capacity to make up volumes on other lines that directly or indirectly deliver crude oil into designated origin points on the Pony Express System or the Belle Fourche Pipeline. The largest committed shipper on the Pony Express System also declared a force majeure as a result of this incident.
In addition, our interconnection with third-party facilities may result in claims being made against us for events that occur downstream of our pipelines. For example, TIGT was named as a defendant in a lawsuit for damages arising from a gas leak and home explosion that occurred in June 2014 in Finney County, Kansas. Although TIGT did not directly distribute natural gas to the home in question, the plaintiffs nonetheless alleged that TIGT committed torts and otherwise violated federal safety laws. TIGT ultimately settled such claims in March 2019 pursuant to a confidential settlement. We could be subject to similar claims in the future.
If the costs to us to access and transport on these third-party pipelines or any alternative pipelines significantly increase, if any of these pipelines or other midstream facilities become unable to receive, transport, store or process products from our assets, if the volumes we transport or process do not meet the quality requirements of such pipelines or facilities, or if claims are made against us for events that occur downstream of our interconnection with third-party facilities, our revenues and our ability to make quarterly cash dividends to our Class A shareholders could be adversely affected.
The lack of diversification of our assets and geographic locations could adversely affect our ability to make quarterly cash dividends to our Class A shareholders.
We rely on revenues generated from our assets, which are primarily located in the Rocky Mountain, Appalachian Mountain and Midwest regions of the United States. Revenues on our assets primarily depend on exploration and production activities of our customers located in these regions. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or our customers' areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in supply or demand for hydrocarbons, could have a significantly greater impact on our results of operations and cash available for dividends to our Class A shareholders than if we maintained more diverse assets and locations.
For example, our water business services are provided through a limited number of assets with a relatively high concentration in Weld County, Colorado. Thus, the growth and profitability of our water business services will be especially vulnerable to conditions and fluctuations in the local Weld County economy and subject to changes in local government regulations and priorities. In addition, a number of our other assets are also located in Colorado. Certain interest groups in Colorado generally opposed to the development of oil, natural gas and NGLs, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives aimed at significantly limiting or preventing the development of oil, natural gas and NGLs. For example, a Colorado ballot initiative, Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and natural gas development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar efforts in Colorado, if passed, could restrict oil and natural gas development in the future which could result in a reduction in demand for our services.
In April 2019, the Colorado state legislature approved and the Colorado governor signed into law, Senate Bill 19-181, which reforms exploration and production activities by the oil and gas industry in the state including, among other things, revising the mission of the Colorado Oil and Gas Conservation Commission, or COGCC, from fostering energy development in the state to instead focusing on regulating the industry in a manner that is protective of public health and safety and the environment, as well as authorizing cities and counties to regulate oil and gas operations within their jurisdiction as they do other development. The COGCC has begun the process of proposing new and amended rules at the state level pursuant to Senate Bill 19-181. The COGCC held hearings in late 2019 and has planned additional hearings and anticipated draft rule proposals in 2020. Some local communities have adopted additional restrictions for oil and gas activities pursuant to Senate Bill 19-181, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the COGCC publishes new rules in keeping with Senate Bill 19-181. While the ultimate impact of this new law is currently unknown, this law or passage or enactment of other similar legislation could have a material adverse effect on our customers in the state of Colorado, which could reduce demand for our pipeline services.
Our operations are dependent on our rights and ability to receive or renew the required permits and other approvals from governmental authorities and other third parties.
Performance of our operations requires that we obtain and maintain numerous environmental and land use permits and other approvals authorizing our business activities. A decision by a governmental authority or other third party to deny, delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke or substantially modify an existing permit or other approval, could have a material adverse effect on our ability to initiate or continue operations at the affected location or facility. Expansion of our existing operations and construction of new assets are both also predicated on securing the necessary environmental or land use permits and other approvals, which we may not receive in a timely manner or at all.
In order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time needed to develop a site or pipeline alignment. Also, obtaining or renewing required permits or other approvals is sometimes delayed or prevented due to community opposition and other factors beyond our control. For example, in connection with the development and construction of the Cheyenne Connector Pipeline, we experienced delays before ultimately obtaining the land use permit from Weld County, Colorado when certain affected landowners raised objections to our project.
The denial of a permit or other approval essential to our operations or the imposition of restrictive conditions with which it is not practicable or feasible to comply could impair or prevent our ability to develop or expand a property or right-of-way. Significant opposition to a permit or other approval by neighboring property owners, members of the public or non-governmental organizations, or other third parties or delay in the environmental review and permitting process also could impair or delay our ability to develop or expand a property or right-of-way. New legal requirements, including those related to the protection of the environment, could be adopted at the federal, state and local levels that could materially adversely affect
our operations, our cost structure or our customers' ability to use our services. Such current or future regulations could have a material adverse effect on our business and we may not be able to obtain or renew permits or other approvals in the future.
Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations.
Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy demand and lower prices for our services and increased difficulty in collecting amounts owed to us by our customers which could reduce our access to credit markets, raise the cost of such access or require us to provide additional collateral to our counterparties. Our ability to access available capacity under the TEP revolving credit facility could be impaired if one or more of our lenders fails to honor its contractual obligation to lend to us. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
The amount of cash we have available for dividends to Class A shareholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making dividends, even during periods in which we record net income.
The amount of cash we have available for dividends depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash dividends during periods when we record net losses for financial accounting purposes and may not make cash dividends during periods when we record net income for financial accounting purposes.
Our success depends on the supply and demand for natural gas and crude oil.
The success of our business is in many ways impacted by the supply and demand for natural gas and crude oil. For example, our business can be negatively impacted by sustained downturns in supply and demand for natural gas and crude oil in the markets that we and our customers serve, including reductions in our ability to renew contracts on favorable terms and to construct new infrastructure. Further, a portion of the demand for our water business services depends substantially on the level of expenditures by the oil and gas industry for the exploration, development and production of oil and natural gas reserves. These expenditures are generally dependent on the industry's view of future oil and natural gas prices and are sensitive to the industry's view of future economic growth and the resulting impact on demand for oil and natural gas. Declines, as well as anticipated declines, in oil and gas prices could also result in project modifications, delays or cancellations, general business disruptions, and delays in, or nonpayment of, amounts that are owed to us. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.
One of the major factors that will impact natural gas demand will be the potential growth of the demand for natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation rather than alternative energy sources. One of the major factors impacting domestic natural gas and crude oil supplies has been the significant growth in unconventional sources such as shale plays and the continued progression of hydraulic fracturing technology. The supply and demand for natural gas and crude oil, and therefore the future rate of growth of our business, depends on these and many other factors outside of our control, including, but not limited to:
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adverse changes in domestic laws and regulations;
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adoption of various energy efficiency and conservation measures;
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adverse changes in general global economic conditions;
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technological advancements that may drive further increases in production and reduction in costs of developing crude oil and natural gas shale plays;
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the price and availability of other forms of energy, including alternative energy which may benefit from government subsidies;
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prices for natural gas, crude oil and NGLs;
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decisions of the members of the Organization of the Petroleum Exporting Countries, or OPEC, regarding price and production controls;
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increased costs to explore for, develop, produce, gather, process and transport natural gas or crude oil;
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weather conditions, seasonal trends and hurricane disruptions;
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the nature and extent of, and changes in, governmental regulation, for example regulation of GHGs and hydraulic fracturing;
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perceptions of customers on the availability and price volatility of our services and natural gas and crude oil prices, particularly customers' perceptions on the volatility of natural gas and crude oil prices over the long-term;
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capacity and transportation service into, or out of, our markets; and
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petrochemical demand for NGLs.
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The oil and gas industry historically has experienced periodic downturns. For example, from the second half of 2014 through the first half of 2016, the oil and gas industry experienced a sustained period of decline and volatility in natural gas and crude oil prices. Throughout 2019, the industry again experienced sustained lower natural gas prices. Such volatility and decline in oil and/or natural gas prices might have an impact on our counterparties and their drilling plans. For example, in September 2019, Ultra Petroleum Corp, the parent company of Ultra, stated it was suspending drilling activity by the end of the September 2019 and it provided a preliminary outlook for 2020 assuming no additional drilling next year. Any prolonged downturns in the oil and gas industry could result in a reduction in demand for our services and could adversely affect our financial condition, results of operations and cash flows.
Any significant decrease in available supplies of hydrocarbons in our areas of operation, or redirection of existing hydrocarbon supplies to other markets, could adversely affect our business and operating results. Persistent low commodity prices could result in lower throughput volumes and reduced cash flows.
Our business is dependent on the continued availability of natural gas and crude oil production and reserves. Production from existing wells and natural gas and crude oil supply basins with access to our assets will naturally decline over time. The amount of natural gas and crude oil reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the contracted capacity and/or the volume of products utilizing our assets, our customers must continually obtain adequate supplies of natural gas and crude oil.
However, the development of additional natural gas and crude oil reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, storage, transportation and other facilities that permit natural gas and crude oil to be produced and products delivered to our facilities. In addition, low prices for natural gas and crude oil, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could have a material adverse effect on the development and production of additional reserves, as well as storage, pipeline transportation, and import and export of natural gas and crude oil supplies. The volatility and sustained lower prices for crude oil and refined products from the second half of 2014 through the first half of 2016, and for natural gas throughout 2019, led to a decline in drilling activity, production and refining of these hydrocarbons, and import levels in these areas. For example, in response to this volatility and lower prices, a number of producers in our areas of operation significantly reduced their capital budgets and drilling plans in 2015 through 2017. Similarly, in September 2019, Ultra Petroleum Corp, the parent company of Ultra, stated it was suspending drilling activity by the end of the September 2019 and it provided a preliminary outlook for 2020 assuming no additional drilling next year. These changes in Ultra Petroleum Corp's liquidity and production could potentially affect Ultra's ability to make payments under its firm transportation service agreement that only recently commenced on December 1, 2019 and result in Ultra filing for bankruptcy protection. In addition, production may fluctuate for other reasons, including, for example, in the case of crude oil, the extent to which the members of OPEC abide by agreements regarding production controls. Furthermore, competition for natural gas and crude oil supplies to serve other markets could reduce the amount of natural gas and crude oil supply available for our customers. Accordingly, to maintain or increase the contracted capacity and/or the volume of products utilizing our assets, our customers must compete with others to obtain adequate supplies of natural gas and crude oil.
If new supplies of natural gas and crude oil are not obtained to replace the natural decline in volumes from existing supply basins, if natural gas and crude oil supplies are diverted to serve other markets, if environmental regulations restrict new natural gas and crude oil drilling or if OPEC does not maintain production controls, the overall demand for services on our systems will likely decline, which could have a material adverse effect on our ability to renew or replace our current customer contracts when they expire and on our business, financial condition, results of operations and ability to make quarterly cash dividends to our Class A shareholders.
Our natural gas, crude oil and liquids operations, including the rates charged on our natural gas and crude oil pipeline systems, are subject to extensive regulation by federal, state and local regulatory authorities, which could have a material adverse effect on our business, financial condition, and results of operations.
