Item 1. Business.
Overview
Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”), to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. TRP is a leading provider of midstream natural gas and NGL services in the United States, with a growing presence in crude oil gathering and petroleum terminaling.
On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”), by and among us, Targa Resources GP LLC (our “general partner”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”) pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP (the “TRC/TRP Merger”), with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.
Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
As used herein, "units" refers to our units representing limited partner interests in the Partnership and not to the Preferred Units (as defined herein) and "unitholders" refers to the holders of units. Unless the context requires otherwise, the term "limited partner interests" refers to the units, the Preferred Units and the Incentive Distribution Rights (“IDRs”), collectively, and “limited partners” refers to the holders of limited partner interests.
The following should be read in conjunction with our audited consolidated financial statements and the notes thereto. We have prepared our accompanying consolidated financial statements under GAAP and the rules and regulations of the SEC. Our accounting records are maintained in U.S. dollars and all references to dollars in this report are to U.S. dollars, except where stated otherwise. Our consolidated financial statements include our accounts and those of our majority-owned and/or controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. The address of our principal executive offices is 811 Louisiana Street, Suite 2100, Houston, Texas 77002, and our telephone number at this address is (713) 584-1000.
Our Operations
We are engaged in the business of:
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gathering, compressing, treating, processing, transporting and selling natural gas;
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storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;
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gathering, storing, terminaling and selling crude oil; and
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storing, terminaling and selling refined petroleum products.
To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).
Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK plays) and South Central Kansas; the Williston Basin in North Dakota; and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and Marketing segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Marketing segment also includes the Grand Prix Pipeline (“Grand Prix”), as well as our equity interest in the Gulf Coast Express Pipeline (“GCX”), which are both currently under construction and expected to begin operations during 2019. Grand Prix, once operational, will integrate our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas. The associated assets, including these pipeline projects, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.
Acquisitions and Organic Growth Projects
Our midstream natural gas and NGL services footprint was initially established through several acquisitions from Targa, totaling $3.1 billion, that occurred from 2007 through 2010. Since the completion of the final acquisitions from Targa in 2010, we have expanded our midstream natural gas and NGL services footprint substantially. The expansion of our business has been fueled by a combination of third-party acquisitions and major organic growth investments in our businesses. Third-party acquisitions included our 2012 acquisition of Saddle Butte Pipeline LLC’s crude oil pipeline and terminal system and natural gas gathering and processing operations in North Dakota (referred to by us as “Badlands”), our 2015 acquisition of Atlas Pipeline Partners L.P. (“APL,” renamed by us as Targa Pipeline Partners LP or “TPL”), and our 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin (referred to by us as the “Permian Acquisition”). As a result of these transactions, we acquired natural gas gathering, processing and treating assets in West Texas, South Texas, North Texas, Oklahoma, North Dakota, New Mexico and the Louisiana Gulf Coast, crude oil gathering and terminal assets in North Dakota and West Texas, and NGL assets consisting of fractionation, transport, storage and terminaling facilities, low sulfur natural gas treating facilities (“LSNG”), pipeline transportation and distribution assets, propane storage and truck terminals primarily located near Houston, Texas and in Lake Charles, Louisiana.
We also continue to invest significant capital in our businesses and in Grand Prix, which connects many of our gathering and processing operations to our Downstream Business. We invested approximately $3.2 billion in growth capital expenditures in 2018. We expect to continue to invest in both large and small organic growth projects in 2019 and currently estimate that we will invest at least $2.3 billion in organic growth capital expenditures for announced projects in 2019.
The map below highlights our more significant assets:
Recent Developments
Gathering and Processing Segment Expansion
Permian Midland Processing Expansions
In response to increasing production and to meet the infrastructure needs of producers, we have announced the construction of additional processing plants that further expand the gathering and processing footprint of our Permian Midland systems. These plants were announced in, or completed in, 2018:
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In February 2018, we announced plans to construct two new cryogenic natural gas processing plants, each with a processing capacity of 250 MMcf/d. The first plant, known as the Hopson Plant, is expected to begin operations early in the second quarter of 2019. The second plant, known as the Pembrook Plant, is expected to begin operations late in the second quarter of 2019.
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In May 2017, we announced plans to build a 200 MMcf/d cryogenic natural gas processing plant, known as the Johnson Plant, which began operations in September 2018.
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In November 2016, we announced plans to build the 200 MMcf/d cryogenic natural gas processing plant, known as the Joyce Plant, which began operations in March 2018.
Permian Delaware Processing Expansions
In March 2018, we announced that we entered into long-term fee-based agreements with an investment grade energy company for natural gas gathering and processing services in the Delaware Basin and for downstream transportation, fractionation and other related services. The agreements are underpinned by the customer's dedication of significant acreage within a large, well-defined area in the Delaware Basin. We are constructing approximately 220 miles of 12- to 24-inch high-pressure rich gas gathering pipelines across the Delaware Basin and a new 250 MMcf/d cryogenic natural gas processing plant (the “Falcon Plant”) in the Delaware Basin that is expected to begin operations in the fourth quarter of 2019. We have also commenced acquiring long lead time items and have begun site preparation for a second 250 MMcf/d cryogenic natural gas processing plant (the “Peregrine Plant”) in the Delaware Basin that is expected to begin operations in the second quarter of 2020.
We will provide NGL transportation services on Grand Prix and fractionation services at our Mont Belvieu complex for a majority of the NGLs from the Falcon and Peregrine Plants. Total growth capital expenditures related to the plants and high-pressure pipeline system are expected to be approximately $500 million.
In May 2017, we announced plans to build a new plant and further expand the gathering footprint of our Permian Delaware systems. This project included a new 250 MMcf/d cryogenic processing plant, known as the Wildcat Plant, which began operations in May 2018. In addition, a 60 MMcf/d cryogenic processing plant, known as the Oahu Plant, was placed into service in April 2018.
Badlands
In January 2018, we announced the formation of a 50/50 joint venture with Hess Midstream Partners LP under which Targa will construct and operate a new 200 MMcf/d natural gas processing plant (the “LM4 Plant”) at Targa’s existing Little Missouri facility. The LM4 Plant is anticipated to be completed in the second quarter of 2019.
SouthOK Expansion
In May 2017, we acquired a 150 MMcf/d natural gas processing plant (the “Flag City Plant”) located in Jackson County, Texas, from subsidiaries of Boardwalk Midstream LLC. In December 2017, ownership of the Flag City Plant assets was transferred to Centrahoma Processing, LLC, a joint venture that we operate (“Centrahoma” or the “Centrahoma Joint Venture”), and in which we have a 60% ownership interest; the remaining 40% ownership interest is held by MPLX LP (“MPLX”). The former Flag City Plant assets have been relocated to, and installed in, Hughes County, Oklahoma, as a new 150 MMcf/d cryogenic natural gas processing plant (the “Hickory Hills Plant”). The Hickory Hills Plant processes natural gas production from the Arkoma Woodford Basin and began operations in December 2018. In October 2018, Targa contributed the 120 MMcf/d cryogenic Tupelo Plant in Coal County, Oklahoma to Centrahoma. In conjunction with Targa’s contribution of both the Hickory Hills and Tupelo plant assets, MPLX made cash contributions to Centrahoma in order to maintain its 40% ownership interest in the expanded operations.
Eagle Ford Shale Natural Gas Gathering and Processing Joint Venture
In May 2018, Sanchez Midstream Partners LP (“Sanchez Midstream”) and we merged our respective 50% interests in the Carnero gathering and Carnero processing joint ventures, which own the high-pressure Carnero gathering line and Raptor natural gas processing plant, to form an expanded 50/50 joint venture in South Texas (the “Carnero Joint Venture”) that we operate. In connection with the joint venture merger transactions, the Carnero Joint Venture acquired our 200 MMcf/d Silver Oak II natural gas processing plant located in Bee County, Texas, which increased the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d. Additional enhancements to the prior joint ventures included dedication of over 315,000 additional gross acres in the Western Eagle Ford, operated by Sanchez Energy Corporation (“Sanchez Energy” or “SN”), under a new long-term firm gas gathering and processing agreement. Including the initial dedication of approximately 105,000 gross acres (the “Catarina acreage”), the joint venture now has over 420,000 gross acres under a long-term dedication.
Downstream Segment Expansion
Grand Prix NGL Pipeline
In May 2017, we announced plans to construct a new common carrier NGL pipeline. The pipeline will transport NGLs from the Permian Basin and North Texas to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported by our volumes and other third-party customer volume commitments, and is expected to be fully in service in the third quarter of 2019.
In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the "Grand Prix Joint Venture"), which owns the portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas, to funds managed by Blackstone Energy Partners (“Blackstone”). We are the operator and construction manager of Grand Prix.
Concurrent with the sale of the minority interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC ("EagleClaw"), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw dedicated and committed significant NGLs associated with EagleClaw's natural gas volumes produced or processed in the Delaware Basin.
Grand Prix NGL Pipeline Extension into Oklahoma
In March 2018, we announced an extension of Grand Prix into southern Oklahoma. The pipeline expansion is supported by long-term commitments of NGLs for both transportation and fractionation from our existing and future processing plants in the Arkoma area in our SouthOK system and from third-party commitments, including a long-term commitment of NGLs for transportation and fractionation with Valiant Midstream, LLC. The extension of Grand Prix into southern Oklahoma is not part of the Grand Prix Joint Venture.
The capacity of the 24-inch diameter pipeline segment from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d. The pipeline segment from the Permian Basin will be connected to a 30-inch diameter pipeline segment in North Texas where Permian, North Texas and Oklahoma volumes will be connected to Mont Belvieu, and will have capacity of approximately 450 MBbl/d, expandable to 950 MBbl/d. The capacity from Oklahoma to North Texas will vary based on telescoping pipe size.
In February 2019, we announced an extension of Grand Prix from southern Oklahoma to the STACK region of Central Oklahoma where it will connect with Williams’ new Bluestem Pipeline and link the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. Williams will also have an initial option to purchase a 20% equity interest in one of our recently announced fractionation trains (Train 7 or Train 8) in Mont Belvieu. This Grand Prix extension is expected to be completed in the first quarter of 2021.
Grand Prix volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in the Blackstone and Grand Prix DevCo (as defined below) joint venture arrangements, while the volumes flowing from North Texas and Oklahoma to Mont Belvieu accrue solely to Targa’s benefit.
Total growth capital spending on Grand Prix, including the extensions into Oklahoma, is now estimated to be approximately $1.9 billion, with our portion of growth capital spending estimated to be approximately $1.3 billion.
Fractionation Expansion
In February 2018, we announced plans to construct a new 100 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 6”), which is expected to begin operations in the second quarter of 2019. The total cost of the fractionation train and related infrastructure is expected to be approximately $350 million.
In November 2018, we announced plans to construct two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7 and Train 8”), which are expected to begin operations in the first quarter of 2020 and second quarter of 2020, respectively. The total cost of these fractionation trains and related infrastructure is expected to be approximately $825 million.
LPG Export Expansion
In February 2019, we announced plans to further expand our LPG export capabilities of propane and butanes at our Galena Park Marine Terminal by increasing refrigeration capacity and load rates. Our current effective export capacity of 7 MMBbl per month will increase to approximately 11 to 15 MMBbl per month, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors. The total cost of the expansion and related infrastructure is expected to be approximately $120 million and is expected to be completed in the third quarter of 2020.
Gulf Coast Express Pipeline
In December 2017, we entered into definitive joint venture agreements with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP (“DCP”) with respect to the joint development of the Gulf Coast Express Pipeline, a natural gas pipeline from the Waha hub, including direct connections to the tailgate of many of our Midland Basin processing facilities, to Agua Dulce in South
Texas. The pipeline will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. We and DCP each own a 25% interest and KMTP owns a 35% interest in GCX. In December 2018, Altus Midstream Company exercised their option to purchase the remaining 15% interest, which was originally held by KMTP. KMTP will serve as the construction manager and operator of GCX. We have committed significant volumes to GCX. In addition, Pioneer Natural Resources Company (“Pioneer”), a joint owner in our WestTX Permian Basin assets, has committed volumes to the project. GCX is designed to transport up to 1.98 Bcf/d of natural gas and the total cost of the project is estimated to be approximately $1.75 billion. GCX is expected to be in service in the fourth quarter of 2019, pending regulatory approvals.
Development Joint Ventures
In February 2018, we also announced the formation of three development joint ventures (the “DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”). Stonepeak owns an 80% interest in both the GCX DevCo JV, which owns our 25% interest in GCX, and the Train 6 DevCo JV, which owns a 100% interest in certain assets associated with Train 6. Stonepeak owns a 95% interest in the Grand Prix DevCo JV, which owns a 20% interest in the Grand Prix Joint Venture. We hold the remaining interest of each DevCo JV, as well as control the management, construction and operation of Grand Prix and the fractionation train. The Train 6 DevCo JV will fund the fractionation train while we will fund 100% of the required brine, storage and other infrastructure that will support the fractionation train’s operations.
Stonepeak committed a maximum of approximately $960 million of capital to the DevCo JVs, including an initial contribution of approximately $190 million that was distributed to the Partnership to reimburse it for a portion of capital spent to date.
For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, we have the option to acquire all or part of Stonepeak’s interests in the DevCo JVs. We may acquire up to 50% of Stonepeak’s invested capital in multiple increments with a minimum of $100 million, and Stonepeak’s remaining 50% interest in a single final purchase. The purchase price payable for such partial or full interests would be based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs.
Channelview Splitter
On December 27, 2015, we and Noble Americas Corp., then an affiliate of Noble Group Ltd., entered into a long-term, fee-based agreement (the “Splitter Agreement”) under which we would build and operate a 35,000 Bbl/d crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (the “Channelview Splitter”). In January 2018, Vitol US Holding Co. (“Vitol”) acquired Noble Americas Corp. In December 2018, Vitol elected to terminate the Splitter Agreement.
The Channelview Splitter is currently in the process of start-up and commissioning and has an estimated total cost of approximately $160 million. The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d of crude oil and condensate into its various components, including naphtha, distillate, gas oil, kerosene/jet fuel and liquefied petroleum gas and will provide segregated storage for the crude and condensate and each of their components. We are working on third-party contracts and commercialization of the Channelview Splitter.
Asset Sales and Divestitures
During the second quarter of 2018, we sold our inland marine barge business to a third party for approximately $69 million. We continue to own and operate two ocean-going barges.
During the third quarter of 2018, we executed agreements to sell our refined products and crude oil storage and terminaling facilities in Tacoma, Washington, and Baltimore, Maryland, to a third party for approximately $165 million. The sale closed in the fourth quarter of 2018 and the proceeds were used to repay debt and to fund a portion of our growth capital program.
In February 2019, we entered into definitive agreements to sell a 45% interest in Targa Badlands LLC, the entity that holds all of our assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities for $1.6 billion. We will continue to be the operator of Targa Badlands LLC and will hold majority governance rights. Future growth capital is expected to be funded on a pro rata basis. Targa Badlands LLC will pay a minimum quarterly distribution to Blackstone and to Targa based on their initial investments, and Blackstone’s capital contributions will have a liquidation preference upon a sale of Targa Badlands LLC. We expect to use the net cash proceeds to pay down debt and for general corporate purposes, including funding our growth capital program. The transaction is expected to close in the second quarter of 2019 and is subject to customary regulatory approvals and closing conditions.
Financing Activities
In April 2018, we issued $1.0 billion aggregate principal amount of 5⅞% senior notes due 2026 (the “5⅞% Senior Notes due 2026”). We used the net proceeds of $991.9 million after costs from this offering to repay borrowings under our credit facilities and for general partnership purposes.
On October 29, 2018, Standard & Poor’s Corporation (“S&P”) raised Targa’s corporate credit rating and our issue-level rating on senior unsecured notes to 'BB' from 'BB-', and raised the outlook to positive from stable.
On December 7, 2018, we amended and extended our accounts receivable securitization facility (the “Securitization Facility”) to increase the facility size from $350.0 million to $400.0 million with a termination date of December 6, 2019.
In January 2019, we issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of $1,488.8 million. The net proceeds from the offerings were used to redeem in full our outstanding senior notes due 2019 and the remainder is expected to be used for general partnership purposes, which may include repaying borrowings under our credit facilities or other indebtedness, funding growth investments and acquisitions, and working capital.
TRP Revolver Amendment
In June 2018, we entered into an agreement to amend and restate the TRP Revolver, which extended the maturity date from October 2020 to June 2023, increased available commitments from $1.6 billion to $2.2 billion and lowered the applicable margin range and commitment fee range used in the calculation of interest. Our ability to request additional commitments of $500.0 million remained unchanged.
The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin (a) before the collateral release date, ranging from 0.25% to 1.25% dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (b) upon and after the collateral release date, ranging from 0.125% to 0.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The Eurodollar rate is equal to LIBOR rate plus an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The TRP Revolver also provides for the release of collateral and a concurrent reduction in loan and commitment fee margins should we achieve certain credit ratings.
We are required to pay a commitment fee equal to an applicable rate ranging from (a) before the collateral release date, 0.25% to 0.375% (dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and (b) upon and after the collateral release date, 0.125% to 0.35% (dependent on our non-credit-enhanced senior unsecured long-term debt ratings) times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The TRP Revolver’s covenants remained substantially the same.
Organization Structure
On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership (the “Third A&R Partnership Agreement”), effective as of December 1, 2016. As a result of the TRC/TRP Merger, Targa owns all of the outstanding TRP common units. Targa also maintains a 2% general partner interest in us. In connection with the Third A&R Partnership Agreement, TRP issued to our general partner: (i) 20,380,286 common units and 424,590 General Partner units in exchange for the cancellation of the IDRs and (ii) 11,267,485 common units and 234,739 General Partner units in exchange for cancellation of the Special GP Interest. The Partnership Agreement with us governs our relationship regarding certain reimbursement and indemnification matters. See “Item 13. Certain Relationships and Related Transactions and Director Independence.”
Targa has used us as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL, crude oil and other complementary energy businesses and assets as evidenced by our acquisitions of businesses from Targa. However, Targa is not prohibited from competing with us and may evaluate acquisitions and dispositions that do not involve us. In addition, through our relationship with Targa, we have access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to Targa’s broad operational, commercial, technical, risk management and administrative infrastructure.
We do not have any employees to carry out our operations. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than its direct support costs of being a separate reporting company and its cost of providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa for cost allocations to the extent that they have required a current cash outlay by Targa. See “-Employees” for further information.
The diagram below shows our corporate structure as of February 21, 2019, which reflects the effect of the TRC/TRP Merger:
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Common shares outstanding as of February 21, 2019.
Growth Drivers
We believe that our near-term growth will be driven by organic projects being placed into service, as well as the level of producer activity in the basins where our gathering and processing infrastructure is located and the level of demand for services provided by our Downstream Business. We believe our assets are not easily duplicated and are located in many attractive and active areas of exploration and production activity and are near key markets and logistics centers. Over the longer term, we expect our growth will continue to be driven by the strong position of our quality assets which will benefit from production from shale plays and by the deployment of shale exploration and production technologies in both liquids-rich natural gas and crude oil resource plays that will also provide additional opportunities for our Downstream Business. We expect that organic growth and third-party acquisitions will continue to be a focus of our growth strategy.
Attractive Asset Positions
We believe that our positioning in some of the most attractive basins will allow us to capture increased natural gas supplies for gathering and processing, increased NGLs for transportation and fractionation and increased crude oil supplies for gathering and terminaling. Producers continue to focus drilling activity on their most attractive acreage, especially in the Permian Basin where we have a large and well positioned footprint, and are benefiting from increasing activity as rigs have been added in the basin in and around our systems.
The development of shale and unconventional resource plays has resulted in increasing NGL supplies that continue to generate demand for our fractionation services at the Mont Belvieu market hub and for LPG export services at our Galena Park Marine Terminal on the Houston Ship Channel. Since 2010, in response to increasing demand we added 278 MBbl/d of additional fractionation capacity with the additions of Cedar Bayou Fractionator (“CBF”) Trains 3, 4 and 5, and have additional capacity of 320 MBbl/d under construction. Trains 6, 7 and 8 are expected to begin operations in the second quarter of 2019, first quarter of 2020 and second quarter of 2020, respectively. We believe that the higher volumes of fractionated NGLs will also result in increased demand for other related fee-based services provided by our Downstream Business. Continued demand for fractionation capacity is expected to lead to other future growth opportunities.
As domestic producers have focused their drilling in crude oil and liquids-rich areas, new gas processing facilities are being built to accommodate liquids-rich gas, which results in an increasing supply of NGLs. As drilling in these areas continues, the supply of NGLs requiring transportation and fractionation to market hubs is expected to continue. As the supply of NGLs increases, our integrated Mont Belvieu and Galena Park Marine Terminal assets allow us to provide the raw product, fractionation, storage, interconnected terminaling, refrigeration and ship loading capabilities to support exports by third-party customers. Grand Prix will transport volumes from the Permian Basin and our North Texas and southern Oklahoma systems to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas, further enhancing the integration of our gathering and processing assets with our Downstream Business. Grand Prix positions us to offer an integrated midstream service across the NGL value chain to our customers by linking supply to key markets. Grand Prix is expected to be fully in service in the third quarter of 2019.
Drilling and production activity from liquids-rich natural gas shale plays and similar crude oil resource plays
We are actively pursuing natural gas gathering and processing and NGL fractionation opportunities associated with liquids-rich natural gas from shale and other resource plays and are also actively pursuing crude gathering and natural gas gathering and processing and NGL fractionation opportunities from active crude oil resource plays. We believe that our leadership position in the Downstream Business, which includes our fractionation and export services and will be complemented by Grand Prix, provides us with a competitive advantage relative to other midstream companies without these capabilities.
Organic growth and third-party acquisitions
While our growth through 2010 was primarily driven by the implementation of a focused drop down strategy, we have a demonstrated track record of completing organic growth and third-party acquisitions. Since 2010, we have executed on approximately $8.3 billion of growth capital projects and approximately $7.2 billion in third-party acquisitions. We expect to continue to grow both organically and through third-party acquisitions.
Competitive Strengths and Strategies
We believe that we are well positioned to execute our business strategies due to the following competitive strengths:
Strategically located gathering and processing asset base
Our gathering and processing businesses are strategically located in attractive oil and gas producing basins and are well positioned within each of those basins. Activity in the shale resource plays underlying our gathering assets is driven by the economics of oil, condensate, gas and NGL production from the particular reservoirs in each play. Activity levels for most of our gathering and processing assets are driven primarily by commodity prices. If drilling and production activities in these areas continue, the volumes of natural gas and crude oil available to our gathering and processing systems will likely increase.
Leading fractionation, LPG export and NGL infrastructure position
We are one of the largest fractionators of NGLs in the Gulf Coast. Our fractionation assets are primarily located in Mont Belvieu, Texas, and to a lesser extent Lake Charles, Louisiana, which are key market centers for NGLs. Our logistics operations at Mont Belvieu, the major U.S. hub of NGL infrastructure, include connections to a number of mixed NGL (“mixed NGLs” or “Y-grade”) supply pipelines, storage, interconnection and takeaway pipelines and other transportation infrastructure. Our logistics assets, including fractionation facilities, storage wells, low ethane propane de-ethanizer, and our Galena Park Marine Terminal and related pipeline systems and interconnects, are also located near and connected to key consumers of NGL products including the petrochemical and industrial markets. Once in service, Grand Prix will connect the very active Permian Basin to Mont Belvieu. The location and interconnectivity of these assets are not easily replicated, and we have additional capability to expand their capacity. We have extensive experience in operating these assets and developing, permitting and constructing new midstream assets.
Comprehensive package of midstream services
We provide a comprehensive package of services to natural gas and crude oil producers. These services are essential to gather crude; gather, process and treat wellhead gas to meet pipeline standards; and extract, transport and fractionate NGLs for sale into petrochemical, industrial, commercial and export markets. We believe that our ability to offer these integrated services provides us with an advantage in competing for new supplies because we can provide substantially all of the services that producers, marketers and others require for moving natural gas, NGLs and crude oil from wellhead to market on a cost-effective basis. Both Grand Prix and GCX further enhance our position to offer an integrated midstream service across the natural gas and NGL value chain by linking supply to key markets. Additionally, we believe the barriers to enter the midstream sector on a scale similar to ours are reasonably high due to the high cost of replicating or acquiring assets in key strategic positions and the difficulty of developing the expertise necessary to operate them.
High quality and efficient assets
Our gathering and processing systems and logistics assets consist of high-quality, well-maintained facilities, resulting in low-cost, efficient operations. Advanced technologies have been implemented for processing plants (primarily cryogenic units utilizing centralized control systems), measurement systems (essentially all electronic and electronically linked to a central data-base) and operations and maintenance management systems to manage work orders and implement preventative maintenance schedules (computerized maintenance management systems). These applications have allowed proactive management of our operations resulting in lower costs and minimal downtime. We have established a reputation in the midstream industry as a reliable and cost-effective supplier of services to our customers and have a track record of safe, efficient, and reliable operation of our facilities. We will continue to pursue new contracts, cost efficiencies and operating improvements of our assets. Such improvements in the past have included new production and acreage commitments, reducing fuel gas and flare volumes and improving facility capacity and NGL recoveries. We will also continue to optimize existing plant assets to improve and maximize capacity and throughput.
In addition to routine annual maintenance expenses, our maintenance capital expenditures have averaged approximately $107 million per year over the last three years. We believe that our assets are well-maintained and anticipate that a similar level of maintenance capital expenditures will be sufficient for us to continue to operate our existing assets in a prudent, safe and cost-effective manner.
Large, diverse business mix with favorable contracts and increasing fee-based business
We maintain gas gathering and processing positions in strategic oil and gas producing areas across multiple basins and provide these and other services under attractive contract terms to a diverse mix of producers across our areas of operation. Consequently, we are not dependent on any one oil and gas basin or counterparty. Our Logistics and Marketing assets are typically located near key market hubs and near most of our NGL customers. They also serve must-run portions of the natural gas value chain, are primarily fee-based and have a diverse mix of customers.
Our contract portfolio has attractive rate and term characteristics including a significant fee-based component, especially in our Downstream Business. Our expected continued growth of the fee-based Downstream Business may result in increasing fee-based cash flow. The Permian Acquisition resulted in increased fee-based cash flow as the entities acquired have primarily fee-based gathering and processing contracts.
Financial flexibility
We have historically maintained sufficient liquidity and have funded our growth investments with a mix of equity and debt over time in order to manage our leverage ratio. Disciplined management of liquidity, leverage and commodity price volatility allow us to be flexible in our long-term growth strategy and enable us to pursue strategic acquisitions and large growth projects.
Experienced and long-term focused management team
Our current executive management team possesses breadth and depth of experience working in the midstream energy business. Most of our executive management team has been with us since the Partnership was formed in 2006, joined shortly thereafter or managed many of our businesses prior to acquisition by Targa. Other officers and key operational, commercial and financial employees have significant experience in the industry and with our assets and businesses.