We provide open-access interstate transportation service on our interstate natural gas transportation systems pursuant to tariffs approved by the FERC. Our interstate natural gas transportation and storage operations are regulated by the FERC, under the NGA, the NGPA, and the EPAct 2005. The Rockies Express Pipeline, the TIGT System and the Trailblazer Pipeline each operate under a tariff approved by the FERC that establishes rates and terms and conditions of service to our customers. The rates and terms of service on the Pony Express System, the PRE Pipeline and the Iron Horse Pipeline are subject to regulation
by the FERC under the ICA, and the Energy Policy Act of 1992. We provide interstate crude oil transportation service on the Pony Express System, the PRE Pipeline and the Iron Horse Pipeline pursuant to tariffs on file with the FERC. Our NGL pipeline that interconnects with Overland Pass Pipeline is leased to a third party that has obtained a FERC waiver from the tariff, filing and reporting requirements of the ICA, and our NGL pipeline that interconnects with ONEOK's Bakken NGL Pipeline is leased to a third party that is obligated to operate the leased pipeline in conformance with the ICA as a FERC-regulated NGL pipeline.
Generally, the FERC's authority over natural gas facilities extends to:
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rates, operating terms and conditions of service;
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the form of tariffs governing service;
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the types of services we may offer to our customers;
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the certification and construction of new, or the expansion of existing, facilities;
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the acquisition, extension, disposition or abandonment of facilities;
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customer creditworthiness and credit support requirements;
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the maintenance of accounts and records;
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relationships among affiliated companies involved in certain aspects of the natural gas business;
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depreciation and amortization policies; and
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the initiation and discontinuation of services.
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The FERC's authority over crude oil and NGL pipelines is less broad, extending to:
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rates, rules and regulations of service;
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the form of tariffs governing rates and service;
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the maintenance of accounts and records; and
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depreciation and amortization policies.
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Interstate natural gas and crude oil 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.
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 changes and changes to terms and conditions of service proposed by a regulated natural gas interstate pipeline may be protested and such changes can be delayed and may ultimately be rejected by the FERC. The FERC may also initiate reviews of our rates. We currently hold authority from the FERC to charge and collect (i) "recourse rates" (i.e., the maximum cost-based rates an interstate natural gas pipeline may charge for its services under its tariff); (ii) "discount rates" (i.e., rates offered by the natural gas pipeline to shippers at discounts vis-à-vis the recourse rates and that fall within the cost-based maximum and minimum rate levels set forth in the natural gas pipeline's tariff); and (iii) "negotiated rates" (i.e., rates negotiated and agreed to by the pipeline and the shipper for the contract term that may fall within or outside of the cost-based maximum and minimum rate levels set forth in the tariff, and which are individually filed with the FERC for review and acceptance). When capacity is available and offered for sale, the rates (which include reservation, commodity, surcharges, and fixed fuel and lost and unaccounted for charges) at which such capacity is sold are subject to regulatory approval and oversight. We cannot guarantee that any new or existing tariff rate for service on the Rockies Express Pipeline, the TIGT System or Trailblazer Pipeline would not be rejected or modified by the FERC, or subjected to refunds. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition and results of operations.
In 2019, we entered into settlements with our customers on the TIGT System and the Trailblazer Pipeline. As a result of these settlements, the rates we can charge on the TIGT System are expected to remain in place through May 31, 2023, and, subject to the approval of the settlement by the FERC, the rates we can charge on the Trailblazer Pipeline are expected to remain in place through December 31, 2025. In the event the assumptions relied upon during settlement negotiations were incorrect or the actual costs incurred to operate these pipelines increase, our cash flows and results of operations could be adversely affected.
Pursuant to the ICA, existing interstate crude oil transportation rates and terms and conditions of service may be challenged by complaint. A successful complainant is entitled to reparations going back two years from the date of the complaint as well as forward reparations from the date of the complaint until a new rate or policy is put in place. Additionally,
rate changes and changes to terms and conditions of service proposed by a regulated interstate crude oil pipeline may be protested and such changes can be suspended for up to seven months and may ultimately be rejected by the FERC. We currently have three different rate types across our systems. The first are contract rates, which means they are contractually agreed to and given in exchange for either commitments to ship on the pipeline or acreage dedications ("Contract Rates"). Contract Rates will generally be honored by the FERC during the term of the contracts. Contract Rates may be changed annually based on the terms of the contract. The second are indexed rates, which means they may be increased or decreased at any time provided they do not exceed the index ceiling ("Indexed Rates"). The index ceiling is calculated yearly by applying the FERC-approved inflationary adjustment, which may be positive or negative. These rates can be challenged on a cost-of-service basis. The third are volume incentive rates, which reflect a discount to the Indexed Rates and are available to all shippers without a contractual commitment to ship on the pipeline ("Volume Incentive Rates"). These discounts are discretionary and not challengeable on a cost-of-service basis; however, should Pony Express' Indexed Rates be lowered due to a cost-of-service challenge, the Volume Incentive Rates would have to be reduced if they are no longer below the Indexed Rates. Interstate crude oil pipelines typically must reserve at least ten percent of their capacity for walk-up shippers, i.e., shippers with no contractual commitment to ship.
We cannot guarantee that any new or existing tariff rate for service on the Pony Express System, the PRE Pipeline, or the Iron Horse Pipeline would not be rejected or modified by the FERC, or subjected to refunds or reparations. While the FERC regulates rates and terms and conditions of service for transportation of crude oil in interstate commerce by pipeline, state agencies may also regulate facilities (including construction, acquisition, disposition, financing, and abandonment), rates, and terms and conditions of service for crude oil pipeline transportation in intrastate commerce. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition and results of operations.
Pony Express Pipeline's tariff rates may not always be eligible for increases to reflect a FERC index adjustment. In addition, the FERC may modify how it determines eligibility for applying the FERC index adjustment. For example, on November 2, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking, under which the FERC is proposing changes to its policies regarding the eligibility for a rate increase under indexing, based on specific pipelines' earnings or their specific changes to costs. The FERC's Advanced Notice of Proposed Rulemaking does not propose specific regulations, and may be followed by a Notice of Proposed Rulemaking proposing specific regulations or a Policy Statement announcing new or changed policies. This proceeding is pending before the FERC.
The FERC's jurisdiction over natural gas facilities extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to, acquisitions, facility maintenance and upgrades, expansions, and abandonment of facilities and services. With some exceptions applicable to smaller projects, auxiliary facilities, and certain facility replacements, prior to commencing construction and/or operation of new or expanded interstate natural gas transportation and storage facilities, an interstate natural gas pipeline must obtain a certificate authorizing the construction from, or file to amend its existing certificate with, the FERC. The FERC may include conditions on its issuance of the certificate that make a project impracticable or too costly, or may ultimately determine not to issue the certificate required for us to pursue a project. Typically, a significant expansion project requires review by a number of governmental agencies, including the FERC, and other federal, state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any delay or refusal by an agency to issue authorizations or permits as requested for one or more of these projects may mean that they will be constructed in a manner or with capital requirements that we did not anticipate or that we will not be able to pursue these projects. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from these projects. The FERC does not regulate the construction, expansion, or abandonment of crude oil or NGL pipelines, whether interstate or intrastate, nor the initiation or discontinuation of services on those pipelines, provided that the action taken is not discriminatory or preferential among similarly situated shippers. The construction of crude oil and NGL pipelines, whether interstate or intrastate, and rates and terms and conditions of intrastate service, however, are typically subject to regulation by state agencies.
For example, in March 2018 we submitted applications to the FERC pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the Cheyenne Hub Enhancement Project and the Cheyenne Connector Pipeline. However, the FERC did not issue an order approving the applications until September 2019. As a result, the expected in-service date of the Cheyenne Hub Enhancement Project and the Cheyenne Connector Pipeline was delayed to the first half of 2020.
The FERC has the authority to conduct audits of regulated entities to assess compliance with FERC regulations and policies. The FERC also conducts audits to verify that the websites of interstate natural gas pipelines accurately provide information on the operations and availability of services on the pipeline. FERC regulations also require entities providing interstate natural gas and crude oil transportation services to comply with uniform terms and conditions for service, as set forth in publicly available tariffs or, as it concerns natural gas facilities, agreements for transportation and storage services executed between interstate pipelines and their customers. Natural gas transportation service agreements are generally required to conform, in all material respects, with the standard form of service agreements set forth in the natural gas pipeline's FERC-
approved tariff. The pipeline and a customer may choose to enter into a non-conforming service agreement so long as the agreement is filed with, and accepted by, the FERC. In the event that the FERC finds that a natural gas transportation agreement, in whole or part, is materially non-conforming, the FERC could reject the agreement or require us to modify the agreement, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers. Transportation agreements entered into with crude oil shippers are generally not subject to FERC regulation or required to be available for FERC or public review, but the rates and terms and services provided to similarly situated shippers may not be unduly discriminatory or preferential.
The FERC has promulgated rules and policies covering many aspects of our natural gas pipeline business, including regulations that require us to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential, provide internet access to current information about our available pipeline capacity and other relevant transmission information, and permit pipeline shippers to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. FERC regulations also prevent interstate natural gas pipelines from sharing customer information with marketing affiliates, and restrict how interstate natural gas pipelines share transportation information with marketing affiliates. FERC regulations require that certain transmission function personnel of interstate natural gas pipelines function independently of personnel engaged in natural gas marketing functions. Crude oil pipelines subject to the ICA must comply with FERC regulations that require the pipeline to act as a common carrier and not engage in undue discrimination or preferential treatment with respect to shippers. The ICA also prevents crude oil and NGL pipelines from disclosing certain shipper information without the shipper's consent.
FERC policies also govern how interstate natural gas pipelines respond to interconnection requests from third party facilities, including other pipelines. Generally, an interstate natural gas pipeline must grant an interconnection request upon the satisfaction of several conditions. As a consequence, an interstate natural gas pipeline faces the risk that an interconnecting third-party pipeline may pose a risk of additional competition to serve a particular market or customer. Failure to comply with applicable provisions of the NGA, NGPA, EPAct 2005 and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of more than $1 million per day, per violation. Violations of the ICA, the Energy Policy Act of 1992, or regulations and orders promulgated by the FERC are also subject to administrative and criminal penalties and remedies, including forfeiture and individual liability.
In addition, new laws or regulations or different interpretations of existing laws or regulations applicable to our pipeline systems or midstream facilities could have a material adverse effect on our business, financial condition, results of operations and prospects. For example, on November 22, 2017, in FERC Docket No. OR17-2-000, the FERC issued an Order on Petition for Declaratory Order addressing whether certain specific hypothetical transactions between a petroleum liquids pipeline and its marketing affiliate proposed by the petitioner, Magellan Midstream Partners, L.P., would violate the requirements of the ICA or the FERC's regulations and policies. The FERC concluded that certain transactions proposed by the petitioner could be inconsistent with the ICA and the FERC's policies. Various market participants filed requests for clarification or, in the alternative, rehearing of the November 22, 2017 declaratory order. On January 22, 2018, the FERC issued an order granting rehearing for further consideration, which afforded the FERC additional time to consider and rule on the pending clarification/rehearing requests. The outcome of this proceeding and any related proceeding(s) may require us to modify the business practices between our petroleum liquids pipelines regulated by the FERC and our affiliated marketer, Stanchion. To the extent the foregoing proceedings result in substantial new restrictions on the transactions between petroleum liquids pipelines and their affiliated shippers, the business activities of Stanchion could be affected.