Attractive cash flow characteristics
We believe that our strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows. Geographic, business and customer diversity enhances our cash flow profile. Our Gathering and Processing segment has a contract mix that is primarily percent-of-proceeds (whereby we receive an agreed upon percentage of the actual proceeds of specified commodities). However, our Gathering and Processing segment contract mix also has increasing components of fee-based margin driven by: (i) fees added to percent-of-proceeds contracts for natural gas treating and compression, (ii) new/amended contracts with a combination of percent-of-proceeds and fee-based components, and (iii) essentially fully fee-based crude oil gathering and gas gathering and processing in certain areas where fee-based contracts are prevalent such as the Williston Basin, South Oklahoma, South Texas and parts of the Permian Basin. Contracts in our Coastal Gathering and Processing segment are primarily hybrid contracts (percent-of-liquids with a fee floor) or percent-of-liquids contracts (whereby we receive an agreed upon percentage of the actual proceeds of the NGLs). Contracts in the Downstream Business are predominately fee-based (based on volumes and contracted rates), with a large take-or-pay component. Our contract mix, along with our commodity hedging program, serves to mitigate the impact of commodity price movements on cash flow.
We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures, purchased puts (or floors) and costless collars. The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and to mitigate the impact of fluctuations in commodity prices on cash flow. We have intentionally tailored our hedges to approximate specific NGL products and to approximate our actual NGL and residue natural gas delivery points. Although the degree of hedging will vary, we intend to continue to manage some of our exposure to commodity prices by entering into similar hedge transactions. We also monitor and manage our inventory levels with a view to mitigate losses related to downward price exposure.
Asset base well-positioned for organic growth
We believe that our asset platform and strategic locations allow us to maintain and potentially grow our volumes and related cash flows as our supply areas benefit from continued exploration and development over time. Technology advances have resulted in increased domestic oil and liquids-rich gas drilling and production activity. The location of our assets provides us with access to natural gas and crude oil supplies and proximity to end-user markets and liquid market hubs while positioning us to capitalize on drilling and production activity in those areas. We believe that as global supply and demand for natural gas, crude oil and NGLs, and services for each grows over the long term, our infrastructure will increase in value as such infrastructure takes on increasing importance in meeting that growing supply and demand.
While we have set forth our strategies and competitive strengths above, our business involves numerous risks and uncertainties which may prevent us from executing our strategies. These risks include the adverse impact of changes in natural gas, NGL and condensate/crude oil prices, the supply of or demand for these commodities, and our inability to access sufficient additional production to replace natural declines in production. For a more complete description of the risks associated with an investment in us, see “Item 1A.
Item 1A. Risk Factors.
Limited partner interests are inherently different from 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. The nature of our business activities subjects us to certain hazards and risks. You should consider carefully the following risk factors together with all the other information contained in this report. If any of the following risks were to occur, then our business, financial condition, cash flows and results of operations could be materially adversely affected.
We have a substantial amount of indebtedness which may adversely affect our financial position.
We have a substantial amount of indebtedness. As of December 31, 2018, we had $5,223.0 million outstanding of our senior unsecured notes and $54.6 million of outstanding senior notes of TPL, excluding $0.3 million of unamortized net discounts and premiums. We also had $280.0 million outstanding under our Securitization Facility. In addition, we had $700.0 million of borrowings outstanding, $79.5 million of letters of credit outstanding and $1,420.5 million of additional borrowing capacity available under the TRP Revolver. Our $2.2 billion TRP Revolver allows us to request increases in commitments up to an additional $500 million. For the years ended December 31, 2018, 2017 and 2016, our consolidated interest expense, net was $170.0 million, $217.8 million and $233.5 million.
In January 2019, we issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of approximately $1,488.8 million. The net proceeds from the offerings were used to redeem in full our outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date and the remainder is expected to be used for general partnership purposes, which may include repaying borrowings under our credit facilities or other indebtedness, funding growth investments and acquisitions and working capital.
This substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments, could have other 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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satisfying our obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;
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we will need a portion of cash flow to make interest payments on debt, reducing the funds that would otherwise be available for operations and future business opportunities;
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our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.
Our long-term unsecured debt is currently rated by Standard & Poor’s Corporation (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”). As of December 31, 2018, Targa’s senior unsecured debt was rated “BB” by S&P. As of December 31, 2018, Targa’s senior unsecured debt was rated “Ba3” by Moody’s. Any future downgrades in our credit ratings could negatively impact our cost of raising capital, and a downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public markets.
Our ability to service our debt will depend 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 or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital, and such results may adversely affect our ability to make cash distributions. We may not be able to affect any of these actions on satisfactory terms, or at all.
Despite current indebtedness levels, we may still be able to incur substantially more debt. This could increase the risks associated with compliance with our financial covenants.
We may be able to incur substantial additional indebtedness in the future. The TRP Revolver allows us to request increases in commitments up to an additional $500 million. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. If we incur additional debt, this could increase the risks associated with compliance with our financial covenants.
Increases in interest rates could adversely affect our business.
We have significant exposure to increases in interest rates. As of December 31, 2018, our total indebtedness was $6,257.6 million, excluding $0.3 million of net premiums and $32.6 million of net debt issuance costs, of which $5,277.6 million was at fixed interest rates and $980.0 million was at variable interest rates. A one percentage point increase in the interest rate on our variable interest rate debt would have increased our consolidated annual interest expense by approximately $9.8 million based on our December 31, 2018 debt balances. As a result of this amount of variable interest rate debt, our financial condition could be negatively affected by increases in interest rates.
The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.
The agreements governing our outstanding indebtedness contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interests. These agreements include covenants that, among other things, restrict our ability to:
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incur or guarantee additional indebtedness or issue additional preferred units;
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pay distributions on our equity securities or to our equity holders or redeem, repurchase or retire our equity securities or subordinated indebtedness;
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make investments and certain acquisitions;
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sell or transfer assets, including equity securities of our subsidiaries;
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engage in affiliate transactions,
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consolidate or merge;
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incur liens;
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prepay, redeem and repurchase certain debt, subject to certain exceptions;
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enter into sale and lease-back transactions or take-or-pay contracts; and
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change business activities conducted by us.
In addition, certain of our debt agreements require us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.
A breach of any of these covenants could result in an event of default under our debt agreements. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. For example, if we are unable to repay the accelerated debt under the TRP Revolver, the lenders under the TRP Revolver could proceed against the collateral granted to them to secure that indebtedness. If we are unable to repay the accelerated debt under the Securitization Facility, the lenders under the Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged the assets and equity of certain of our subsidiaries as collateral under the TRP Revolver and the accounts receivables of Targa Receivables LLC under the Securitization Facility. If the indebtedness under our debt agreements is accelerated, we cannot assure you that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.
Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.
Our operations can be affected by the level of natural gas and NGL prices and the relationship between these prices. The prices of crude oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. Our future cash flow may be materially adversely affected if we experience significant, prolonged price deterioration. The markets and prices for crude oil, natural gas and NGLs depend upon factors beyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:
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the impact of seasonality and weather;
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general economic conditions and economic conditions impacting our primary markets;
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the economic conditions of our customers;
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the level of domestic crude oil and natural gas production and consumption;
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the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;
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actions taken by foreign oil and gas producing nations;
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the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs;
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the availability and marketing of competitive fuels and/or feedstocks;
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the impact of energy conservation efforts;
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stockholder activism and activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas; and
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the extent of governmental regulation and taxation.
Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. For the year ended December 31, 2018, our percent-of-proceeds arrangements accounted for approximately 69.0% of our gathered natural gas volume. Under these arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Changes in future business conditions could cause recorded goodwill to become further impaired, and our financial condition and results of operations could suffer if there is an additional impairment of goodwill or other intangible assets with indefinite lives, intangible assets with definite lives, or property, plant and equipment assets.
We evaluate goodwill for impairment at least annually, as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not the fair value of a reporting unit is less than its carrying amount. Global oil and natural gas commodity prices, particularly crude oil, have declined substantially as compared to mid-2014 and remain volatile. Decreases in commodity prices have previously had, and could continue to have, a negative impact on the demand for our services and our market capitalization.
Should energy industry conditions deteriorate, there is a possibility that goodwill may be impaired in a future period. Any additional impairment charges that we may take in the future could be material to our financial statements. We cannot accurately predict the amount and timing of any impairment of goodwill. For a further discussion of our goodwill impairments, see Note 7 - Goodwill of the “Consolidated Financial Statements” included in this Annual Report.
We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.
Many of our customers may experience financial problems that could have a significant effect on their creditworthiness, especially in a depressed commodity price environment. A decline in natural gas, NGL and crude oil prices may adversely affect the business, financial condition, results of operations, creditworthiness, cash flows and prospects of some of our customers. 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. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from a decline in commodity prices, a reduction in borrowing bases under reserve-based 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 payment or perform on their obligations to us. Additionally, a decline in the share price of some of our public customers may place them in danger of becoming delisted from a public securities exchange, limiting their access to the public capital markets and further restricting their liquidity. 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. 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. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues. Any material nonpayment or nonperformance by our key customers or our derivative counterparties could reduce our ability to make distributions to our unitholders.
Because of the natural decline in production in our operating regions and in other regions from which we source NGL supplies, our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.
Our gathering systems are connected to crude oil and natural gas wells from which production will naturally decline over time, which means that the cash flows associated with these sources of natural gas and crude oil will likely also decline over time. Our logistics assets are similarly impacted by declines in NGL supplies in the regions in which we operate as well as other regions from which we source NGLs. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas, NGL and crude oil supplies. A material decrease in natural gas or crude oil production from producing areas on which we rely, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas or crude oil that we process, NGL products delivered to our fractionation facilities or crude oil that we gather. Our ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successful drilling and production activity near our gathering systems and, in part, on the level of successful drilling and production in other areas from which we source NGL and crude oil supplies. We have no control over the level of such activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling, completion or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital.
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling and production activity generally decreases as crude oil and natural gas prices decrease. Prices of crude oil and natural gas have been historically volatile, and we expect this volatility to continue. Consequently, even if new natural gas or crude oil reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. For example, current low prices for natural gas combined with relatively high levels of natural gas in storage could result in curtailment or shut-in of natural gas production. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which we operate may prevent us from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes from existing wells, which could result in reduced volumes through our facilities and reduced utilization of our gathering, treating, processing and fractionation assets.
If we do not make acquisitions or develop growth projects for expanding existing assets or constructing new midstream assets on economically acceptable terms, or fail to efficiently and effectively integrate acquired or developed assets with our asset base, our future growth will be limited. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to make distributions to our limited partners. In addition, we may not achieve the expected results of any acquisitions and any adverse conditions or developments related to such acquisitions may have a negative impact on our operations and financial condition.
Our ability to grow depends, in part, on our ability to make acquisitions or develop growth projects that result in an increase in cash generated from operations. We are unable to acquire businesses from Targa in order to grow because Targa’s only assets currently are the interests in us that Targa owns. As a result, we will need to focus on third-party acquisitions and organic growth. If we are unable to make accretive acquisitions or develop accretive growth projects because we are (1) unable to identify attractive acquisition candidates and negotiate acceptable acquisition agreements or develop growth projects economically, (2) unable to obtain financing for these acquisitions or projects on economically acceptable terms, or (3) unable to compete successfully for acquisitions or growth projects, then our future growth and ability to increase distributions will be limited.
Any acquisition or growth project involves potential risks, including, among other things:
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operating a significantly larger combined organization and adding new or expanded operations;
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difficulties in the assimilation of the assets and operations of the acquired businesses or growth projects, especially if the assets acquired are in a new business segment and/or geographic area;
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the risk that crude oil and natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
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the failure to realize expected volumes, revenues, profitability or growth;
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the failure to realize any expected synergies and cost savings;
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coordinating geographically disparate organizations, systems and facilities;
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the assumption of environmental and other unknown liabilities;
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limitations on rights to indemnity from the seller in an acquisition or the contractors and suppliers in growth projects;
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the failure to attain or maintain compliance with environmental and other governmental regulations;
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inaccurate assumptions about the overall costs of equity or debt;
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the diversion of management’s and employees’ attention from other business concerns;
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challenges associated with joint venture relationships and minority investments, including dependence on joint venture partners, controlling shareholders or management who may have business interests, strategies or goals that are inconsistent with ours; and
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customer or key employee losses at the acquired businesses or to a competitor.
If these risks materialize, any acquired assets or growth project may inhibit our growth, fail to deliver expected benefits and/or add further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition or growth project. If we consummate any future acquisition or growth project, our capitalization and results of operations may change significantly and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions or growth projects.
Our acquisition and growth strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants and new opportunities created by industry expansion. A material decrease in such divestitures or in opportunities for economic commercial expansion would limit our opportunities for future acquisitions or growth projects and could adversely affect our operations and cash flows available for distribution to our limited partners.
Acquisitions may significantly increase our size and diversify the geographic areas in which we operate and growth projects may increase our concentration in a line of business or geographic region. We may not achieve the desired effect from any future acquisitions or growth projects.
Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. For example, the construction of additional systems may be delayed or require greater capital investment if the commodity prices of certain supplies, such as steel pipe, increase due to imposed tariffs. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, fractionation facility or gas processing plant, the construction may occur over an extended period of time and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct pipelines or facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing pipelines or facilities in such area. To the extent we rely on estimates of future production in any decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new pipelines or facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights of way prior to constructing new pipelines. We may be unable to obtain or renew such rights of way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights of way or to renew existing rights of way. If the cost of renewing or obtaining new rights of way increases, our cash flows could be adversely affected.
Our acquisition and growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow through acquisitions or growth projects.
We continuously consider and enter into discussions regarding potential acquisitions and growth projects. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders. These factors may impair our ability to execute our acquisition and growth strategy.
In addition, we are experiencing increased competition for the types of assets we contemplate purchasing or developing. Current economic conditions and competition for asset purchases and development opportunities could limit our ability to fully execute our acquisition and growth strategy.
Demand for propane is significantly impacted by weather conditions and therefore seasonal and requires increases in inventory to meet seasonal demand.
Weather conditions have a significant impact on the demand for propane because domestic end-users principally utilize propane for heating purposes. Warmer-than-normal temperatures in one or more regions in which we operate can significantly decrease the total volume of propane we sell. Lack of consumer domestic demand for propane may also adversely affect the retailers with which we transact our wholesale propane marketing operations, exposing us to retailers’ inability to satisfy their contractual obligations to us.
If our general partner loses any of its named executive officers, our business may be adversely affected.
Our success is dependent upon the efforts of the named executive officers of our general partner. The named executive officers of our general partner are responsible for executing our business strategies. There is substantial competition for qualified personnel in the midstream natural gas industry. Our general partner may not be able to retain its existing named executive officers or fill new positions or vacancies created by expansion or turnover. Our general partner has not entered into employment agreements with any of its named executive officers. In addition, it does not maintain “key man” life insurance on the lives of any of its named executive officers. A loss of one or more of the named executive officers of our general partner could harm our business and prevent us from implementing our business strategies.
We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our business.
We operate in areas in which industry activity has increased rapidly. As a result, demand for qualified personnel in these areas, particularly those related to our Permian and Badlands assets, and the cost to attract and retain such personnel, has increased over the past few years due to competition, and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development projects, or any significant increases in costs with respect to the hiring, training or retention of qualified personnel, could have a material adverse effect on our business, financial condition and results of operations.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.
Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financial reporting capabilities. These enhancements require a significant commitment of resources, personnel and the development and maintenance of formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting now or in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002.
Any failure to maintain effective controls or difficulties encountered in the effective improvement of our internal controls could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our results of operations, financial condition and ability to comply with our debt obligations.
If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.
We may not be successful in balancing our purchases and sales of the commodities we handle. In addition, a producer could fail to deliver promised volumes to us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between our purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.
Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodity volumes that are hedged decreases substantially over time.
We have entered into derivative transactions related to only a portion of our equity volumes, future commodity purchases and sales, and transportation basis risk. As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity. The percentages of our expected equity volumes that are covered by our hedges decrease over time. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. The derivative instruments we utilize for these hedges are based on posted market prices, which may be higher or lower than the actual natural gas, NGL and condensate prices that we realize in our operations. These pricing differentials may be substantial and could materially impact the prices we ultimately realize. Market and economic conditions may adversely affect our hedge counterparties’ ability to meet their obligations. Given volatility in the financial and commodity markets, we may experience defaults by our hedge counterparties. In addition, our exchange traded futures are subject to margin requirements, which creates variability in our cash flows as commodity prices fluctuate.
As a result of these and other factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and processing facilities become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be adversely affected.
We depend upon third-party pipelines, storage and other facilities that provide delivery options to and from our gathering and processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, our revenues could be adversely affected.
Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large crude oil, natural gas and NGL companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than we do. Some of these competitors may expand or construct gathering, processing, storage, terminaling and transportation systems that would create additional competition for the services we provide to our customers. In addition, customers who are significant producers of natural gas may develop their own gathering, processing, storage, terminaling and transportation systems in lieu of using those operated by us. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.
We typically do not obtain independent evaluations of natural gas or crude oil reserves dedicated to our gathering pipeline systems; therefore, supply volumes on our systems in the future could be less than we anticipate.
We typically do not obtain independent evaluations of natural gas or crude oil reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of supply, then the volumes of natural gas or crude oil transported on our gathering systems in the future could be less than we anticipate. A decline in the volumes on our systems could have a material adverse effect on our business, results of operations and financial condition.
A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel or export markets, or a significant increase in NGL product supply relative to this demand, could materially adversely affect our business, results of operations and financial condition.
The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry-specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), reduced demand for propane or butane exports whether for price or other reasons, increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Also, increased supply of NGL products could reduce the value of NGLs handled by us and reduce the margins realized. Our NGL products and their demand are affected as follows:
Ethane. Ethane is typically supplied as purity ethane and as part of an ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream, thereby reducing the volume of NGLs delivered for fractionation and marketing.
Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is increasingly driven by international exports supplying a growing global demand for the product. Domestically in the U.S., propane is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of slow global economic growth and warmer-than-normal weather.
Normal Butane. Normal butane is used in the production of isobutane, as a refined petroleum product blending component, as a fuel gas (either alone or in a mixture with propane) and in the production of ethylene and propylene. Changes in the composition of refined petroleum products resulting from governmental regulation, changes in feedstocks, products and economics, and demand for heating fuel, ethylene and propylene could adversely affect demand for normal butane. The volume of butane sold is increasingly driven by international exports supplying a growing demand for the product.
Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.
Natural Gasoline. Natural gasoline is used as a blending component for certain refined petroleum products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation, and in demand for ethylene and propylene, could adversely affect demand for natural gasoline.
NGLs and products produced from NGLs also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect both demand for the services we provide and NGL prices, which could negatively impact our results of operations and financial condition.
We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.
We do not own most of the land on which our pipelines, terminals and compression facilities 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 rights of way or leases or if such rights of way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Additionally, following a decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights of way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights of way or obtain new rights of way without experiencing significant costs. Any loss of rights with respect to our real property, through our inability to renew rights of way contracts or leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce our revenue.
We may be unable to cause our majority-owned joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.
We participate in several majority-owned joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities include, among others, large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business. Without the concurrence of joint venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not take certain actions, even though taking or preventing those actions may be in our best interests or the particular joint venture.
In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in our partnering with different or additional parties.
We may operate a portion of our business with one or more joint venture partners where we own a minority interest and/or are not the operator, which may restrict our operational and corporate flexibility. Actions taken by the other partner or third-party operator may materially impact our financial position and results of operations, and we may not realize the benefits we expect to realize from a joint venture.
As is common in the midstream industry, we may operate one or more of our properties with one or more joint venture partners where we own a minority interest and/or contract with a third party to control operations. These relationships could require us to share operational and other control, such that we may no longer have the flexibility to control completely the development of these properties. If we do not timely meet our financial commitments in such circumstances, our rights to participate may be adversely affected. If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator does not operate in accordance with our expectations, our costs of operations could be increased. We could also incur liability as a result of actions taken by a joint venture partner or third-party operator. Disputes between us and the other party may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.
Weather may limit our ability to operate our business and could adversely affect our operating results.
The weather in the areas in which we operate can cause disruptions and in some cases suspension of our operations. For example, unseasonably wet weather, extended periods of below freezing weather, or hurricanes may cause disruptions or suspensions of our operations, which could adversely affect our operating results. Some forecasters expect that potential climate changes may have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events and could have an adverse effect on our operations.
Our business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.
Our operations are subject to many hazards inherent in gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; gathering, storing and terminaling crude oil; and storing and terminaling refined petroleum products, including:
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damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;
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inadvertent damage from third parties, including from motor vehicles and construction, farm or utility equipment;
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damage that is the result of our negligence or any of our employees’ negligence;
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leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
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spills or other unauthorized releases of natural gas, NGLs, crude oil, other hydrocarbons or waste materials that contaminate the environment, including soils, surface water and groundwater, and otherwise adversely impact natural resources; and
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other hazards that could also result in personal injury, loss of life, pollution and/or suspension of operations.
These risks could result in substantial losses due to personal injury, loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental or natural resource damage, and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to our business. Additionally, while we are insured for pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. For example, following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that could be obtained prior to such hurricanes. Insurance market conditions worsened as a result of the losses sustained from Hurricanes Gustav and Ike. As a result, we experienced further increases in deductibles and premiums, and further reductions in coverage and limits, with some coverage unavailable at any cost.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to the authority under the NGPSA and HLPSA, as amended from time to time, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain natural gas and hazardous liquids pipelines that, in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. Among other things, these regulations require operators of covered pipelines to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquids pipelines. We currently estimate an average annual cost of $2.6 million between 2019 and 2021 to implement pipeline integrity management program testing along certain segments of our natural gas and hazardous liquids pipelines. This estimate does not include the costs, if any, of repair, remediation or preventative or mitigative actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, in January 2017, PHMSA issued a final rule for hazardous liquid pipelines that significantly extends and expands the reach of certain PHMSA integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a high consequence area. The final rule also requires all pipelines in or affecting a high consequence area to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure. The timing for implementation of this rule has been delayed and remains uncertain at this time due to the change in U.S. Presidential administrations. In a second example, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines, including, among other things, the imposition of increased integrity management requirements. PHMSA has not yet finalized the March 2016 proposed rulemaking. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation services.
Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.
We sell processed natural gas at plant tailgates or at pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. We attempt to balance sales with volumes supplied from processing operations, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose us to volume imbalances which, in conjunction with movements in commodity prices, could materially impact our income from operations and cash flow.
Our operations are subject to environmental and occupational health and safety laws and regulations and a failure to comply or an accidental release into the environment may cause us to incur significant costs and liabilities.
Our operations are subject to numerous federal, tribal, state and local environmental laws and regulations governing occupational health and safety, the discharge of pollutants into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including acquisition of a permit or other approval before conducting regulated activities, restrictions on the types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmentally sensitive areas such as wetlands, urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements, imposing specific health and safety standards addressing worker protection and imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA, OSHA and BLM, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, which can often require difficult and costly actions. Failure to comply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting or performance of projects, and the issuance of orders enjoining or conditioning performance of some or all of our operations in a particular area. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or waste products have been released, even under circumstances where the substances, hydrocarbons or waste have been released by a predecessor operator or the activities conducted and from which a release emanated complied with applicable law.
The risk of incurring environmental costs and liabilities in connection with our operations is significant due to our handling of natural gas, NGLs, crude oil and other petroleum products, because of air emissions and product-related discharges arising out of our operations, and as a result of historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations. Moreover, stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. The adoption of any laws, regulations or other legally enforceable mandates that result in more stringent air emission limitations or that restrict or prohibit the drilling of new oil or natural gas wells for any extended period of time could increase our oil and natural gas customers’ operating and compliance costs as well as reduce the rate of production of natural gas or crude oil from operators with whom we have a business relationship, which could have a material adverse effect on our results of operations and cash flows. See “Item 1. Business -Regulation of Operations-Environmental and Operational Health and Safety Matters” for additional information regarding regulatory developments with respect to environmental regulations.
Laws and regulations regarding hydraulic fracturing could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets.
While we do not conduct hydraulic fracturing, many of our customers do perform such activities. Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion of certain oil and natural gas wells whereby water, sand or alternative proppant, and chemical additives are injected under pressure into subsurface formations to stimulate the flow of certain oil and natural gas, increasing the volumes that may be recovered. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over, proposed or promulgated regulations governing, and conducted investigations relating to certain aspects of the process, including the EPA and the BLM. For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. Moreover, some states have adopted, and others are considering adopting, legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities, assess more taxes, fees or royalties on natural gas production, or otherwise limit the use of the technique. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Moreover, non-governmental organizations may seek to restrict hydraulic fracturing, such as was the case in Colorado where certain interest groups therein have unsuccessfully pursued ballot initiatives in recent general election cycles that, had they been successful, would have revised the state constitution or state statutes in a manner that would have made exploration and production activities in the state more difficult or expensive in the future, including, for example, by increasing mandatory setbacks of oil and natural gas operations from occupied structures and environmentally-sensitive areas. New or more stringent laws, regulations or regulatory or ballot initiatives relating to the hydraulic fracturing process could lead to our customers reducing crude oil and natural gas drilling activities using hydraulic fracturing techniques, while increased public opposition to activities using such techniques may result in operational delays, restrictions, cessations, or increased litigation. Any one or more of such developments could reduce demand for our gathering, processing and fractionation services and have a material adverse effect on our business, financial condition and results of operations.
A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase or delay or increase the cost of expansion projects.
With the exception of the Driver Residue Pipeline, TPL SouthTex Transmission pipeline, Tarzan 311 residue line, Agua Blanca 311 line, and Targa Midland 311 line, which are each subject to limited FERC regulation under either the NGA or NGPA, our natural gas pipeline operations are generally exempt from FERC regulation, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses, including certain FERC reporting and posting requirements in a given year. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. We also operate natural gas pipelines that extend from some of our processing plants to interconnections with both intrastate and interstate natural gas pipelines. Those facilities, known in the industry as “plant tailgate” pipelines, typically operate at transmission pressure levels and may transport “pipeline quality” natural gas. Because our plant tailgate pipelines are relatively short, we treat them as “stub” lines, which are exempt from FERC’s jurisdiction under the Natural Gas Act.
Targa NGL and Grand Prix Joint Venture have pipelines that are considered common carrier pipelines subject to regulation by FERC under ICA. The ICA requires that we maintain tariffs on file with FERC for each of the Targa NGL and Grand Prix Joint Venture pipelines that have not been granted a waiver. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and non-discriminatory. With respect to pipelines that have been granted a waiver of the ICA and related regulations by FERC, should a particular pipeline’s circumstances change, FERC could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies for a waiver. In the event that FERC were to determine that one or more of these pipelines no longer qualified for a waiver, we would likely be required to file a tariff with FERC for the applicable pipeline(s), provide a cost justification for the transportation charge, and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on these pipelines could adversely affect our results of operations.
In addition, the courts have determined that certain pipelines that would otherwise be subject to the ICA are exempt from regulation by FERC under the ICA as proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordingly, the classification and regulation of some of our gathering facilities and transportation pipelines may be subject to change based on future determinations by FERC, the courts or Congress, in which case, our operating costs could increase and we could be subject to enforcement actions under the EP Act of 2005.
Various federal agencies within the U.S. Department of the Interior, particularly the BLM, Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate a significant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands can generally be subject to the Native American tribal court system. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.
Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity. For more information regarding the regulation of our operations, see “Item 1. Business-Regulation of Operations.”