The FERC's treatment of income taxes could affect the rates charged on our natural gas and crude oil pipeline systems which could adversely affect our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders.
The FERC has historically permitted regulated interstate crude oil and natural gas pipelines to include an income tax allowance in their cost of service used to calculate cost-based transportation rates. The allowance is intended to reflect the actual or potential tax liability attributable to the regulated entity's operating income, regardless of the form of ownership. On July 1, 2016, in United Airlines, Inc. v FERC, the United States Court of Appeals for the D.C. Circuit vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by a Master Limited Partnership ("MLP") to include an income tax allowance in its cost-of-service rates. The D.C. Circuit held that the FERC had failed to demonstrate that the inclusion of both an income tax allowance in the pipeline's rates and a return on equity determined using a discounted cash flow methodology would not lead to a double-recovery of income tax costs for a pipeline organized as an MLP.
Following the D.C. Circuit's decision, the FERC issued its Revised Policy Statement on Treatment of Income Taxes in Docket No. PL17-1-000 on March 15, 2018 which eliminates the recovery of an income tax allowance by MLP crude oil and natural gas pipelines in cost-of-service-based rates. The FERC directed MLP crude oil pipelines to reflect the elimination of the income tax allowance in their Form No. 6, page 700 reporting and stated that it will incorporate the effects of this Revised Policy on industry-wide crude oil pipeline costs in the 2020 five-year review of the pipeline index level that pipelines with rates
subject to annexing apply annually to adjust the rates. The FERC also stated that it would address income tax allowances for other "pass-through" entities that are not MLPs in future proceedings.
While we are not an MLP, our ownership of our FERC-regulated pipelines is held directly and indirectly by "pass-through" entities. The FERC could determine to apply the elimination of the income tax allowance to such "pass-through" entities. To the extent that we charge cost-of-service based rates, those rates could be affected by the elimination of the income tax allowance if our rates are subject to complaint or challenge raised by shippers or by the FERC acting on its own initiative, or if we propose new cost-of-service rates or changes to our existing rates. In such instances, it is possible that certain tariff rates could be reduced, which could adversely affect our financial position, results of operations and ability to make quarterly cash dividends to our Class A shareholders.
On December 22, 2017, federal legislation known as the "Tax Cuts and Jobs Act" was enacted, which made various changes to the United States tax laws, including reducing the highest marginal U.S. federal corporate income tax rate from 35% to a flat rate of 21% for tax years beginning after December 31, 2017, adjusting the individual income tax brackets, and establishing limited deductions for certain income from "pass-through" entities. In late 2018, Rockies Express and TIGT each submitted one-time informational filings in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement. FERC determined that no action was required on Rockies Express' filing to adjust its rates in respect of the tax changes. In connection with FERC's approval of the TIGT pre-filing rate settlement, FERC also took no action in respect of the tax changes. The effects of the corporate income tax rate reduction will be considered by FERC in 2020 in the five-year review of the pipeline index level.
The outcome of these proceedings could affect the rates charged on our natural gas and crude oil pipeline systems which could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders.
We are subject to numerous hazards and operational risks.
Our operations are subject to all the risks and hazards typically associated with transportation, storage, terminalling, processing, gathering and disposing of hydrocarbons and water. These operating risks include, but are not limited to:
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damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires or other adverse weather conditions and other natural disasters and acts of terrorism;
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inadvertent damage from construction, vehicles, farm and utility equipment;
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uncontrolled releases of crude oil, natural gas and other hydrocarbons or hazardous materials, including water from hydraulic fracturing;
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leaks, migrations or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;
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outages at our facilities;
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ruptures, fires, leaks and explosions; and
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other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and suspension of operations.
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These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of our assets, including certain segments of our pipeline systems in or near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas could increase the level of damages resulting from these risks. Despite the precautions we take, events could cause considerable harm to people or property, could result in loss of service available to customers, and could have a material adverse effect on our financial condition and results of operations and ability to make quarterly cash dividends to Class A shareholders.
For example, the Pony Express Pipeline had a temporary embargo of deliveries beginning May 23, 2019 that continued until May 31, 2019 due to extensive flooding on the Cimarron River in Payne County, Oklahoma. The flooding did not damage the Pony Express Pipeline, but our operating costs were temporarily increased after the embargo ended to facilitate the completion of the backlog of deliveries. Further, any walk-up shipper barrels that were not already tendered to Pony Express Pipeline were diverted to other pipelines during the embargo. If any future flooding occurs that results in a longer delivery embargo being necessary, the impact of such embargo could significantly decrease our revenues on the Pony Express Pipeline.
In addition, on January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations. However, the release required Rockies Express to shut off the flow through the segment until February 27, 2018, when
temporary repairs were completed allowing the segment to be placed back into service. Permanent repairs were completed in September 2018 and the total cost of remediation was approximately $6.1 million prior to any insurance recoveries. As an additional example, approximately 10,000 bbls of crude oil were released at the Sterling Terminal in January 2017 as a result of a defective roof drain system on a storage tank. While the release was restricted to the containment area designed for such purpose and approximately 9,000 bbls were ultimately recovered, the total cost to remediate the release was approximately $600,000.
Moreover, maintenance, repair and remediation activities could result in service interruptions on segments of our systems or alter the operational profile of our systems. Any such service interruption or alteration could limit our ability to satisfy customer requirements, could obligate us to provide reservation charge credits to customers for constrained capacity, or could allow existing customers to be solicited by other companies for potential new projects that would compete directly with our services.
We could be required by regulatory authorities to test or undertake modifications to our systems, operations or both that could result in a material adverse impact on our business, financial condition and results of operations. Such actions, including those required by PHMSA, could materially and adversely impact our ability to meet contractual obligations and retain customers, with a resulting material adverse impact on our business and results of operations, and could also limit or prevent our ability to make quarterly cash dividends to our Class A shareholders. Some or all of our costs arising from these operational risks may not be recoverable under insurance, contractual indemnification or increases in rates charged to our customers.
Our business could be negatively impacted by security threats, including cyber security threats, and related disruptions.
We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. We may face cyber security and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, "hacktivists," or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cyber security threats. We could also face attempts to gain access to information related to our assets through unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information, otherwise known as "social engineering."
Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, service interruptions, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position, results of operations and prospects. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective and detective measures or to investigate and remediate any vulnerability to cyber incidents.
If we are unable to protect our information and telecommunication systems against disruptions or failures, our operations could be disrupted.
We rely extensively on computer systems to process transactions, maintain information and manage our business. Disruptions in the availability of our computer systems could impact our ability to service our customers and adversely affect our sales and results of operations. We are dependent on internal and third-party information technology networks and systems, including the Internet, wired, and wireless communications, to process, transmit and store electronic information. Our computer systems are subject to damage or interruption due to system replacements, implementations and conversions, power outages, computer or telecommunication failures, computer viruses, security breaches, catastrophic events such as fires, tornadoes, snowstorms and floods and usage errors by our employees, consultants and contractors. If our computer systems are damaged or cease to function properly, we may have to make a significant investment to fix or replace them, and we may have interruptions in our ability to service our customers. Although we attempt to reduce these risks by using redundancy for certain critical systems, this disruption caused by the unavailability of our computer systems could nevertheless significantly disrupt our operations or may result in financial damage or loss due to, among other things, lost or misappropriated information.
Increasing regulatory focus on privacy and security issues and expanding laws could impact our business models, expose us to increased liability, subject us to lawsuits, investigations and other liabilities and restrictions on our operations that could significantly and adversely affect our business.
Along with our own data and information in the normal course of our business, we collect and retain significant volumes of certain types of data, some of which are subject to specific laws and regulations. Complying with varying jurisdictional requirements is becoming increasingly complex and could increase the costs and difficulty of compliance, and violations of
applicable data protection laws, including the European Union General Data Protection Regulation ("GDPR") and the California Consumer Privacy Act ("CCPA"), could result in significant penalties.
The GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through vendors and subcontractors, from an establishment in the European Union. As interpretation and enforcement of the GDPR evolves, it creates a range of new compliance obligations, which could cause us to incur costs or require us to change our business practices in a manner adverse to our business. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover that may materially adversely affect our business, reputation, results of operations, and cash flows.
The CCPA, which came into effect on January 1, 2020, gives California residents specific rights in relation to their personal information, requires that companies take certain actions, including notifications for security incidents and may apply to activities regarding personal information that is collected by us, directly or indirectly, from California residents. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could cause us to change our business practices, with the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.
Non-compliance with these and other data protection laws could expose us to regulatory investigations, which could result in fines and penalties. In addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations. We could also be subject to litigation from individuals or entities allegedly affected by data protection violations. Any violation of these laws or harm to our reputation could have a material adverse effect on our business, financial condition, results of operations and prospects.
Our insurance coverage may not be adequate.
We are not insured or fully insured against all risks that could affect our business, including losses from environmental accidents or cyber security threats. For example, we do not maintain business interruption insurance in the type and amount to cover all possible losses. In addition, we do not carry insurance for certain environmental exposures, including but not limited to potential environmental fines and penalties, certain business interruptions, named windstorm or hurricane exposures and, in limited circumstances, certain political risk exposures. Further, in the event there is a total or partial loss of one or more of our insured assets, any insurance proceeds that we may receive in respect thereof may be insufficient to effect a restoration of such asset to the condition that existed prior to such loss. In addition, we are either not insured or not fully insured with respect to the legal proceedings described in Note 20 – Legal and Environmental Matters and may, depending upon the circumstances, need to pay self-insured retention amounts prior to having losses covered by the insurance providers. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates, and we have elected and may elect in the future to self-insure a portion of our risks of loss. As a result of market conditions, premiums and deductibles for certain types of insurance policies may substantially increase, and in some instances, certain types of insurance could become unavailable or available only for reduced amounts of coverage. Any insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses.
Our pipeline integrity program may impose significant costs and liabilities on us, while increased regulatory requirements relating to the integrity of our pipeline systems may require us to make additional capital and operating expenditures to comply with such requirements.
We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal requirements set by PHMSA for owners and operators of pipelines in the areas of pipeline design, construction, and testing, the qualification of personnel and the development of operations and emergency response plans. The rules require pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as HCAs.
Our pipeline operations are subject to pipeline safety regulations administered by PHMSA. These regulations, among other things, include requirements to monitor and maintain the integrity of our pipeline systems and determine the pressures at which our pipeline systems can operate. The Pipeline Safety Act of 2011, enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002 in a number of significant ways, including:
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reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines;
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requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote- controlled shutoff valves on new or rebuilt pipeline facilities;
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requiring operators of pipelines to verify MAOP and report exceedances within five days; and
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requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those requirements to areas outside of HCAs.