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the EP Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for violations of the NGA or NGPA, respectively, up to approximately $1.27 million (adjusted annually for inflation) per day for each violation and disgorgement of profits associated with any violation. While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmission pipeline, Tarzan 311 residue line, Agua Blanca 311 line, and Targa Midland 311 line, have not been regulated by FERC under the NGA or NGPA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability. In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA of up to approximately $13,000 per violation per day, and failure to comply with the ICA and regulations implementing the ICA could subject us to civil penalty liability. For more information regarding regulation of our operations, see “Item 1. Business-Regulation of Operations.”
The adoption and implementation of climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the products and services we provide.
Climate change continues to attract considerable public and scientific attention in the United States and in foreign countries. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
In the United States, no comprehensive climate change legislation has been implemented at the federal level, to date. However, the EPA has adopted rules under authority of the CAA that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting "best available control technology" standards for those GHG emissions. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities such as, for example, gathering, compression and boosting facilities as well as blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. For example, in 2016, the EPA published New Source Performance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously EPA-issued New Source Performance Standards known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, in June 2017, the EPA published a proposed rule to stay certain portions of the 2016 standards for two years but the rule has not been finalized. Rather, in February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule. These rules, should they remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our and our customers’ operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business.
On the international level, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (“Paris Agreement”) for nations to limit their GHG emissions through individually-determined reduction goals every five years beginning in 2020. In August 2017, however, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement, which provides for a four-year exit process beginning when the agreement took effect in November 2016.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our products and services. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Finally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
In 2016, President Obama signed the 2016 Pipeline Safety Act that extends PHMSA’s statutory mandate regarding pipeline safety through 2019 and requires PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act. The 2011 Pipeline Safety Act had directed the promulgation of regulations relating to such matters as expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. The 2016 Pipeline Safety Act also called for the development of new safety standards for natural gas storage facilities by June 22, 2018 and empowered PHMSA to address unsafe conditions or practices constituting imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA published an interim rule in October 2016 to implement the agency's expanded authority to address imminent hazards to life, property, or the environment.
The imposition of new safety enhancement requirements pursuant to the 2016 Pipeline Safety Act and the 2011 Pipeline Safety Act or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. For example, in 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards; and requiring consideration of seismicity in evaluating threats to pipelines. In 2018, PHMSA announced that it had separated the 2016 rulemaking into three proceedings and the agency is expected to finalize these proceedings in 2019. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation. The safety enhancement requirements and other provisions of the 2016 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs or operational delays that could have a material adverse effect on our results of operation or financial position.
Additionally, PHMSA and one or more state regulators, including the RRC, have in recent years expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, to assess compliance with hazardous liquids pipeline safety requirements. To the extent that PHMSA and/or state regulatory agencies are successful in asserting their jurisdiction in this manner, midstream operators of NGL fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA PSM and EPA RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.
Portions of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our systems, which expenditures or resulting loss of revenue due to pipeline age or condition could have a material adverse effect on our business and results of operations.
Some portions of the pipeline systems that we operate have been in service for several decades prior to our purchase of them. Consequently, there may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of some of our pipeline systems could also 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 some portions of our pipeline systems could adversely affect our business and results of operations.
The implementation of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized most of these regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.
In November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The rules were re-proposed in December 2016. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. The CFTC and the federal banking regulators have adopted regulations requiring certain counterparties to swap to post initial and variation margin. However, our current hedging activities would qualify for the non-financial end user exemption from the margin requirements.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until all of the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts or increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices.
Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
The European Union (the “EU”) and other non-U.S. jurisdictions are also implementing regulations with respect to the derivatives market. To the extent we enter into swaps with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to or otherwise impacted by such regulations. As is the case with the Dodd-Frank Act and the regulations promulgated under it, the implementing regulations adopted by the EU and by other non-U.S. jurisdictions could have an adverse effect on us, our financial condition and our results of operations.
Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.
The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general and on us in particular is not known at this time. However, resulting regulatory requirements and/or related business decisions associated with security are likely to increase our costs. Additionally, destructive forms of protest and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural gas development, production and midstream transportation activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our or our customers’ operations, which may adversely affect the demand for our services or our financial condition and results of operations.
Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets, or indirect casualties, of an act of terror.
Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage or coverage may be reduced or unavailable. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct business. For example, we depend on digital technologies to operate our facilities, serve our customers and record financial data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers, customers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could adversely disrupt our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to enhance our security posture and cybersecurity defenses or to investigate and remediate any vulnerability to or consequences of cyber incidents. Our insurance coverages for cyberattacks may not be sufficient to cover all the losses we may experience as a result of a cyber incident.
Risks Related to Our Structure
Targa owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Targa has conflicts of interest with us and may favor its own interests to your detriment.
All of our general partner’s directors and all of its executive officers are directors or officers of Targa. Therefore, conflicts of interest may arise between Targa, including our general partner, on the one hand, and us and our limited partners, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests over the interests of our limited partners. These conflicts include, among others, the following situations:
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neither our partnership agreement nor any other agreement requires Targa to pursue a business strategy that favors us. Targa’s directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Targa, which may be contrary to our interests; and
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our general partner is allowed to take into account the interests of parties other than us, such as Targa or its owners, in resolving conflicts of interest.
Targa is not limited in its ability to compete with us and is under no obligation to offer assets it may acquire to us, which could limit our ability to acquire additional assets or businesses.
Our partnership agreement does not prohibit Targa from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Targa may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competition from Targa could adversely impact our results of operations and cash available for distribution.
The credit and business risk profile of our general partner could adversely affect our credit ratings and profile.
The credit and business risk profiles of our general partner may be factors in credit evaluations of us. This is because our general partner can exercise significant influence over our business, including our cash distribution and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness.
Targa, the owner of our general partner and all of our common units, is dependent on the cash distributions from its indirect general partner and limited partner equity interests in us to provide working capital. Any distributions by us to such entities will be made only after satisfying our then-current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or more risky than ours.
Our partnership agreement limits our general partner’s fiduciary duties to our limited partners and restricts the remedies available to limited partners for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, Targa. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of or factors affecting us;
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provides that our general partner does not have any liability to us or our limited partners for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of limited partners must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties, or must be “fair and reasonable” to us, as determined by our general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
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provides that our general partner and its officers and directors are not liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons 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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provides that in resolving conflicts of interest, it is presumed that in making its decision our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Your liability may not be limited if a court finds that limited partner action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Our partnership is organized under Delaware law and we conduct business in Louisiana, Texas, Oklahoma and North Dakota as well as other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or that your right to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Limited partners may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, limited partners may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to limited partners if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Risks Related to the Preferred Units
We cannot assure you that we will be able to pay distributions on our Preferred Units regularly, and the agreements governing our indebtedness may limit the cash available to make distributions on the Preferred Units.
Subject to the limitations on restricted payments contained in our indentures and in our senior secured credit agreement, we distribute all of our “available cash” each quarter to our limited partners and our general partner. “Available cash” is defined in our partnership agreement and described below under “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities-Distributions of Available Cash-Definition of Available Cash.” As a result, we do not expect to accumulate significant amounts of cash. Depending on the timing and amount of our cash distributions, these distributions could significantly reduce the cash available to us in subsequent periods to make payments on the Preferred Units.
The Preferred Units are subordinated to our existing and future debt obligations, and could be diluted by the issuance of additional units, including additional Preferred Units, and by other transactions.
The Preferred Units are subordinated to all of our existing and future indebtedness (including indebtedness outstanding under our senior secured credit facility, our existing senior notes and indebtedness outstanding under our Securitization Facility). The payment of principal and interest on our debt reduces cash available for distribution to us and on our units, including the Preferred Units. The issuance of additional units pari passu with or senior to the Preferred Units would dilute the interests of the holders of the Preferred Units, and any issuance of Senior Securities or Parity Securities (each as defined in our partnership agreement) or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Preferred Units.
Our ability to issue parity securities in the future could adversely affect the rights of holders of our Preferred Units.
We are allowed to issue additional Preferred Units and parity securities without any vote of the holders of the Preferred Units, except where the cumulative distributions on the Preferred Units or any parity securities are in arrears. The issuance of additional Preferred Units or any parity securities would have the effect of reducing the amounts available to the holders of the outstanding Preferred Units upon our liquidation, dissolution or winding up if we do not have sufficient funds to pay all liquidation preferences of the Preferred Units and parity securities in full. It also would reduce amounts available to make distributions on the outstanding Preferred Units if we do not have sufficient funds to pay distributions on all outstanding Preferred Units and parity securities.
In addition, although holders of Preferred Units are entitled to limited voting rights, with respect to certain matters the Preferred Units will generally vote separately as a class along with all other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Preferred Units may be significantly diluted, and the holders of such other series of Parity Securities that we may issue may be able to control or significantly influence the outcome of any vote. Future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Preferred Units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.
Tax Risks to Holders of Preferred Units
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to you may be substantially reduced.
A publicly traded partnership such as us may be treated as a corporation for U.S. federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is 21% for tax years beginning after December 31, 2017, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions instead of as guaranteed payments for the use of capital, as described further below. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you may be substantially reduced. Therefore, the treatment of us as a corporation may result in a material reduction in the anticipated cash flow.
At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income and franchise taxes and other forms of taxation. For example, we are subject to the Texas franchise tax at a maximum effective rate of 0.75% of our gross income apportioned to Texas in the prior year.
Holders of Preferred Units should consult their tax advisor with respect to the consequences of owning our Preferred Units.
The tax treatment of publicly traded partnerships or an investment in our Preferred Units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in us, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including a prior legislative proposal that would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. Although there are no current legislative or administrative proposals, there can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in us. You are urged to consult with your own tax advisor with respect to the status of legislative or administrative developments and proposals and their potential effect on your investment in our Preferred Units.
The tax treatment of distributions on our Preferred Units as guaranteed payments for the use of capital is uncertain and such distributions will likely not be eligible for the 20% deduction for qualified publicly traded partnership income.
The tax treatment of distributions on our Preferred Units is uncertain. We will treat the holders of Series A Preferred Units as partners for tax purposes and will treat distributions on the Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Preferred Units as ordinary income. We anticipate accruing and making guaranteed payment distributions on a monthly basis. However, the accrual of such a guaranteed payment is not contingent upon a cash distribution, and holders of Preferred Units will recognize taxable income from such accrual even in the absence of a contemporaneous cash distribution. Otherwise, the holders of Preferred Units are generally neither anticipated to share in our items of income, gain, loss or deduction, nor be allocated any share of our nonrecourse liabilities. If the Preferred Units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Preferred Units.
Although we expect that much of the income we earn is generally eligible for the 20% deduction for qualified publicly traded partnership income, a guaranteed payment for the use of capital does not constitute an allocable or distributive share of such income under proposed Treasury Regulations. As a result, if the proposed Treasury Regulations are finalized as written, the guaranteed payment for the use of capital received by the holders of Preferred Units will not be eligible for the 20% deduction for qualified publicly traded partnership income.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our Preferred Units that may result in adverse tax consequences to them.
Investment in the Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. Although the issue is not free from doubt, we will treat distributions to non-U.S. holders of the Preferred Units as “effectively connected income” (which will subject holders to U.S. net income taxation and possibly the branch profits tax) that are subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. holders. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders may be required to file U.S. federal income tax returns in order to seek a refund of such excess. Non-U.S. holders of Preferred Units who sell or otherwise dispose of a Preferred Unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that Preferred Unit. The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued.
Furthermore, the treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income, or UBTI, for federal income tax purposes. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa.
If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning our Preferred Units.
If the IRS contests the U.S. federal income tax positions we take, the market for our Preferred Units may be adversely affected and the cost of any contest will reduce our cash available for distribution to you. The Bipartisan Budget Act of 2015 alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to you.
We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Preferred Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our partners because the costs will reduce our cash available for distribution.
The Bipartisan Budget Act of 2015, which is applicable to us for taxable years beginning after December 31, 2017, alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised information statements to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our partners may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, partners during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.
A holder of Preferred Units whose units are the subject of a securities loan (e.g., a loan to cover a short sale of units) may be considered to have disposed of those units. If so, such holder of Preferred Units may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.
Because there are no specific rules governing the federal tax consequences of loaning a partnership interest, a holder of Preferred Units whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case the holder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan, and the holder may recognize gain or loss from such disposition. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
You may be subject to state and local taxes and return filing requirements in jurisdictions where you do not live as a result of investing in our Preferred Units.
In addition to federal income taxes, holders of Preferred Units may be subject to return filing requirements and other taxes, including state, local and non-U.S. income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. You may be subject to penalties for failure to comply with return filing requirements. It is your responsibility to file all U.S. federal, state and local tax returns.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
A description of our properties is contained in “Item 1. Business” in this Annual Report.
Our principal executive offices are located at 811 Louisiana Street, Suite 2100, Houston, Texas 77002 and our telephone number is 713-584-1000.
Item 3.
Item 3. Legal Proceedings.
The information required for this item is provided in Note 17 - Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, which is incorporated by reference into this item.
Item 4.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
On February 17, 2016, TRC completed the TRC/TRP Merger, pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Pursuant to the TRC/TRP Merger Agreement, TRC agreed to cause our common units under the symbol “NGLS” to be delisted from the NYSE and deregistered under the Exchange Act. As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The Preferred Units remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
There is no established trading market for the 5,629,136 general partner units held only by our general partner.
Distributions of Available Cash
General
As a result of the TRC/TRP Merger, Targa owns all of our outstanding common units. We have discretion under the Third A&R Partnership Agreement as to whether to distribute all available cash for any period. See Note 10 - Debt Obligations and Note 12 - Partnership Units and Related Matters of the “Consolidated Financial Statements” included in this Annual Report.
The IDR Giveback Amendment in conjunction with the Atlas mergers in 2015 resulted in reallocation of IDR payments to common unitholders of $6.25 million for each of the first three quarters of 2016.
On October 19, 2016, we executed the Third A&R Partnership Agreement, which became effective on December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the IDRs held by our general partner, and related distribution and allocation provisions, (ii) eliminating the Special GP Interest (as defined in the Third A&R Partnership Agreement) held by our general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.