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In August 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties from $0.1 million to $0.2 million per violation per day of violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing PHMSA's enforcement process. In July 2019, PHMSA issued a final rule that increased the per-day violation penalty from $213,268 to $218,647 and the maximum penalty for a related series of violations from $2,132,679 to $2,186,465, effective July 31, 2019. On October 1, 2019, PHMSA finalized new hazardous liquid pipeline safety regulations extending certain regulatory reporting requirements to hazardous liquid gathering (including oil) pipelines, except transportation-related flow lines, which will be exempt from reporting requirements until further study and cost analyses can be conducted. The final rule requires additional event-driven (e.g., following extreme weather events) and periodic inspections, requires the use of leak detection systems on all new, covered, hazardous liquid pipelines, imposes modified repair criteria, and requires certain pipelines to eventually accommodate in-line inspection tools. The rule becomes effective July 1, 2020.
In addition, on April 8, 2016, PHMSA published a notice of proposed rule-making, or NPRM, addressing natural gas transmission and gathering lines. The proposed rule would include changes to existing integrity management requirements and would expand assessment and repair requirements to pipelines in MCAs, along with other changes. Further, this NPRM would build on the requirements in an Advisory Bulletin PHMSA issued in May 2012, which advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. On October 1, 2019, PHMSA issued a final rule, effective July 1, 2020, that puts in place the first third of the regulations contemplated by the 2016 NPRM; two other phases of rulemaking are expected to address the remainder of items proposed in the 2016 NPRM. The October 2019 final rule requires the completion of periodic integrity reassessments, ordinarily required once every seven years, within six months of written notice from PHMSA; requires operators to consider and account for seismicity in identifying potential threats; requires the reporting of MAOP exceedances of gas transition pipelines; and imposes the proposed record-keeping requirements to confirm MAOP. In addition, the final rule requires operators to perform integrity assessments in MCAs and Class 3 and 4 areas (involving either high density or high consequence structures) at least once by October 1, 2033, and at least once every 10 years thereafter. The final rule also sets specific standards for pressure-relief safety devices on in-line pipeline inspection tools. We are still evaluating the effects of these recently finalized requirements on our operations.
The PIPES Act, enacted on June 22, 2016, reauthorized PHMSA's oil and gas pipeline programs through 2019 and provided for the following new mandates, among others:
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empowers PHMSA to issue emergency orders to individual operators, groups of operators, or the industry upon a written finding that an unsafe condition or practice constitutes or is causing an imminent hazard;
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requires PHMSA, in consultation with other federal agencies, to issue minimum safety standards for underground natural gas storage facilities within two years;
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requires PHMSA to conduct post-inspection briefings outlining any concerns within 30 days and providing written preliminary findings within 90 days to the extent practicable;
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requires liquid pipeline operators to provide safety data sheets on spilled product to the designated federal on-scene coordinator and appropriate state and local emergency responders within 6 hours of telephonic or electronic notice of an accident to the National Response Center; and
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requires PHMSA to publish updates on its website every 90 days on the status of an outstanding final rule required by a statutory mandate.
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The reauthorization of these programs for periods subsequent to 2019 remains pending before the U.S. Congress.
On December 14, 2016, PHMSA issued an IFR that addresses safety issues related to downhole facilities, including well integrity, well bore tubing and casing at underground natural gas storage facilities. The IFR incorporates by reference two of the American Petroleum Institute's Recommended Practice standards and mandates certain reporting requirements for operators of underground natural gas storage facilities. Operators of natural gas storage facilities were given one year from January 18, 2017, the effective date of the IFR, to implement this first set of PHMSA regulations governing underground storage fields. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule.
In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. The associated NPRM is expected in April 2020.
The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe determined to be located in HCAs or expansion of integrity management requirements to areas outside of HCAs, such as the MCAs and Class 3 and 4 areas included in the recently finalized PHMSA rule, can have a significant impact on the costs to perform integrity testing and repairs.
For example, starting in 2014, Trailblazer's operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing subscription levels or had a material adverse financial impact on us. However, Trailblazer continued performing remediation to increase and maximize its operating capacity over the long-term and spent approximately $21 million during 2018 for this pipe replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating capacity.
Additionally, in connection with certain crack tool runs on the Pony Express System completed in 2015, 2016 and 2017, Pony Express completed approximately $18 million of remediation for anomalies identified on the Pony Express System associated with portions of the pipeline converted from natural gas to crude oil service. Remediation work was substantially complete as of March 31, 2018.
There can be no assurance as to the amount or timing of future expenditures required to remediate or resolve these issues, and actual future expenditures may be different from the amounts we currently anticipate. These integrity issues could have a material adverse effect on our business, financial position, results of operations and prospects.
We will continue pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the U.S. Department of Transportation regulations. The results of these tests could cause us to incur potentially material unanticipated capital and operating expenditures for repairs or upgrades.
Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. For example, PHMSA issued an Advisory Bulletin in May 2012 which advised pipeline operators that they must have records to document the MAOP for each section of their pipeline and that the records must be traceable, verifiable and complete. Certain of these requirements are included in the recently finalized PHMSA rule that becomes effective July 1, 2020. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of verifiable pressures, could significantly increase costs. TIGT continues to investigate and, when necessary, report to PHMSA the miles of pipeline for which it has incomplete records for MAOP. Additionally, failure to locate such records or verify maximum pressures could require us to operate at reduced pressures, which would reduce available capacity on our natural gas pipeline systems. These specific requirements do not currently apply to crude oil pipelines, but proposed regulations implementing the Pipeline Safety Act of 2011 and future regulations implementing the PIPES Act likely will expand the scope of regulation applicable to crude oil pipelines. There can be no assurance as to the amount or timing of future expenditures required to comply with pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. In addition, we may be subject to enforcement actions and penalties for failure to comply with pipeline regulations. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial position, results of operations and prospects. In addition, we may be subject to enforcement actions and penalties for failure to comply with pipeline regulations.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures that could exceed our current expectations.
Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in our crude oil transportation, storage, gathering and terminalling, natural gas transportation, storage, gathering and processing, NGL transportation and water business services, and as a result, we may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state, and local laws and regulations governing health and safety aspects of our operations, environmental protection, including the discharge of materials into the environment, and the security of chemical and industrial facilities. These laws include, but are not limited to, the following:
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CAA and analogous state and local laws, which impose obligations related to air emissions and which the EPA has relied upon as authority for adopting climate change regulatory initiatives;
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CWA and analogous state and local laws, which regulate discharge of pollutants or fill material from our facilities to state and federal waters, including wetlands and which require compliance with state water quality standards;
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CERCLA and analogous state and local laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;
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RCRA and analogous state and local laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from our facilities;
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The SDWA, which ensures the quality of the nation's public drinking water through adoption of drinking water standards and controls the waste fluids from disposal wells into below-ground formations;
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OSHA and analogous state and local laws, which establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
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NEPA and analogous state and local laws, which require federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;
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The Migratory Bird Treaty Act, or MBTA, and analogous state and local laws, which implement various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
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ESA and analogous state and local laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;
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Bald and Golden Eagle Protection Act, or BGEPA, and analogous state and local laws, which prohibit anyone, without a permit issued by the Secretary of the Interior, from "taking" bald or golden eagles, including their parts, nests, or eggs, and defines "take" as "pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, molest or disturb;"
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OPA and analogous state and local laws, which impose liability for discharges of oil into waters of the United States and requires facilities which could be reasonably expected to discharge oil into waters of the United States to maintain and implement appropriate spill contingency plans; and
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National Historic Preservation Act, or NHPA, and analogous state and local laws, which are intended to preserve and protect historical and archeological sites.
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Various governmental authorities, including but not limited to the EPA, the U.S. Department of the Interior, the U.S. Department of Homeland Security, and analogous federal, state and local agencies have the power to enforce compliance with these and other similar laws and regulations and the permits and related plans issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these and other similar laws, regulations, permits, plans and agreements may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays in granting permits.
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products we transport, process, treat, dispose, gather or store, air emissions related to our operations, historical industry operations, and waste disposal practices, such as the prior use of flow meters and manometers containing mercury. These activities are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact our business activities in many ways, such as restricting the way we handle or dispose of wastes or requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operators. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including but not limited to CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with oil, natural gas and wastes on, under, or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses,
which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. We are currently conducting remediation at several sites to address contamination. For these ongoing environmental remediation projects, we spent approximately $362,000 in 2018, approximately $518,000 in 2019 and we have budgeted approximately $1.15 million for 2020.
Private parties, including but not limited to the owners of properties through which our pipelines pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws, regulations and permits issued thereunder, or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage, processing, operations or other facilities, and there is a risk that contamination has migrated from those sites to ours that could result in remedial action. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance does not cover all environmental risks and costs and may not provide sufficient coverage if an environmental claim is made against us.
For the 2020-2023 time period, as part of its National Compliance Initiatives (previously National Enforcement Initiatives), the EPA is proposing to focus on significant sources of VOCs that have a substantial impact on air quality, without regard to sector, and that may adversely affect vulnerable populations or an area's CAA attainment status. We cannot predict what the results of the current initiative or any future initiative will be, or whether federal, state or local laws or regulations will be enacted in this area. If new regulations are imposed related to oil and gas extraction, the volumes of products, including hydrocarbons and water, that we transport, store, gather, dispose and/or process could decline and our results of operations could be materially and adversely affected.
Our business may be materially and adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits or plans developed thereunder. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations, or may have to implement contingencies or conditions in order to obtain such approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation, maintenance or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows. For instance, in November 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. 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. In March 2019, TMID and TIGT entered into a Consent Decree to settle this matter with the WDEQ and made an approximately $0.1 million penalty payment to the WDEQ.
We are also generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. As an example, in August 2011, the EPA and the Wyoming Department of Environmental Quality conducted an inspection of the Leak Detection and Repair Program, or LDAR, at the Casper Plant in Wyoming, and TMID subsequently received a letter from the EPA in September 2011 alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the CAA. After settlement negotiations that extended over several years, TMID and TIGT entered into a Consent Agreement and Final Order to settle this matter with the EPA in February 2019 and made an approximately $0.1 million penalty payment to the EPA.
We have agreed to a number of conditions in our environmental permits and associated plans, approvals and authorizations that require the implementation of environmental habitat restoration, enhancement and other mitigation measures that involve, among other things, ongoing maintenance and monitoring. Governmental authorities may require, and community groups and private persons may seek to require, additional mitigation measures in the future to further protect ecologically sensitive areas where we currently operate, and would operate if our facilities are extended or expanded, or if we construct new facilities, and we are unable to predict the effect that any such measures would have on our business, financial position, results of operations or prospects.
Also, on January 23, 2020, the EPA and the U.S. Army Corps of Engineers, or Corps, issued a pre-publication version of a final rule to clarify the term "waters of the United States" as it pertains to federal jurisdiction under the CWA. This rule is in direct response to a prior rule, issue June 29, 2015, that many interested parties believed expanded federal jurisdiction under the CWA and that was extensively litigated. It is anticipated that the 2020 final rule defining "waters of the United States" will also be subject to court challenge. The regulation and future interpretation of the term "waters of the United States" rule may require additional Corps or EPA authorizations or involvement in our future operations.
Certain interest groups generally opposed to the development of oil, natural gas and NGLs, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives aimed at significantly limiting or preventing the development of oil, natural gas and NGLs. As discussed above in "-The lack of diversification of our assets and geographic locations could adversely affect our ability to make quarterly cash dividends to our Class A shareholders.", following the failure of several ballot initiatives to restrict oil and gas development, Colorado passed a new law in April 2019 (Senate Bill 19-181) that, among other things, changes the mission of the COGCC from fostering oil and gas development to instead focus on environmental protection, directs the COGCC and various state agencies to consider new rules imposing stricter environmental controls on the oil and gas industry, and provides local governments with the authority to promulgate their own regulations on oil and gas development. Pursuant to this statutory change, in November 2019, the COGCC issued draft proposed rules related to the oversight of flowlines. The COGCC is also currently soliciting public comment on anticipated future rule changes related to the COGCC's mission, cumulative impacts, and alternative location analyses. While the ultimate impact of the new Colorado law and related rules is currently unknown, this law or passage or enactment of other similar legislation could have a material adverse effect on our customers in the state of Colorado, which could reduce demand for our pipeline services. In addition, our operations could be directly impacted by new rulemakings targeting air emissions from our facilities. For example, the Colorado Department of Public Health and the Environment is considering proposing additional oil and gas measures to reduce VOC and methane emissions from the sector in accordance with the directives of Senate Bill 19-181.
The general trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be materially different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.
Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for us and reduced demand for our services.
The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. On April 22, 2016, 175 countries, including the United States, signed the Paris Agreement. The Paris Agreement will require countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in November 2019, the United States formally initiated its year-long withdrawal from the Paris Agreement, which will result in an effective exit as early as November 2020.
Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA also expanded its existing GHG emissions reporting requirements to include upstream petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year. Some of our facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting requirements. Furthermore, the EPA adopted a final rule, effective August 2, 2016, imposing more stringent controls on methane and volatile organic compounds emissions from oil and gas development, production, and transportation operations under the New Source Performance Standard, or NSPS, program. In September 2019, the EPA proposed a rule to reconsider, rescind, and amend various requirements of the NSPS standard, including removing sources in the transmission and storage segment from the regulated source category, rescinding the NSPS (including both VOC and methane requirements) applicable to those sources, and rescinding the methane-specific requirements of the NSPS applicable to sources in the production and processing segments. Alternatively, EPA proposes to rescind the methane requirements of the NSPS applicable to all oil and natural gas sources, without removing any sources from the source category. However, the NSPS rule currently remains in effect. In 2016, the EPA also finalized a rule regarding the alternative criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby
triggering more stringent air permitting processes and requirements across the oil and gas industry. The BLM also adopted new rules, effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. This rule was suspended, stayed, and reinstated before the BLM issued a final rule in September 2018 that rescinds and revises many of the requirements of the 2017 rule. The revision rule is being challenged in the U.S. District Court for the Northern District of California but currently remains in effect. In addition, many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.
The adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to reduce emissions of GHGs associated with our operations, could adversely affect our operations in the absence of any permits that may be required to regulate emission of GHGs, or could adversely affect demand for the crude oil and natural gas we transport, gather, process, or otherwise handle. For instance, the EPA's recently finalized NSPS rules or future rules under CAA Section 111(d) could result in the direct regulation of GHGs associated with our operations, including the operations of Rockies Express. We are not able at this time to estimate such increased costs; however, they could be significant. While we may be able to recover some or all of such increased costs in the rates charged by our processing facilities, such recovery of costs is uncertain and may depend on the terms of our contracts with our customers.
Increased regulation of hydraulic fracturing could affect our operations and result in reductions or delays in production by our customers, which could have a material adverse impact on our revenues.
A sizeable portion of our customers' production comes from hydraulically fractured wells. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations. The process typically involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state's oil and gas commission; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the SDWA and has released draft permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where the EPA is the permitting authority. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, on May 19, 2014, the EPA published an advance notice of rulemaking under the Toxic Substances Control Act, to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. In May 2016, the EPA issued final rules that update new source performance standard requirements and that will impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. In September 2019, the EPA proposed a rule to reconsider, rescind, and amend various requirements of the NSPS standard. However, the rule currently remains in effect. The EPA also issued a final rule in June 2016 that prohibits the discharge of hydraulic fracturing wastewater from onshore unconventional oil and gas extraction facilities into publicly owned sewage treatment plants. Also, the BLM adopted new rules effective January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. This rule was suspended, stayed, and reinstated before the BLM issued a final rule in September 2018 that rescinds and revises many of the requirements of the 2017 rule. The revision rule is being challenged in the U.S. District Court for the Northern District of California but currently remains in effect.
Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, and in some cases, may seek to ban hydraulic fracturing entirely. Some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including temporary or permanent bans, additional permit requirements, operational restrictions and chemical disclosure obligations on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. Other governmental agencies, including the U.S. Department of Energy and the EPA, have evaluated or are evaluating various other aspects of hydraulic fracturing such as the potential environmental effects of hydraulic fracturing on drinking water and groundwater. On December 13, 2016, the EPA released a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, concluding that there is scientific evidence that hydraulic fracturing activities potentially can impact drinking water resources in the United States under some circumstances.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or significantly more costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of crude oil, natural gas or other hydrocarbons that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for us and our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.
Our produced water disposal operations may be subject to additional regulation and liability or claims of environmental damages.
We operate produced water disposal wells which are regulated under the federal SDWA as Class II wells and under state and local laws. State and local laws and regulations that govern these operations can be more stringent than the SDWA. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may also incur material environmental costs and liabilities. Furthermore, our insurance may not provide sufficient coverage in the event an environmental claim is made against us. In addition, although the disposal wells have received certain governmental regulatory licenses, permits or approvals, this does not shield us from potential claims from third parties claiming contamination of their water supply or other environmental damages. Remediation of environmental contamination or damages can be extremely costly and such costs, if we are found liable, may have a material adverse effect on our business, financial condition and results of operations.
Produced water injection well operations and hydraulic fracturing may cause induced seismicity.
State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of produced water injection wells in the vicinity of seismic events have been ordered to reduce produced water injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado and Texas, have modified their regulations to account for induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In 2015, the United States Geological Study, or USGS, identified eight states, including Colorado, Oklahoma and Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. The USGS also produced a one-year 2017 induced seismicity model that forecast an elevated hazard from induced seismicity in Oklahoma compared to the hazard calculated for seismicity before 2009. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that produced water disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. The Oklahoma Corporation Commission, or OCC, has adopted a plan calling for mandatory reductions in oil and gas wastewater disposal well volumes, the implementation of which has involved reductions of injection or shut-ins of disposal wells. The OCC has also released guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing activities. These developments could result in additional regulation and restrictions on the use of produced water injection wells and hydraulic fracturing. Such regulations and restrictions could have a material adverse effect on our business, financial condition and results of operations.
Certain portions of our transportation, storage and processing facilities have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our facilities that could have a material adverse effect on our business and results of operations.
Significant portions of our transportation, storage and processing systems have been in service for several decades. The age and condition of our facilities could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our facilities could adversely affect our business and results of operations and our ability to make quarterly cash dividends to our Class A shareholders.
We have certain long-term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if our costs increase. As a result, our costs could exceed our revenues.
As of December 31, 2019, approximately 59% of our contracted natural gas transportation firm capacity was provided under long-term, fixed price "negotiated or discount rate" contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts. It is possible that costs to perform services under our "negotiated or discount rate" contracts will exceed the negotiated or discounted rates. It is also possible with respect to discounted rates that if our filed "recourse rates" should ever be reduced below applicable discounted rates, we would only be allowed by the FERC to charge the lower recourse rates, since FERC policy does not allow discount rates to be charged to the extent that they exceed applicable recourse rates. If these events were to occur, it could decrease the cash flow realized by our assets and, therefore, the cash we have available for dividends to our Class A shareholders.
Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a "negotiated rate," which is generally fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based "recourse rates," provided that the affected customer is willing to agree to such rates and that the FERC has accepted the negotiated rate agreement. These "negotiated or discount rate" contracts are not generally subject to adjustment for increased costs which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between "recourse rates" (if higher) and negotiated or discounted rates, under current FERC policy, may be recoverable from other shippers in certain circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case. However, if the FERC were to disallow the recovery of such costs from other customers, it could decrease the cash flow realized by our assets and, therefore, the cash we have available for dividends to our Class A shareholders.
Rates under Pony Express' TDAs are typically subject to change only per contract terms and conditions, including Pony Express' right to file changes to contract rates to reflect annual index percentage adjustments published by the FERC. We generally cannot file for rate increases with respect to committed shippers who have signed TDAs, other than to reflect annual index adjustments or to recover compliance costs imposed by governmental actions.
A significant amount of the revenue currently generated by our Gathering, Processing & Terminalling segment depends on whether our customers actually use our services. A period of low usage will reduce our revenue in our Gathering, Processing & Terminalling segment and could result in an impairment of the goodwill at the Midstream Facilities reporting unit within this segment.
Many of our water business services and natural gas gathering and processing customers are not subject to "take or pay" obligations. Rather, a significant amount of the revenue currently generated by our Gathering, Processing & Terminalling segment depends on whether our customers actually use our services. If these customers do not utilize our services, revenue for our Gathering, Processing & Terminalling segment will decline.
For example, the decreased commodity prices since 2015 contributed to a significant drop in actual volumes from several producers from which TMID receives natural gas for processing. If processing volumes at TMID do not continue recovering over time, our revenue will decline in the Gathering, Process & Terminalling segment and we could have an impairment of the goodwill at the Midstream Facilities reporting unit within this segment.
We are exposed to direct commodity price risk in our Gathering, Processing & Terminalling segment, including certain of TMID's contracts and the utilization of commodity derivatives by Stanchion, and our exposure to direct commodity price risk may increase in the future.
TMID operates under three types of contracts, two of which directly expose our cash flows in the Gathering, Processing & Terminalling segment to increases and decreases in the price of natural gas and NGLs: percent of proceeds and keep whole processing contracts. We do not currently hedge the commodity exposure inherent in these types of processing contracts, and as a result, our revenues and results of operations are impacted by fluctuations in the prices of natural gas and NGLs.
Percent of proceeds processing contracts generally provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under keep whole processing contracts, our revenues and our cash flows generally increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for us to process natural gas under keep whole arrangements. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed at some of our plants. In addition, NGL prices have historically been related to the market price of oil and as a result any significant changes in oil prices could also indirectly impact our operations. Indirectly, reduced commodity prices impact us through reduced exploration and production activity, which results in fewer opportunities for new business to offset natural volume declines. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. For example, from the second half of 2014 through the first half of 2016, natural gas and crude oil prices declined substantially. Throughout 2019, the industry again experienced sustained lower natural gas prices. These declines directly and indirectly resulted in lower processing volumes and realizations on our percent of proceeds and keep whole processing contracts.