As a result of the Third A&R Partnership Agreement, the reallocations of IDRs under the IDR Giveback Amendment ceased in the fourth quarter of 2016.
Definition of Available Cash
Under the partnership agreement, the term “available cash,” is defined, for any quarter or month, as applicable, as the sum of all cash and cash equivalents on hand at the end of that quarter or month, as applicable, and all additional cash and cash equivalents on hand immediately prior to the date of the distribution of available cash resulting from borrowings for working capital purposes subsequent to the end of that quarter or month, as applicable, less the amount of any cash reserves established by our general partner to:
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provide for the proper conduct of our business (including reserves for future capital expenditures and for anticipated future credit needs);
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comply with applicable law or any loan agreements, security agreements, mortgages, debt instruments or other agreements;
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provide funds for distributions on and redemptions with respect to the Preferred Units; or
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provide funds for further distributions.
The amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. The board of directors of our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business, including reserves to provide funds for distributions on and redemptions with respect to the Preferred Units. These can also include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to our unitholders, reserves to reduce debt or, as necessary, reserves to comply with the terms of any of our agreements or obligations. We will be prohibited from making any distributions to unitholders if it would cause an event of default or if an event of default exists under our credit agreement or indentures.
Preferred Units
Distributions on the Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on the Preferred Units will be paid out of amounts legally available therefor to, but not including, November 1, 2020, at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on the Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. For the year ended December 31, 2018, we have paid $11.3 million in distributions to the holders of our Preferred Units. See Note 12 - Partnership Units and Related Matters of the “Consolidated Financial Statements” included in this Annual Report.
Recent Sales of Unregistered Equity Securities
There were no sales of unregistered equity securities for the year ended December 31, 2018.
Repurchase of Equity by Targa Resources Partners LP or Affiliated Purchasers
None.
Item 6.
Item 6. Selected Financial Data.
The following table presents selected historical consolidated financial and operating data of Targa Resources Partners LP for the periods ended, and as of, the dates indicated. We derived this information from our historical “Consolidated Financial Statements” and accompanying notes. The information in the table below should be read together with, and is qualified in its entirety by reference to, those financial statements and notes in this Annual Report.
_________________________________
(1)
Revenues for 2018 include the impact of the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606). See “Recently adopted accounting pronouncements - Revenue from Contracts with Customers” included in Note 3 of the “Consolidated Financial Statements” for a presentation of financial results by reportable segment and “Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes included in Part IV of this Annual Report. Additional sections in this Annual Report should be helpful to the reading of our discussion and analysis and include the following: (i) a description of our business strategy found in “Item 1. Business-Overview”; (ii) a description of recent developments, found in “Item 1. Business-Recent Developments”; and (iii) a description of risk factors affecting us and our business, found in “Item 1A. Risk Factors.”
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The amendments in this update supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. We adopted Topic 606 on January 1, 2018 by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption of Topic 606 did not result in an impact to our operating or gross margin. However, the adoption did have an impact on the classification between components of operating margin and gross margin, “Fees from midstream services” and “Product purchases,” as well as the reporting of gross versus net revenues. For more information, see “Recent Accounting Pronouncements” included within Note 3 - Significant Accounting Policies in our Consolidated Financial Statements.
Overview
Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by TRC. Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC’s acquisition on February 17, 2016 of all our outstanding common units that it and its subsidiaries did not already own. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
We are engaged in the business of:
•
gathering, compressing, treating, processing, transporting and selling natural gas;
•
storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;
•
gathering, storing, terminaling and selling crude oil; and
•
storing, terminaling and selling refined petroleum products.
Factors That Significantly Affect Our Results
Our results of operations are impacted by a number of factors, including changes in commodity prices, the volumes that move through our gathering, processing and logistics assets, contract terms, the impact of hedging activities and the cost to operate and support assets.
Commodity Prices
The following table presents selected average annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periods presented:
________________
(1)
Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.
(2)
“Illustrative Targa NGL” pricing is weighted using average quarterly prices from Mont Belvieu Non-TET monthly commercial index and represents the following composition for the periods noted:
2018: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline
2017: 38% ethane, 34% propane, 13% normal butane, 5% isobutane and 10% natural gasoline
2016: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline
(3)
Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX.
Volumes
In our gathering and processing operations, plant inlet volumes, crude oil volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a regional basis and more broadly by the impact of prices for crude oil, natural gas and NGLs on exploration and production activity in the areas of our operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to our Downstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available pipeline capacity to transport NGLs to our fractionators and our competitive and contractual position relative to other fractionators.
Contract Terms, Contract Mix and the Impact of Commodity Prices
With the potential for volatility of commodity prices, the contract mix of our Gathering and Processing segment, other than fee-based contracts in certain gathering and processing business units and gathering and processing services, can have a significant impact on our profitability, especially those contracts that create direct exposure to changes in energy prices by paying us for gathering and processing services with a portion of proceeds from the commodities handled (“equity volumes”).
Contract terms in the Gathering and Processing segment are based upon a variety of factors, including natural gas and crude quality, geographic location, competitive dynamics and the pricing environment at the time the contract is executed, and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to crude, natural gas and NGL prices may change as a result of producer preferences, competition and changes in production as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common and other market factors.
The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. Fractionation services are supported by fee-based contracts whose rates and terms are driven by NGL supply and fractionation capacity. Export services are supported by fee-based contracts whose rates and terms are driven by global LPG demand fundamentals. The Logistics and Marketing segment includes primarily fee-based contracts.
Impact of Our Commodity Price Hedging Activities
We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures, and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We intend to continue managing our exposure to commodity prices in the future by entering into derivative transactions. We actively manage the Downstream Business product inventory and other working capital levels to reduce exposure to changing prices. For additional information regarding our hedging activities, see “Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our customers.
Risk Management
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all our commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.
Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk through 2023. Market conditions may also impact our ability to enter into future commodity derivative contracts.
Commodity Price Risk
A significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of natural gas and/or NGLs as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.
The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2018, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Marketing segment and (iii) natural gas transportation basis risk in our Logistics and Marketing segment by entering into derivative instruments. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.
When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The natural gas and NGL hedges’ fair values are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.
A majority of these commodity price hedges are documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in commodity prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.
We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas and NGL prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.
These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls).
To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. We switched from the tabular presentation option to the sensitivity analysis during 2018 as we believe that it provides more meaningful information to investors in understanding our commodity price exposure. The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair value of our derivative instruments are also influenced by changes in market volatility for option contracts and the discount rates used to determine the present values.
The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of December 31, 2018:
For comparison purposes, the following table shows what the effect of hypothetical price movements on the estimated fair value of our derivative instruments were as of December 31, 2017:
The tables above contain all derivative instruments outstanding as of the stated dates for the purpose of hedging commodity price risk, which we are exposed to due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.
During the years ended December 31, 2018, 2017 and 2016, our operating revenues increased (decreased) by $(72.2) million, $(49.7) million, and $40.1 million, respectively, as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.
Our risk management position has moved from a net liability position of $38.2 million at December 31, 2017 to a net asset position of $112.7 million at December 31, 2018. The fixed prices we currently expect to receive on derivative contracts are above the aggregate forward prices for commodities related to those contracts, creating this net asset position.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the Securitization Facility. As of December 31, 2018, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRP Revolver and the Securitization Facility will also increase. As of December 31, 2018, we had $980.0 million in outstanding variable rate borrowings under the TRP Revolver and the Securitization Facility. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact our annual interest expense by $9.8 million based on our December 31, 2018 debt balances.
Counterparty Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the International Swap Dealers Association agreements with our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by $36.7 million as of December 31, 2018. The range of losses attributable to our individual counterparties as of December 31, 2018 would be between $0.3 million and $28.0 million, depending on the counterparty in default.
Customer Credit Risk
We extend credit to customers and other parties in the normal course of business. We have an established policy and various procedures to manage our credit exposure risk, including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.
We have an active credit management process, which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectible accounts resulted in a 1% reduction of our third-party accounts receivable as of December 31, 2018, our operating income would decrease by $8.6 million in the year of the assessment.
During the year ended December 31, 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 15% of our consolidated revenues. No customer comprised greater than 10% of our consolidated revenues in the years ended December 31, 2017 and 2016.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Our “Consolidated Financial Statements,” together with the report of our independent registered public accounting firm, begin on page in this Annual Report.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Annual Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2018, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
(a)
Management’s Report on Internal Control Over Financial Reporting
Our Management’s Report on Internal Control Over Financial Reporting is included on page of this Annual Report and is incorporated herein by reference. Management concluded that our internal control over financial reporting was effective as of December 31, 2018.
(b)
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during our most recent fiscal quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
We are a limited partnership and, therefore, have no officers or directors. Unless otherwise indicated, references to our officers and directors in Items 10 through 14 of this Annual Report refer to the officers and directors of our general partner.
Management of Targa Resources Partners LP
Targa Resources GP LLC, our general partner, manages our operations and activities. Our general partner is not currently elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes fiduciary duties to our unitholders, but our partnership agreement contains various provisions modifying and restricting its fiduciary duties. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.
The directors of our general partner oversee our operations. Our general partner currently has eleven directors. Targa GP Inc. elects all members to the board of directors of our general partner (the “Board”) and our general partner has eight directors that are independent as defined under the independence standards established by the NYSE. The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating/corporate governance committee.
The Board has a standing audit committee (the “Audit Committee”) that consists of three directors. The members of our Audit Committee are Messrs. Tong and Redd and Ms. Fulton. Mr. Tong is the Chairman of this committee. Our board of directors has affirmatively determined that Messrs. Tong and Redd and Ms. Fulton are independent as described in the rules of the NYSE and the Exchange Act. Our board of directors has also determined that, based upon relevant experience, Mr. Tong is an “audit committee financial expert” as defined in Item 407 of Regulation S-K of the Exchange Act. This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the Audit Committee oversees our compliance programs relating to legal and regulatory requirements. We have adopted an Audit Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.
The compensation of our general partner’s executive officers is set by Targa, the indirect parent of our general partner, with the Board playing no role in the process. Compensation decisions relating to oversight of the long-term incentive plan described below, however, are made by the Board. While the Board may establish a compensation committee in the future, it has no current plans to do so.
All of our executive management personnel are employees of Targa Resources and devote their time as needed to conduct our and Targa’s business and affairs. These officers of Targa Resources manage the day-to-day affairs of our business. Because Targa’s only cash generating assets are direct and indirect partnership interests in us, we expect that our executive officers will devote a substantial majority of their time to our business. We expect the amount of time that the executive management personnel of our general partner devote to our business in future periods to be driven by the needs and demands of our ongoing business and business development efforts, which are likely to increase as our asset base and operations increase in size. However, depending on how our business develops and the nature of the business development efforts by executive management, the amount of time that the executive management team of our general partner devotes to our business may increase or decrease in future periods. We also utilize a significant number of employees of Targa Resources to operate our business and provide us with general and administrative services. We reimburse Targa for allocated expenses of operational personnel who perform services for our benefit, allocated general and administrative expenses and certain direct expenses. See “Reimbursement of Expenses of Our General Partner” included in this Item 10.
Directors, Executive Officers and Other Officers
Our general partner’s directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the Board. There are no family relationships among any of our general partner’s directors or executive officers. The following table shows information with respect to the current directors, executive officers and other officers of Targa Resources GP LLC as of February 17, 2019:
Name
Age
Position
Joe Bob Perkins
Chief Executive Officer and Director
James W. Whalen
Executive Chairman of the Board and Director
Michael A. Heim
Vice Chairman of the Board and Director
Matthew J. Meloy
President
Jeffrey J. McParland
President - Administration
Patrick J. McDonie
President - Gathering and Processing
D. Scott Pryor
President - Logistics and Marketing
Robert M. Muraro
Chief Commercial Officer
Jennifer R. Kneale
Chief Financial Officer
Paul W. Chung
Executive Vice President, General Counsel and Secretary
Clark White
Executive Vice President - Engineering and Operations
John R. Klein
Senior Vice President and Chief Accounting Officer
Rene R. Joyce
Director
Charles R. Crisp
Director
Chris Tong
Director
Ershel C. Redd Jr.
Director
Laura C. Fulton
Director
Waters S. Davis, IV
Director
Robert B. Evans
Director
Beth A. Bowman
Director
Joe Bob Perkins has served as Chief Executive Officer and director of the Company and our general partner since January 1, 2012. Mr. Perkins previously served as President of the Company between the date of its formation on October 27, 2005 and December 31, 2011 and of our general partner between October 2006 and December 31, 2011. He also served as President of predecessor companies from 2003 through 2005. Mr. Perkins was an independent consultant in the energy industry from 2002 through 2003 and was an active partner in an outdoor advertising firm during a portion of such time period. Mr. Perkins served as President and Chief Operating Officer for the Wholesale Businesses, Wholesale Group and Power Generation Group of Reliant Resources, Inc. and its parent/predecessor companies, from 1998 to 2002 and Vice President, Corporate Planning and Development, of Houston Industries from 1996 to 1998. He served as Vice President, Business Development, of Coral Energy Holding, L.P. (“Coral”) from 1995 to 1996 and as Director, Business Development, of Tejas Gas Corporation (“Tejas”) from 1994 to 1995. Prior to 1994, Mr. Perkins held various positions with the consulting firm of McKinsey & Company and with an exploration and production company. Mr. Perkins’ intimate knowledge of all facets of the Company, derived from his service as President from its founding through 2011 and his current service as Chief Executive Officer and director, coupled with his broad experience in the oil and gas industry, and specifically in the midstream sector, his engineering and business educational background and his experience with the investment community enable Mr. Perkins to provide a valuable and unique perspective to the board on a range of business and management matters.