In 2017, we also began utilizing commodity derivatives in connection with the operations of our crude oil marketing subsidiary, Stanchion. Our portfolio of derivative and other energy contracts may consist of contracts to buy and sell commodities that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. If a performance failure were to occur in one of our contracts, we might incur losses in addition to amounts, if any, already recognized in our financial
statements or paid to, or received from, counterparties. As a result, our business, results of operations, financial condition and ability to pay quarterly cash dividends to our Class A shareholders may be adversely affected.
The TEP revolving credit facility and the indentures governing the TEP senior notes contain certain restrictions which could adversely affect our business, financial condition, results of operations and ability to make quarterly cash dividends to our Class A shareholders.
We are dependent upon certain earnings and cash flow generated by our operations in order to meet our debt service obligations. The TEP revolving credit facility, the indenture governing its 4.75% senior notes due 2023 (the "2023 Notes") the indenture governing its 5.50% senior notes due 2024 (the "2024 Notes"), and the indenture governing its 5.50% senior notes due 2028 (the "2028 Notes") contain, and any future financing agreements may contain, operating and financial restrictions and covenants that could restrict our ability to finance future operations or capital needs, or to expand or pursue our business activities, which may, in turn, limit our ability to make quarterly cash dividends. For example, the TEP revolving credit facility limits TEP's ability and the ability of its restricted subsidiaries to, among other things:
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incur or guarantee additional indebtedness;
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redeem or repurchase units or pay distributions under certain circumstances;
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make certain investments and acquisitions;
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incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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merge or consolidate with another company; and
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transfer, sell or otherwise dispose of assets.
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The TEP revolving credit facility also contains covenants requiring TEP to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that TEP will meet those ratios and tests. Further, TEP's obligations under the revolving credit facility are (i) guaranteed by TEP and each of its existing and subsequently acquired or organized direct or indirect wholly-owned domestic subsidiaries, subject to its ability to designate certain subsidiaries as "Unrestricted Subsidiaries," and (ii) secured by a first priority lien on substantially all of the present and after acquired property owned by TEP and each guarantor (other than real property interests related to its pipelines).
Similarly, the indenture governing the 2024 Notes contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all its properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates.
In addition, the indentures governing the 2023 Notes and the 2028 Notes contain covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all of its properties to, another person.
The provisions of the TEP revolving credit facility and the indentures governing its senior notes may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the TEP revolving credit facility or the indentures governing its senior notes, including a failure to meet any of the required financial ratios and tests, could result in a default or an event of default that could enable TEP's lenders or the holders of the senior notes to declare the outstanding principal of that indebtedness, together with accrued and unpaid interest, to be immediately due and payable, and in the case of the TEP revolving credit facility, would prohibit TEP's ability to make distributions. If the payment of the indebtedness under the TEP revolving credit facility is accelerated and we are unable to repay the indebtedness in full, the lenders could foreclose on the assets pledged by TEP and the guarantors under the TEP revolving credit facility. In that case, these assets may be insufficient to repay such indebtedness in full, and our Class A shareholders could experience a partial or total loss of their investment.
Our future indebtedness levels may limit our flexibility to obtain financing and to pursue other business opportunities.
Our level of indebtedness could have important consequences to us, including the following:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
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our funds available for operations, future business opportunities and dividends to Class A shareholders will be reduced by that portion of our cash flow required to make interest payments on our indebtedness;
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we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our flexibility in responding to changing business and economic conditions may be limited.
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Our ability to service our indebtedness depends upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. Taking any of these actions is likely to reduce the value of an investment in us. Plus, we may not be able to effect any of these actions on satisfactory terms or at all.
Increases in interest rates could adversely impact our Class A share price, our ability to issue equity or incur indebtedness for acquisitions or other purposes and our ability to make quarterly cash dividends at our intended levels.
The interest rate on borrowings under the TEP revolving credit facility float based upon one or more of the prime rate, the U.S. federal funds rate or LIBOR. As a result, those borrowings, as well as borrowings under possible future credit facilities or debt offerings, could be higher than current levels, causing our financing costs to increase accordingly. We do not currently hedge the interest rate risk on borrowings under the TEP revolving credit facility.
As with other yield-oriented securities, our Class A share price may be impacted by the level of our cash dividend and implied dividend yield. The dividend yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our Class A shares, and a rising interest rate environment could have an adverse impact on our Class A share price, our ability to issue equity or incur indebtedness for acquisitions or other purposes and our ability to maintain or increase quarterly cash dividends on our Class A shares.
Rockies Express has a substantial amount of indebtedness and Rockies Express may not be able to generate a sufficient amount of cash flow to meet its debt service obligations.
As of January 31, 2020, Rockies Express had $2.8 billion of senior notes outstanding, of which $750 million will mature on April 15, 2020 and are expected to be redeemed in March 2020, $400 million will mature in 2025, $550 million will mature in 2029, $350 million will mature in 2030, $250 million will mature in 2038 and $500 million will mature in 2040. Further, Rockies Express has a revolving credit facility with $150 million of borrowing capacity that matures in November 2024.
The substantial indebtedness held by Rockies Express could have important consequences. For example, it could:
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make it more difficult for Rockies Express to satisfy its obligations with respect to its indebtedness;
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increase the vulnerability of Rockies Express to general adverse economic and industry conditions;
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limit the ability of Rockies Express to obtain additional financing for future working capital, capital expenditures and other general business purposes;
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require Rockies Express to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of cash flow for operations and other purposes;
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limit its flexibility in planning for, or reacting to, changes in its business and the industry in which Rockies Express operates;
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place Rockies Express at a competitive disadvantage compared to its competitors that have less indebtedness; and
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have a material adverse effect if Rockies Express fails to comply with the covenants in the indenture relating to its notes or in the instruments governing its other indebtedness.
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Other than the indenture governing the senior notes due in 2025 and 2030, the terms of the indentures governing the existing Rockies Express notes do not restrict the amount of additional unsecured indebtedness Rockies Express may incur, and the agreements governing its revolving credit facility permit additional unsecured borrowings. If new indebtedness is added to the current indebtedness levels, these related risks could increase.
Rockies Express' ability to make scheduled payments or to refinance its obligations with respect to its indebtedness will depend on its financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business, and other factors beyond its control. In addition, a significant amount of Rockies Express' revenue in 2018 and 2019 was generated by long-term west-to-east contracts that have expired in 2019. The re-contracting of the capacity made available from these expirations has been at lower rates than those expiring contracts and we expect the re-contracting of any remaining capacity for west-to-east transport will also be at lower rates. As a result, we expect lower cash flows in periods subsequent to such contract expirations. We cannot assure you that Rockies Express' operating performance, cash flow and capital resources will be sufficient for payment of its indebtedness in the future. In the event that Rockies Express is required to dispose of
material assets or restructure its indebtedness to meet its debt service and other obligations, we cannot assure you as to the terms of any such transaction or how soon any such transaction could be completed.
If Rockies Express' cash flow and capital resources are insufficient to fund its debt service obligations, it may be forced to sell material assets, obtain additional capital, including through capital contributions from its members, or restructure its indebtedness. The payment of additional capital contributions by us to Rockies Express to fund such obligations would reduce the amount of cash available to make dividends to our Class A shareholders.
Rockies Express' revolving credit facility contains certain restrictions which could limit its financial flexibility and increase its financing costs.
Rockies Express' revolving credit facility contains restrictive covenants that may prevent it from engaging in various transactions that Rockies Express deems beneficial and that may be beneficial to Rockies Express. The revolving credit facility generally requires Rockies Express to comply with various affirmative and negative covenants, including a limit on the leverage ratio (as defined in each credit agreement) of Rockies Express and restrictions on:
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incurring secured indebtedness;
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entering into mergers, consolidations and sales of assets;
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entering into transactions with affiliates; and
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making restricted payments.
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Instruments governing any future indebtedness at Rockies Express may contain similar or more restrictive provisions. Rockies Express' ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.
We do not own most of the land on which our assets are located, which could disrupt our operations and subject us to increased costs.
We do not own in fee but rather have leases, easements, rights-of-way, permits, surface use agreements, and licenses for most of the land on which our assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid interests in the land, if such interests in the land lapse or terminate or if our facilities are not properly located within the boundaries of such interests in the land. For example, the West Frenchie Draw treating facility is located on land leased from the Wyoming Board of Land Commissioners pursuant to a contract that can be terminated at any time. Although many of these rights are perpetual in nature, we occasionally obtain the right to construct and operate pipelines on other owners' land for a specific period of time. If we were to be unsuccessful in renegotiating our leases, easements, rights-of-way, permits, surface use agreements and licenses, we might incur increased costs to maintain our assets, which could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash dividends to our Class A shareholders. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
Some leases, easements, rights-of-way, permits, surface use agreements and licenses for our assets are shared with other pipeline systems and other assets owned by third parties. We or owners of the other pipeline systems or assets may not have commenced or concluded eminent domain proceedings for some rights-of-way. In some instances, lands over which leases, easements, rights-of-way, permits, surface use agreements and licenses have been obtained are subject to prior liens which have not been subordinated to the grants to us.
Our interstate natural gas pipeline systems have federal eminent domain authority in certain instances. To the extent federal eminent domain authority is not available, the availability of eminent domain for future pipeline expansions varies from state to state, depending upon the laws of the particular state and in some states it may not be available at all. Regardless, we must compensate landowners for the use of their property, which may include any loss of value to the remainder of their property not being used by us, which are sometimes referred to as "severance damages." Severance damages are often difficult to quantify and their amount can be significant. In eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our crude oil or natural gas pipeline systems are located. In addition, the cost to voluntarily obtain rights-of-way from landowners has increased in recent years as landowners more frequently seek to collectively negotiate. For example, a number of landowner groups sought to negotiate collectively with respect to the Cheyenne Connector Pipeline project and in some instances, these groups also raised objections at the hearings held to consider the issuance of the land use permit from Weld County, Colorado. The collective efforts by such landowner groups added to the costs associated with acquisition of the right-of-way, delayed the issuance of a local land use permit from Weld County, Colorado and increased the risk that FERC would not issue a certificate of public convenience and necessity for the project.
A shortage of skilled labor in the midstream industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.
The transportation, storage and terminalling of crude oil, the transportation, storage and processing of natural gas, and the transportation, gathering, recycling and disposal of water requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs for employees, our results of operations could be materially and adversely affected.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A shares.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded company. 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, that we will be able to prevent fraud, 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.
New technologies, including those involving recycling of produced water or the replacement of water in fracturing fluid, may adversely affect our future results of operations and financial condition.
The produced water disposal industry is subject to the introduction of new waste treatment and disposal techniques and services using new technologies including those involving recycling of produced water, some of which may be subject to patent protection. As competitors and others use or develop new technologies or technologies comparable to our water business services in the future, we may lose market share or be placed at a competitive disadvantage. For example, some companies have successfully used propane as the fracturing fluid instead of water. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or products at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations or reduce the amount of waste produced in oil and natural gas drilling and production activities, thereby reducing or eliminating the need for third-party disposal. Limits on our ability to effectively use or implement new technologies, including in its water business services, may have a material adverse effect on our business, financial condition and results of operations.