James W. Whalen has served as Executive Chairman of the Board of the Company and our general partner since January 1, 2015. Mr. Whalen has also served as a director of the Company since its formation on October 27, 2005 and of our general partner since February 2007. He also served as director of an affiliate of the Company during 2004 and 2005. Mr. Whalen previously served as Advisor to Chairman and CEO of the Company and our general partner between January 1, 2012 and December 31, 2014. He served as Executive Chairman of the Board of the Company between October 25, 2010 and December 31, 2011 and of our general partner between December 15, 2010 and December 31, 2011. He also served as President - Finance and Administration of the Company between January 2006 and October 2010 and our general partner between October 2006 and December 2010 and for various Targa subsidiaries since November 2005. Between October 2002 and October 2005, Mr. Whalen served as the Senior Vice President and Chief Financial Officer of Parker Drilling Company. Between January 2002 and October 2002, he was the Chief Financial Officer of Diversified Diagnostic Products, Inc. He served as Chief Commercial Officer of Coral from February 1998 through January 2000. Previously, he served as Chief Financial Officer for Tejas from 1992 to 1998. Mr. Whalen brings a breadth and depth of experience as an executive, board member, and audit committee member across several different companies and in energy and other industry areas. His valuable management and financial expertise includes an understanding of the accounting and financial matters that the Company and industry address on a regular basis.
Michael A. Heim has served as a director of the Company since March 1, 2016 and Vice Chairman of the Board since March 11, 2016. He has also served as a director and Vice Chairman of the Board of our general partner since November 12, 2015. Mr. Heim previously served as President and Chief Operating Officer of the Company and our general partner between January 1, 2012 and November 12, 2015. Mr. Heim previously served as Executive Vice President and Chief Operating Officer of the Company between the date of its formation on October 27, 2005 and December 2011 and of our general partner between October 2006 and December 2011. He also served as an officer of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliate during 2003. Mr. Heim also served as a consultant in the energy industry from 2001 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Heim served as Chief Operating Officer and Executive Vice President of Coastal Field Services, a subsidiary of The Coastal Corp. (“Coastal”) a diversified energy company, from 1997 to 2001 and President of Coastal States Gas Transmission Company from 1997 to 2001. In these positions, he was responsible for Coastal’s midstream gathering, processing, and marketing businesses. Prior to 1997, he served as an officer of several other Coastal exploration and production, marketing and midstream subsidiaries.
Matthew J. Meloy has served as President of the Company and our general partner since March 1, 2018. Mr. Meloy previously served as Executive Vice President and Chief Financial Officer of the Company and our general partner between May 20, 2015 and February 28, 2018. He also served as Treasurer of the Company and our general partner until December 2015. He also served as Senior Vice President, Chief Financial Officer and Treasurer of the Company between October 25, 2010 and May 20, 2015 and of our general partner between December 15, 2010 and May 20, 2015. He also served as Vice President - Finance and Treasurer of the Company between April 2008 and October 2010, and as Director, Corporate Development of the Company between March 2006 and March 2008 and of our general partner between March 2006 and March 2008. He has served as Vice President - Finance and Treasurer of our general partner between April 2008 and December 15, 2010. Mr. Meloy was with The Royal Bank of Scotland in the structured finance group, focusing on the energy sector from October 2003 to March 2006, most recently serving as Assistant Vice President.
Jeffrey J. McParland has served as President - Administration of the Company since February 22, 2017. He previously served as President - Finance and Administration of the Company between October 25, 2010 and February 22, 2017 and of our general partner between December 15, 2010 and February 22, 2017. He has also served as Executive Vice President and Chief Financial Officer of the Company between October 27, 2005 and October 25, 2010. He also served as an officer of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliate during 2003. He served as Executive Vice President and Chief Financial Officer of our general partner between October 2006 and December 15, 2010 and served as a director of our general partner from October 2006 to February 2007. Mr. McParland served as Treasurer of the Company from October 27, 2005 until May 2007 and of our general partner from October 2006 until May 2007. Mr. McParland served as Senior Vice President, Finance of Dynegy Inc., a company engaged in power generation, the midstream natural gas business and energy marketing, from 2000 to 2002. In this position, he was responsible for corporate finance and treasury operations activities. He served as Senior Vice President, Chief Financial Officer and Treasurer of PG&E Gas Transmission, a midstream natural gas and regulated natural gas pipeline company, from 1999 to 2000. Prior to 1999, he worked in various engineering and finance positions with companies in the power generation and engineering and construction industries.
Patrick J. McDonie, has served as President - Gathering and Processing of the Company and our general partner since March 1, 2018. Mr. McDonie previously served as Executive Vice President - Southern Field Gathering and Processing of the Company and our general partner between November 12, 2015 and February 28, 2018. He also served as President of Atlas Pipeline Partners GP LLC (“Atlas”), which was acquired by the Partnership on February 28, 2015, between October 2013 and February 2015. He also served as Chief Operating Officer of Atlas between July 2012 and October 2013 and as Senior Vice President of Atlas between July 2012 and October 2013. He served as President of ONEOK Energy Services Company, a natural gas transportation, storage, supplier and marketing company between May 2008 and July 2012.
D. Scott Pryor has served as President - Logistics and Marketing of the Company and our general partner, since March 1, 2018. Mr. Pryor previously served as Executive Vice President - Logistics and Marketing of the Company and our general partner between November 12, 2015 and February 28, 2018. He also served as Senior Vice President - NGL Logistics & Marketing of Targa Resources Operating LLC (“Targa Operating”) and various other subsidiaries of the Partnership between June 2014 and November 2015. He also served as Vice President of Targa Operating between July 2011 and May 2014 and has held officer positions with other Partnership subsidiaries since 2005.
Robert M. Muraro has served as Chief Commercial Officer of the Company and our general partner since March 1, 2018. Mr. Muraro previously served as Executive Vice President - Commercial of the Company and our general partner between February 22, 2017 and February 28, 2018. He also served as Senior Vice President - Commercial and Business Development of Targa Midstream Services LLC (“Targa Midstream”) and various other subsidiaries of the Partnership between March 2016 and February 2017. He also served as Vice President - Commercial Development of Targa Midstream and various other subsidiaries of the Partnership between January 2013 and March 2016. He held the position of Director of Business Development between August 2004 and January 2013.
Jennifer R. Kneale has served as Chief Financial Officer of the Company and our general partner since March 1, 2018. Ms. Kneale previously served as Vice President - Finance of the Company and our general partner between December 16, 2015 and February 28, 2018. She also served as Senior Director, Finance of the Company and our general partner between March 2015 and December 2015. She also served as Director, Finance of the Company and our general partner between May 2013 and February 2015. Ms. Kneale was with Tudor, Pickering, Holt & Co. in its energy private equity group, TPH Partners, from September 2011 to May 2013, most recently serving as Director of Investor Relations.
Paul W. Chung has served as Executive Vice President, General Counsel and Secretary of the Company since its formation on October 27, 2005 and of our general partner since October 2006. He also served as an officer of an affiliate of the Company during 2004 and 2005. Mr. Chung served as Executive Vice President and General Counsel of Coral from 1999 to April 2004; Shell Trading North America Company, a subsidiary of Shell Oil Company (“Shell”), from 2001 to April 2004; and Coral Energy, LLC from 1999 to 2001. In these positions, he was responsible for all legal and regulatory affairs. He served as Vice President and Assistant General Counsel of Tejas from 1996 to 1999. Prior to 1996, Mr. Chung held a number of legal positions with different companies, including the law firm of Vinson & Elkins L.L.P.
Clark White has served as Executive Vice President - Engineering and Operations of the Company and our general partner since November 12, 2015. Mr. White previously served as Senior Vice President - Field G&P of Targa Operating and various other subsidiaries of the Partnership between June 2014 and November 2015. He also served as Vice President of Targa Operating between July 2011 and May 2014 and has held officer positions with other Partnership subsidiaries since 2003.
John R. Klein has served as Senior Vice President and Chief Accounting Officer of the Company and our general partner since February 22, 2017. Mr. Klein previously served as Senior Vice President - Controller of the Company and our general partner between December 2015 and February 2017. He also served as Vice President - Controller of the Company between March 2007 and December 2015 and of our general partner between November 2007 and December 2015. Mr. Klein served as a senior executive in a consulting firm from 1995 through 2006. Prior to 1995, he held various executive accounting management positions in the energy industry and in public accounting.
Rene R. Joyce has served as a director of the Company since its formation on October 27, 2005 and of our general partner since October 2006. Mr. Joyce previously served as Executive Chairman of the Board of our general partner between January 1, 2012 and December 31, 2014. He also served as Chief Executive Officer of the Company between October 27, 2005 and December 31, 2011 and our general partner between October 2006 and December 31, 2011. He also served as an officer and director of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliate during 2003. Mr. Joyce is a director of Apache Corporation. Mr. Joyce served as a consultant in the energy industry from 2000 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Joyce served as President of onshore pipeline operations of Coral Energy, LLC, a subsidiary of Shell from 1998 through 1999 and President of energy services of Coral, a subsidiary of Shell which was the gas and power marketing joint venture between Shell and Tejas, during 1999. Mr. Joyce served as President of various operating subsidiaries of Tejas, a natural gas pipeline company, from 1990 until 1998 when Tejas was acquired by Shell. As the founding Chief Executive Officer of the Company, Mr. Joyce brings deep experience in the midstream business, expansive knowledge of the oil and gas industry, as well as relationships with chief executives and other senior management at peer companies, customers and other oil and natural gas companies throughout the world. His experience and industry knowledge, complemented by an engineering and legal educational background, enable Mr. Joyce to provide the board with executive counsel on the full range of business, technical, and professional matters.
Charles R. Crisp has served as a director of the Company since its formation on October 27, 2005 and of our general partner since March 1, 2016. He also served as a director of an affiliate of the Company during 2004 and 2005. Mr. Crisp was President and Chief Executive Officer of Coral Energy, LLC, a subsidiary of Shell, from 1999 until his retirement in November 2000 and was President and Chief Operating Officer of Coral from January 1998 through February 1999. Prior to this, Mr. Crisp served as President of the power generation group of Houston Industries and, between 1988 and 1996, as President and Chief Operating Officer of Tejas. Mr. Crisp is also a director of Southern Company Gas (formerly known as AGL Resources Inc.), a subsidiary of The Southern Company, EOG Resources Inc. and IntercontinentalExchange Inc. Mr. Crisp brings extensive energy experience, a vast understanding of many aspects of our industry and experience serving on the boards of other public companies in the energy industry. His leadership and business experience and deep knowledge of various sectors of the energy industry bring a crucial insight to the board of directors.
Chris Tong has served as a director of the Company since January 2006 and of our general partner since March 1, 2016. Mr. Tong is a director of Kosmos Energy Ltd. He served as Senior Vice President and Chief Financial Officer of Noble Energy, Inc. from January 2005 until August 2009. He also served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. from August 1997 until December 2004. Prior thereto, he was Senior Vice President of Finance of Tejas Acadian Holding Company and its subsidiaries, including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions from August 1996 until August 1997 and had served in other treasury positions with Tejas since August 1989. Mr. Tong brings a breadth and depth of experience as a chief financial officer in the energy industry, a financial executive, a director of other public companies and a member of other audit committees. He brings significant financial, capital markets and energy industry experience to the board and in his position as the chairman of our Audit Committee.
Ershel C. Redd Jr. has served as a director of the Company since February 2011 and of our general partner since March 1, 2016. Mr. Redd has served as a consultant in the energy industry since 2008 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Redd was President and Chief Executive Officer of El Paso Electric Company, a public utility company, from May 2007 until March 2008. Prior to this, Mr. Redd served in various positions with NRG Energy, Inc., a wholesale energy company, including as Executive Vice President - Commercial Operations from October 2002 through July 2006, as President - Western Region from February 2004 through July 2006, and as a director between May 2003 and December 2003. Mr. Redd served as Vice President of Business Development for Xcel Energy Markets, a unit of Xcel Energy Inc., from 2000 through 2002, and as President and Chief Operating Officer for New Century Energy’s (predecessor to Xcel Energy Inc.) subsidiary, Texas Ohio Gas Company, from 1997 through 2000. Mr. Redd brings to the Company extensive energy industry experience, a vast understanding of varied aspects of the energy industry and experience in corporate performance, marketing and trading of natural gas and natural gas liquids, risk management, finance, acquisitions and divestitures, business development, regulatory relations and strategic planning. His leadership and business experience and deep knowledge of various sectors of the energy industry bring a crucial insight to the board of directors.
Laura C. Fulton has served as a director of the Company since February 26, 2013 and of our general partner since March 1, 2016. Ms. Fulton has served as the Chief Financial Officer of Hi-Crush Proppants LLC since April 2012 and Hi-Crush GP LLC, the general partner of Hi-Crush Partners LP, since May 2012. From March 2008 to October 2011, Ms. Fulton served as Executive Vice President, Accounting and then Executive Vice President, Chief Financial Officer of AEI Services, LLC (“AEI”), an owner and operator of essential energy infrastructure assets in emerging markets. Prior to AEI, Ms. Fulton spent 12 years with Lyondell Chemical Company in various capacities, including as general auditor responsible for internal audit and the Sarbanes-Oxley certification process, and as the assistant controller. Prior to that, she spent 11 years with Deloitte & Touche in public accounting, with a focus on audit and assurance. As a chief financial officer, general auditor and external auditor, Ms. Fulton brings to the company extensive financial, accounting and compliance process experience. Ms. Fulton’s experience as a financial executive in the energy industry, including her current position with a master limited partnership, also brings industry and capital markets experience to the board.