Rockies Express is a joint venture and our investment could be adversely affected by our lack of sole decision-making authority.
We do not control Rockies Express through our ownership of a 75% membership interest. Under the limited liability company agreement of Rockies Express, substantially all matters are decided by a vote of 80% of the membership interests, other than certain fundamental decisions that require a vote of 90% of the membership interests. As a result, all the decisions of the Rockies Express members effectively require unanimous approval of us and the other member of Rockies Express, Phillips 66. Thus, our investment in Rockies Express involves risks that are not present when we are able to exercise control over an asset, including the possibility that the unaffiliated third-party member of Rockies Express might become bankrupt, fail to fund its required capital contributions or otherwise attempt to make business decisions with respect to Rockies Express that we do not believe are in its best interest. Moreover, under the Rockies Express limited liability company agreement, we are required to provide certain capital contributions in order to fund expenditures contemplated by Rockies Express' annual budget, and may be required to provide capital contributions under certain circumstances specified in the Rockies Express limited liability company agreement if determined to be reasonably necessary by a vote of Rockies Express' members.
As an unaffiliated third-party member of Rockies Express, Phillips 66 may have economic or other business interests or goals that are inconsistent with our business interests or goals. The Rockies Express limited liability company agreement expressly permits Rockies Express members to make decisions with respect to their ownership interest without taking into account the interests of Rockies Express or any other member of Rockies Express.
Our membership interest in Rockies Express is subject to a right of first refusal, which may make it more difficult to sell our interest in Rockies Express in the future.
Under the terms of Rockies Express' limited liability company agreement, if any member desires to transfer its membership interest to an unaffiliated third party, each other member first has a right to purchase its proportionate share of the membership interest being sold. If we desire to sell all or any portion of our interest in Rockies Express to an unaffiliated third-party in the future, we will be required to first offer the sale of our membership interest to the other member, who will have 30 days to elect to purchase their proportionate interest before any sale or transfer to a third party may be consummated. This requirement could make it difficult for us to sell our interest in Rockies Express.
Risks Inherent in an Investment in Us
Our quarterly cash dividends to our Class A shareholders are not cumulative.
Except as discussed in Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations, "Dividends," our quarterly cash dividends to our Class A shareholders are not cumulative. Consequently, if cash dividends on our Class A shares are not paid with respect to any fiscal quarter then our Class A shareholders will not be entitled to receive that quarter's payments in the future.
Our partnership agreement requires that we distribute our available cash on a quarterly basis, which could limit our ability to grow and make acquisitions.
Our partnership agreement requires us to distribute our available cash to our Class A shareholders on a quarterly basis. Accordingly, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we intend to dividend our available cash, subject to our agreement pursuant to the Take-Private Merger Agreement not to pay dividends during the pendency of the transactions contemplated by the Take-Private Merger Agreement, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional shares in connection with any acquisitions or expansion capital expenditures, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level. There are no limitations in our partnership agreement on our ability to issue additional shares, including shares ranking senior to the Class A shares. The incurrence of additional commercial borrowings or other indebtedness to finance our growth strategy would result in increased interest expense, which in turn may impact the cash available for dividends to our Class A shareholders.
If we issue additional Class A shares without canceling an equivalent number of Class B shares, Tallgrass Equity incurs additional debt, we incur debt or we or Tallgrass Equity are required to pay taxes, the payment of distributions on those additional Class A shares or interest on that debt or payment of such taxes could increase the risk that we will be unable to maintain or increase our cash dividend levels.
Restrictions in TEP's and Rockies Express' respective credit facilities and the indentures governing TEP's and Rockies Express' existing senior notes could limit their ability to make distributions, thereby limiting our ability to make quarterly cash dividends to our Class A shareholders. Any credit facility we enter into in the future could pose similar restrictions that would further limit our ability to make quarterly cash dividends.
TEP's and Rockies Express' respective credit facilities and the indentures governing TEP's and Rockies Express' existing senior notes contain various operating and financial restrictions and covenants. TEP's and Rockies Express' respective ability to comply with these restrictions and covenants may be affected by events beyond their control, including prevailing economic, financial and industry conditions. If TEP or Rockies Express are unable to comply with these restrictions and covenants, any indebtedness under these credit facilities and indentures may become immediately due and payable and TEP's and Rockies Express' respective lenders' commitment to make further loans under their revolving credit facilities may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.
We may enter into a credit facility in the future that would impose similar restrictions to those discussed above. In addition, our payment of principal and interest on any future indebtedness would reduce our cash available for dividends to our Class A shares.
For more information regarding the TEP revolving credit facility and the indentures governing TEP's existing senior notes, please see the section above "—The TEP revolving credit facility and the indentures governing the TEP senior notes contain certain restrictions which could adversely affect our business, financial condition, results of operations and ability to make quarterly cash dividends to our Class A shareholders." For more information regarding Rockies Express' revolving credit facility and the indentures governing Rockies Express' existing senior notes, please see the sections above "—Rockies Express has a substantial amount of indebtedness and Rockies Express may not be able to generate a sufficient amount of cash flow to
meet its debt service obligations." and "—Rockies Express' revolving credit facility contains certain restrictions which could limit its financial flexibility and increase its financing costs."
Our shareholders do not vote in the election of our general partner's directors. The Sponsor Entities own a sufficient number of shares to allow them to prevent the removal of our general partner and to strongly influence all other matters requiring shareholder approval.
Our shareholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Our general partner is responsible for conducting our business and managing our operations. Our shareholders do not have the ability to elect our general partner or the members of the board of directors of our general partner.
The members of the board of directors of our general partner, including the independent directors, are currently designated and elected by BIP through the exercise of the rights of the sole member of our general partner, subject only to certain contractual rights in the Equityholders Agreement entered into between certain affiliates of the Sponsor Entities and BIP's co-investors in March 2019 and limitations in the Take-Private Merger Agreement. As a result of these rights, including the ability to cause or prevent a change in the composition of the board of directors of our general partner or a change in control of TGE, BIP effectively controls our business and affairs.
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. As of December 31, 2019, the Sponsor Entities owned approximately 44.1% of the combined voting power of our Class A and Class B shares. This ownership level enables the Sponsor Entities to prevent our general partner's removal. In addition, with their combined voting power, the Sponsor Entities are able to strongly influence all other matters requiring shareholder approval, regardless of whether or not unaffiliated shareholders believe that the transaction is in their own best interests.
As a result of these provisions, the price at which our shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
Our general partner may cause us to issue additional Class A shares or other equity securities, including equity securities that are senior to our Class A shares, without your approval, which may adversely affect you.
Our general partner has the ability to cause us to issue an unlimited number of additional Class A shares, or other equity securities of equal rank with the Class A shares, without shareholder approval. In addition, we may issue an unlimited number of shares that are senior to our Class A shares in right of dividend, liquidation and voting. Except for Class A shares issued in connection with the exercise by any Exchange Right Holder of its right to exchange a Class B share for a Class A share (the "Exchange Right"), each of which will result in the cancellation of an equivalent number of Class B shares and therefore have no effect on the total 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:
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each shareholder's proportionate ownership interest in us may decrease;
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the amount of cash available for dividends on each Class A share may decrease;
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the relative voting strength of each previously outstanding Class A share may be diminished;
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the date upon which we begin paying material U.S. federal income taxes, or upon which a material portion of our dividends constitute taxable dividend income for U.S. federal income tax purposes, could be accelerated; and
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the market price of the Class A shares may decline.
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You may not have limited liability if a court finds that shareholder action constitutes control of our business.
Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our shareholders (who hold limited partner interests despite the fact that we use the term "shareholder" in this Annual Report) as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the "control" of our business. Additionally, the limitations on the liability of holders of limited partner interests for the liabilities of a limited partnership have not been clearly established in many jurisdictions.
Furthermore, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a shareholder may be liable to us for the amount of a dividend for a period of three years from the date of the dividend.
Our partnership agreement restricts the rights of shareholders owning 20% or more of our shares.
Our shareholders' voting rights are restricted by the provision in our partnership agreement generally providing that any shares held by a person or group that owns 20% or more of any class of shares then outstanding, other than our general partner or its affiliates and persons who acquired such shares with the prior approval of our general partner's board of directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our shareholders to call meetings or to acquire information about our operations, as well as other provisions limiting our shareholders' ability to influence the manner or direction of our management. As a result, the price at which our Class A shares trade may be lower because of the absence or reduction of a takeover premium in the trading price.
Future sales of our Class A shares in the public market, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, could reduce our Class A share price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
Subject to certain limitations and exceptions, the Exchange Right Holders may cause the exchange of their TE 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 in the public market. For example, certain participating Exchange Right Holders exercised their exchange right and sold 10,350,000 Class A shares in a secondary offering completed in November 2016. In addition, for the years ended December 31, 2019 and 2018, 21,751,018 Class A shares and 2,821,332 Class A shares, respectively, were issued and an equal number of Class B shares were canceled, as a result of the exercise of the exchange right. Further, in accordance with an amended and restated registration rights agreement entered into with the Exchange Right Holders, we have registered the resale of 125,291,659 Class A shares, 102,136,875 of which remain issuable upon exercise of the Exchange Right, pursuant to our Form S-3 (File No. 333-225382) filed with the SEC on June 1, 2018, which became effective June 13, 2018.
We may also issue additional Class A shares or convertible securities in subsequent public or private offerings. We cannot predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that future issuances and sales of our Class A shares, including sales of Class A shares by the Exchange Right Holders after the exercise of the Exchange Right, will have on the market price of our Class A shares. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.
A valuation allowance on our deferred tax asset could reduce our earnings.
A significant deferred tax asset was recorded as a result of certain reorganization transactions completed in connection with the TGE IPO. In November 2016, we completed a Secondary Offering of Class A shares, which resulted in the recognition of an additional deferred tax asset. The aggregate deferred tax asset was $318.2 million as of December 31, 2019. GAAP requires that a valuation allowance must be established for deferred tax assets when it is more likely than not that they will not be realized. If we were to determine that a valuation allowance was appropriate for our deferred tax asset, we would be required to take an immediate charge to earnings with a corresponding reduction of partners' equity and increase in balance sheet leverage as measured by debt to total capitalization.
The NYSE does not require a limited partnership like us to comply with certain of its corporate governance requirements.
Because we are a limited partnership, the NYSE does not require our general partner to have a majority of independent directors on its board of directors. The NYSE also does not require our general partner to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our shareholders do not have the same protections afforded to certain corporations that are subject to all the NYSE corporate governance requirements. In addition, as a limited partnership, we are not required to seek shareholder approval for issuances of Class A shares including issuances in excess of 20% of outstanding equity securities, or for issuances of equity to certain affiliates.
We may incur liability as a result of our ownership of TEP's general partner.
Under Delaware law, a general partner of a limited partnership is generally liable for the debts and liabilities of the partnership for which it serves as general partner, subject to the terms of any indemnification agreements contained in the partnership agreement and except to the extent the partnership's contracts are non-recourse to the general partner. As a result of our structure, we indirectly own and control the general partner of TEP. To the extent the indemnification provisions in TEP's partnership agreement or non-recourse provisions in our contracts are not sufficient to protect TEP GP from such liability, we may in the future incur liabilities as a result of our indirect ownership of TEP's general partner. Please read the section entitled "—Risks Related to Conflicts of Interest."
Risks Related to Conflicts of Interest
Our existing organizational structure and the relationships among us, our general partner, BIP, the Sponsor Entities, and their affiliated entities and owners present the potential for conflicts of interest. Moreover, additional conflicts of interest may arise in the future among us and the entities affiliated with any general partner or similar interests we acquire.
Conflicts of interest may arise as a result of our organizational structure and the relationships among us, our general partner, and its direct and indirect owners, which include BIP, the Sponsor Entities and their affiliated entities and owners.
Our partnership agreement defines the duties of our general partner (and, by extension, its officers and directors). Our general partner's board of directors or its conflicts committee has authority on our behalf to resolve any conflict involving us and they have broad latitude to consider the interests of all parties to the conflict.
Conflicts of interest may arise between us and our shareholders, on the one hand, and our general partner and its direct and indirect owners, on the other hand, which include BIP and its co-investors. The resolution of these conflicts may not always be in our best interest or that of our shareholders.
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. 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:
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how to allocate business opportunities among us and its affiliates;
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whether to exercise its limited call right;
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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;
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how to exercise its voting rights with respect to the units it owns; and
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whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.
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In addition, our partnership agreement provides that any construction or interpretation of our partnership agreement and any action taken pursuant thereto or any determination, in each case, made by our general partner in good faith, shall be conclusive and binding on all shareholders.
By purchasing shares, you agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to holders of our Class A shares for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to shareholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
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whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
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our general partner will not have any liability to us or our shareholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our shareholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
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approved by the conflicts committee of the board of directors of our general partner (although our general partner is not obligated to seek such approval);
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approved by the vote of a majority of the outstanding voting shares, excluding any shares owned by our general partner and its affiliates;
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determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
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determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
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In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our shareholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the last two bullets above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our general partner's affiliates 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 BIP, the Sponsor Entities, and their respective affiliates and owners, 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 or its affiliates, our general partner has the right (which it may assign to any of its affiliates or to us), but not the obligation, to acquire all, but not less than all, of the 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 or its affiliates for any shares purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those shares and (y) the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed. As a result, you may be required to sell your Class A shares at an undesirable time or price and may not receive any return of or on your investment. You may also incur a tax liability upon a sale of your Class A shares.
Tax Risks
The tax treatment of TEP depends on it not being subject to a material amount of entity-level taxation by individual states. If TEP becomes subject to material additional amounts of entity-level taxation for state tax purposes, it would reduce the amount of cash available for dividends to us and increase the portion of our dividends treated as taxable dividends.
We own a 63.75% membership interest in Tallgrass Equity as of February 12, 2020, which directly and indirectly owns all of the partnership interests in TEP. Accordingly, the value of our indirect investment in TEP, as well as the anticipated after-tax economic benefit of an investment in our Class A shares, depends largely on TEP being treated as a partnership for income tax purposes.
Several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such a tax on TEP by any state will reduce the cash available for distributions to TEP unitholders, likely causing a substantial reduction in the value of our Class A shares.
We may incur substantial corporate income tax liabilities on our allocable share of TEP income.
We are classified as a corporation for U.S. federal income tax purposes and, in most states in which TEP does business, for state income tax purposes. To the extent that TEP allocates to us net taxable income in any year, current law provides that we will be subject to U.S. federal income tax at a rate of 21%, and to state income tax at rates that vary from state to state. The amount of cash available for dividends to you will be reduced by the amount of any such income taxes payable by us for which we establish reserves.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income tax laws and transactional tax laws such as excise, sales/use, payroll, franchise and ad valorem tax laws. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Further, taxing authorities may change their application of existing taxes, so that additional entities or transactions may become subject to an existing tax. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional tax payments, as well as interest and penalties. In one such audit for a tax period from May 1, 2014 through April 30, 2015, the Ohio Tax Commissioner began assessing Rockies Express a public utility excise tax on transactions concerning product that entered and exited the Rockies Express Pipeline with the State of Ohio. Rockies Express disputed its obligation to pay Ohio's public utility excise tax under the relevant Ohio statute, but made payments in the amounts assessed for the 2015 tax period and subsequent tax periods in order to preserve its right to appeal. On February 11, 2020, the Ohio Supreme Court reached a final decision adverse to the position taken by Rockies Express. As a result, Rockies Express no longer anticipates receiving a refund of the prior payments made to the State of Ohio and expects to continue to be required to pay this tax in future tax periods. These excise taxes will reduce the cash available for dividends to our Class A shareholders, and any additional tax payments, interest and penalties that are successfully assessed by a taxing authority in the future as a result of an audit or otherwise, will also reduce the cash available for dividends to our Class A shareholders.
If the IRS makes audit adjustments to TEP's income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from TEP, in which case TEP may require its unitholders and former unitholders to reimburse it for such taxes (including any applicable penalties or interest) or, if TEP is required to bear such payment, TEP's cash available for distribution to TEP's unitholders might be substantially reduced.
If the IRS makes audit adjustments to TEP's income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from TEP. TEP will generally have the ability to shift any such tax liability to its general partner and its unitholders in accordance with their interests in TEP during the year under audit, but there can be no assurance that TEP will be able to (or will choose to) do so under all circumstances. If TEP is required to make payments of taxes, penalties and interest resulting from audit adjustments, it may require its unitholders and former unitholders to reimburse it for such taxes (including any applicable penalties or interest) or, if TEP is required to bear such payment, its cash available for distribution to its unitholders might be substantially reduced.
Taxable gain or loss on the sale of our Class A shares could be more or less than expected.
If a holder sells our Class A shares, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder's tax basis in those Class A shares. To the extent that the amount of our dividends exceeds our current and accumulated earnings and profits as determined for U.S. federal income tax purposes, the dividends will be treated as a tax-free return of capital and will reduce a holder's tax basis in the Class A shares. Because our dividends in excess of our earnings and profits decrease a holder's tax basis in Class A shares, such excess dividends will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A shares.
Our current tax treatment may change, which could affect the value of our Class A shares or reduce our cash available for dividends.
Changes in U.S. federal income tax law relating to our tax treatment as a corporation could result in (i) our being subject to additional taxation at the entity level with the result that we would have less cash available for dividends and (ii) a greater portion of our dividends being treated as taxable dividends. Moreover, we are subject to tax in numerous jurisdictions. Changes in current law in these jurisdictions, particularly relating to the treatment of deductions attributable to acquisitions of interests in Tallgrass Equity, could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for dividends.
Any decrease in our Class A share price could adversely affect our amount of cash available for dividends.
Changes in certain market conditions may cause our Class A share price to decrease. If the Exchange Right Holders exercise their Exchange Right when our Class A share price is less than the price at which the Class A shares were sold in the TGE IPO, the ratio of our income tax deductions to gross income would decline. This decline could result in our being subject to tax sooner than expected, our tax liability being greater than expected, or a greater portion of our dividends being treated as taxable dividends.
The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income with respect to our shares for U.S. federal income tax purposes, and failure to report your dividend income in a manner consistent with the IRS Form 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your U.S. federal income tax return. If you are a non-U.S. holder of our shares, your broker or other withholding agent may overwithhold taxes from dividends paid to you, in which case you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to claim a refund of the overwithheld taxes.
Dividends we pay with respect to our Class A shares will constitute "dividends" for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits as determined for U.S. federal income tax purposes. Dividends we pay in excess of our earnings and profits will not be treated as "dividends" for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of your tax basis in your shares and then as capital gain realized on the sale or exchange of such shares. We may be unable to timely determine the portion of our dividends that is a "dividend" for U.S. federal income tax purposes.
If you are a U.S. holder of our Class A shares, the IRS Form 1099-DIV may not be consistent with our determination of the amount that constitutes a "dividend" to you for U.S. federal income tax purposes or you may receive a corrected IRS Form 1099-DIV (and you may therefore need to file an amended federal, state or local income tax return). For example, we provided a corrected IRS Form 1099-DIV to applicable shareholders in August 2019 for dividends paid in 2018 following further review and revision of our initial estimates used to provide the original IRS Form 1099-DIV in February 2019. We will attempt to timely notify you of available information to assist you with your income tax reporting (such as posting the correct information on our website). However, the information that we provide to you may be inconsistent with the amounts reported to you by your broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your tax return.
If you are a non-U.S. holder of our Class A shares, "dividends" for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with your conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our dividends that is a "dividend" for U.S. federal income tax purposes, or your broker or withholding agent chooses to withhold taxes from dividends in a manner inconsistent with our determination of the amount that constitutes a "dividend" for such purposes, your broker or other withholding agent may overwithhold taxes from dividends paid to you. In such a case, you generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.
We expect that our ability to use net operating losses arising prior to the TEP Merger to offset future income will be limited as a result of the TEP Merger, and our ability to use net operating losses arising after the TEP Merger to offset future income may be limited.
We expect that our ability to use any net operating losses ("NOLs") generated by us prior to the TEP Merger to offset future income will be limited due to experiencing an "ownership change" as defined under Section 382 of the Code, as a result of the TEP Merger. Our ability to use NOLs arising after the TEP Merger to offset future income may be substantially limited if we were to experience another ownership change.
In general, an ownership change occurs if our "5-percent shareholders," as defined under Section 382 of the Code, including certain groups of persons treated as 5-percent shareholders, collectively increased their ownership in Class A shares by more than 50 percentage points over a rolling three-year period. An ownership change can occur as a result of a public offering of Class A shares, as well as through secondary market purchases of Class A shares and certain types of reorganization transactions. As a result of the exchange of TEP common units for Class A shares in the TEP Merger, we expect that the TEP Merger caused us to experience an ownership change.
A corporation (including any entity such as us that is treated as a corporation for U.S. federal income tax purposes) that experiences an ownership change will generally be subject to an annual limitation on the use of its pre-ownership change NOLs (and certain other losses and credits) equal to the equity value of the corporation immediately before the ownership change, multiplied by the long-term tax-exempt rate (as determined by the Internal Revenue Service) for the month in which the ownership change occurs. Such a limitation could, for any given year, have the effect of increasing the amount of our U.S. federal income tax liability, which would negatively impact the amount of after-tax cash available for dividends to holders of Class A shares and our financial condition.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
A description of our properties is contained in Item 1.—Business, "Our Assets" of this Annual Report.
Our principal executive offices are located at 4200 W. 115th Street, Suite 350, Leawood, KS 66211 and our telephone number is 913-928-6060.
We own two office buildings in Lakewood, Colorado, with a portion being leased to a third party pursuant to a lease with an initial term through March 2020. In addition, we lease our principal executive offices in Leawood, Kansas.
Item 3. Legal Proceedings
See Note 20 – Legal and Environmental Matters, which is incorporated by reference into this Part I—Item 3 of this Annual Report.
Item 4. Mine Safety Disclosures
Not applicable.