Waters S. Davis, IV has served as director of the Company since July 2015 and of our general partner since March 1, 2016. Mr. Davis has served as President of National Christian Foundation, Houston since July 2014. Mr. Davis was Executive Vice President of NuDevco LLC from December 2009 to December 2013. Prior to his employment with NuDevco, he served as President of Reliant Energy Retail Services from June 1999 to January 2002 and as Executive Vice President of Spark Energy from April 2007 to November 2009. He previously served as a senior executive at a number of private companies and as an advisor to a private equity firm, providing operational and strategic guidance. Mr. Davis also serves as a director of Milacron Holdings Corp. Mr. Davis brings expertise in the retail energy, midstream and services industries, which enhances his contributions to the board of directors.
Robert B. Evans has served as a director of the Company since March 1, 2016 and of our general partner since February 2007. Mr. Evans is also a director of New Jersey Resources Corporation and One Gas, Inc. Mr. Evans was a director of Sprague Resources GP LLC until October 2018. Mr. Evans was the President and Chief Executive Officer of Duke Energy Americas, a business unit of Duke Energy Corp., from January 2004 until his retirement in March 2006. Mr. Evans served as the transition executive for Energy Services, a business unit of Duke Energy, during 2003. Mr. Evans also served as President of Duke Energy Gas Transmission beginning in 1998 and was named President and Chief Executive Officer in 2002. Prior to his employment at Duke Energy, Mr. Evans served as Vice President of marketing and regulatory affairs for Texas Eastern Transmission and Algonquin Gas Transmission from 1996 to 1998. Mr. Evans’ extensive experience in the gas transmission and energy services sectors enhances the knowledge of the board in these areas of the oil and gas industry. As a former President and CEO of various operating companies, his breadth of executive experiences is applicable to many of the matters routinely facing the Partnership.
Beth A. Bowman has served as a director of the Company and our general partner since September 7, 2018. Ms. Bowman has served as a director of Sprague Resources GP LLC, the general partner of Sprague Resources LP (“Sprague”), since October 2014, and she currently serves on the Audit Committee of Sprague. Ms. Bowman held management positions at Shell Energy North America (US) L.P. (“Shell”) for 17 years until her retirement in September 2015. While at Shell, she held the roles of Senior Vice President of the West and Mexico and later as the Senior Vice President of Sales and Origination for Shell’s North America business. Prior to joining Shell, Ms. Bowman held management positions at Sempra Energy Trading and Sempra’s San Diego Gas & Electric utility in various areas including trading and marketing, risk management, fuel and power supply, regulatory, finance and engineering. Ms. Bowman also served on the board of the California Power Exchange and the board of the California Foundation of Energy and Environment from 2004 until 2015. Ms. Bowman’s extensive energy industry background, including her experience in origination, commodities markets and risk management enhances the knowledge of the board in these areas of the oil and gas industry.
Reimbursement of Expenses of Our General Partner
Under the terms of our Partnership Agreement, we reimburse Targa for all direct and indirect expenses, as well as expenses otherwise allocable to us in connection with the operation of our business, incurred on our behalf, which includes certain operating and direct expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for our benefit. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. We reimburse Targa for the direct expenses to provide these services as well as other direct expenses it incurs on our behalf, such as compensation of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits. Other than Targa’s direct costs of being a public reporting company, substantially all of Targa’s general and administrative costs have been, so long as Targa’s only cash-generating assets consist of its interest in us, and will continue to be allocated to us. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Board of Directors
Our board of directors consists of eleven members. The board reviewed the independence of our directors using the independence standards of the NYSE and, based on this review, determined that Messrs. Joyce, Crisp, Evans, Redd, Tong and Davis and Mses. Fulton and Bowman are independent within the meaning of the NYSE listing standards currently in effect.
Our directors are divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2020, 2021 and 2019, respectively. The Class I directors are Messrs. Crisp, Heim and Whalen and Ms. Fulton the Class II directors are Messrs. Evans, Redd, and Perkins and Ms. Bowman and the Class III directors are Messrs. Tong, Joyce and Davis. At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.
Corporate Governance
Code of Business Conduct and Ethics
Our general partner has adopted a Code of Ethics For Chief Executive Officer and Senior Financial Officers (the “Code of Ethics”), which applies to our general partner’s Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller and all of our other senior financial and accounting officers, and our Code of Conduct (the “Code of Conduct”), which applies to officers, directors and employees of the Company and its subsidiaries, including our general partner. In accordance with the disclosure requirements of applicable law or regulation, we intend to disclose any amendment to, or waiver from, any provision of the Code of Ethics or Code of Conduct under Item 5.05 of a current report on Form 8-K.
Available Information
We make available, free of charge within the “Corporate Governance” section of our website at http://www.targaresources.com and in print to any unitholder who so requests, our Corporate Governance Guidelines, Code of Ethics, Code of Conduct and the Audit Committee Charter. Requests for print copies may be directed to: Investor Relations, Targa Resources Partners LP, 811 Louisiana, Suite 2100, Houston, Texas 77002 or made by telephone by calling (713) 584-1000. The information contained on or connected to our internet website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
Corporate Governance Guidelines
Our general partner’s board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE.
Executive Sessions of Non-Management Directors
Our non-management directors meet in executive session without management participation at regularly scheduled executive sessions. These meetings are chaired by Mr. Crisp.
Interested parties may communicate directly with our non-management directors by writing to: Non-Management Directors, Targa Resources Partners LP, 811 Louisiana, Suite 2100, Houston, Texas 77002.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our directors, executive officers and 10% unitholders to file with the SEC reports of ownership and changes in ownership of our equity securities that are registered pursuant to Section 12 of the Exchange Act. Based solely upon a review of the copies of the Form 3, 4 and 5 reports furnished to us and certifications from our directors and executive officers, we believe that during 2018, all of our directors, executive officers and beneficial owners of more than 10% of our Preferred Units complied with Section 16(a) filing requirements applicable to them.
Item 11.
Item 11. Executive Compensation.
COMPENSATION DISCUSSION AND ANALYSIS
The following Compensation Discussion and Analysis (“CD&A”) contains statements regarding our compensation programs and our executive officers’ business priorities related to our compensation programs and target payouts under the programs. These business priorities are disclosed in the limited context of our compensation programs and should not be understood to be statements of management’s expectations or estimates of results or other guidance.
Overview
Neither we nor our General Partner directly employ any of the persons responsible for managing our business. Any compensation decisions that are required to be made by our General Partner will be made by the board of directors of our General Gartner, which does not have a compensation committee. All of our General Partner’s executive officers are employees of Targa Resources Corp.
For 2018, our named executive officers were:
Name
Position as of December 31, 2018
Joe Bob Perkins
Chief Executive Officer
Matthew J. Meloy
President
Jennifer R. Kneale
Chief Financial Officer
Patrick J. McDonie
President - Gathering and Processing
D. Scott Pryor
President - Logistics and Marketing
Paul W. Chung
Executive Vice President, General Counsel and Secretary
Mr. Meloy served as our Chief Financial Officer in 2018 from January 1 to March 1, at which time he was promoted to President and Ms. Kneale was appointed to serve as our Chief Financial Officer.
The named executive officers of the Company also served as executive officers of our General Partner during 2018. The named executive officers devote their time as needed to the conduct of the Company’s business and affairs and the conduct of the Partnership’s business and affairs.
The compensation information described in this CD&A and contained in the tables that follow reflects all compensation received by the named executive officers for the services they provide to the Company and for the services they provide to our General Partner and the Partnership for the years indicated. For 2018, the Compensation Committee of the Company’s board of directors (the “Compensation Committee”) was generally responsible for determining and setting compensation practices for the named executive officers. During 2018, we reimbursed the Company and its affiliates for the compensation of the named executive officers pursuant to the Partnership’s partnership agreement. See “- Certain Relationships and Related Transactions” and “Director Independence - Partnership Agreement” for additional information regarding our reimbursement obligations.
The Compensation Committee believes that it has taken actions to govern compensation in a responsible way, as described in this CD&A, and our performance demonstrates that the compensation programs are structured to pay reasonable amounts for performance based on the Company’s understanding of the markets in which we compete for executive talent.
The Company held its most recent advisory say-on-pay vote regarding executive compensation at its 2018 Annual Meeting. At that meeting, more than 93% of the votes cast by the Company’s shareholders approved, on an advisory basis, of the compensation paid to the named executive officers as described in the CD&A and the other related compensation tables and disclosures contained in the Company’s Proxy Statement filed with the SEC on March 29, 2018. The board of directors of the Company and the Compensation Committee reviewed the results of this vote and concluded that, with this level of support, no changes to the compensation design and philosophy needed to be considered as a result of the say-on-pay vote. In accordance with the preference expressed by the Company’s shareholders to conduct an advisory vote on executive compensation every year, the next advisory vote will occur this year at the Company’s 2019 Annual Meeting. We are generally not subject to the advisory say on pay vote requirements under the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.
The following CD&A is presented from the perspective of the Compensation Committee and discusses our General Partner’s named executive officers in their roles as officers of the Company. The elements of compensation and the Compensation Committee’s decisions with respect to determination on payments are not subject to approval by the board of directors of our General Partner or the board of directors of the Company (the “Targa Board”). All members of the board of directors of our general partner are members of the Targa Board. As used in this CD&A (other than in this “Overview”), references to “our,” “we,” “us,” the “Company,” and similar terms refer to Targa, references to the “Board” or “Board of Directors” refers to the Targa Board, and references to the Partnership refer to us, Targa Resources Partners LP.
Summary of Key Strategic Results
As noted above, our operating assets are held in the Partnership. As described in “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2018, our 2018 strategic and operational accomplishments and our 2018 financial results (including the financial results of the Partnership on a consolidated basis) demonstrate the performance of our businesses, which, along with our ongoing growth capital expenditure programs, have allowed us to increase both our business scale and diversity. In summary, certain of our more significant financial, operational and strategic highlights in 2018 included:
Excellent execution across our businesses with Company Adjusted EBITDA of over $1.3 billion, driven by higher Field G&P volumes, higher fractionation volumes and continued strong export volumes while exceeding the high end of the public EBITDA guidance range and with dividend coverage that achieved public guidance;
Excellent execution on 2018 net growth investments of approximately $2.7 billion completed or on track to be completed generally on time and on budget;
Continued development of our potential future expansion project portfolio;
Excellent financial execution including capital raising and balance sheet and liquidity management while funding growth expenditures and maintaining TRC dividend per share; and
A continued strong track record and performance regarding safety and strong compliance performance in all other aspects of our business, including environmental and regulatory compliance.
See “-Components of Executive Compensation Program for Fiscal 2018-Annual Incentive Bonus” for further discussion of certain of these summary highlights. Please also see our Annual Report on Form 10-K for the year ended December 31, 2018 for a reconciliation of Adjusted EBITDA to net income (loss) attributable to the Company.
Summary of 2018 and 2019 Compensation Decisions
While the compensation arrangements for our named executive officers during fiscal 2018 remained substantially similar to those in place during fiscal 2017, specific compensatory actions in 2018 included the following:
2018 Annual Bonus Pool Funding and CEO and Executive Chairman Bonus Award Paid in Restricted Stock Units. Our overall performance on the 2018 business priorities significantly exceeded expectations for the year (as was the case for 2017), the bonus pool was funded at 170% of target under the 2018 Bonus Plan. In connection with this approval and our current focus on reducing cash expenses, and in light of industry conditions in late 2018 and early 2019, the Compensation Committee approved settlement of the 2018 bonuses solely in restricted stock units awards for our Chief Executive Officer and our Executive Chairman of the Board (“Chairman”), instead of an all-cash bonus. The restricted stock unit awards will vest in full three years after the date of grant of the award, subject to continued employment of the officer through that date. See “-Components of Executive Compensation Program for Fiscal 2018-Annual Incentive Bonus” for additional information.
Increases to 2018 Total Compensation and Increases to Base Salary. For 2018, base salary raises were approved for the named executive officers ranging from 5% to 43% from 2017 amounts. Specifically, the following base salary increases were approved: (i) 13% for Mr. Perkins, (ii) 11% for Mr. Meloy, (iii) 43% for Ms. Kneale, (iv) 12% for Mr. McDonie, (v) 12% for Mr. Pryor and (vi) 5% for Mr. Chung. The Compensation Committee authorized base salary increases for the named executive officers in order to align the total direct compensation of these individuals more closely with the total direct compensation provided to similarly situated executives at companies within our 2018 Peer Group, considering company size, and, in the case of Mr. Meloy and Ms. Kneale, to reflect professional growth and the assumption of additional responsibilities in connection with their promotions. Ms. Kneale’s base salary was also adjusted to bring her closer to similarly situated officers, as her salary was significantly below those of officers with a comparable level of duties and responsibilities both internally and in comparison to our peers. See “-Changes for 2018-2018 Peer Group” for a description of the companies that comprise the 2018 Peer Group. In addition, for 2018 under our annual incentive bonus plan, the target bonus percentages for our named executive officers (other than Mr. Chung) were increased in order to align their total direct compensation more closely with the total direct compensation provided to similarly situated officers at companies within our 2018 Peer Group, adjusted for company size. For similar reasons, the long-term equity incentive award targets for 2018 for the named executive officers were also increased.
Performance/Retention Awards. In recognition of past performance and to enhance retention, on January 12, 2018, the Compensation Committee also granted a special retention award to Mr. Perkins. The special retention award was granted in the form of 80,000 restricted stock units that vest 50% on December 31, 2018 and the remaining 50% on December 31, 2019, subject to his continued employment through the applicable vesting date. Mr. Perkins is the only named executive officer who received a special retention award in 2018.
With respect to 2019 compensation, the Compensation Committee has made the following determinations, which are described in greater detail below under “-Changes for 2019: Increases to 2019 Total Compensation”. For 2019, base salary raises were approved for the named executive officers ranging from approximately 5% to 14%. The Compensation Committee authorized base salary increases for the named executive officers in order to align the total direct compensation of these individuals more closely with the total direct compensation provided to similarly situated executives at companies within our 2019 Peer Group, considering company size, and, in the case of Mr. Meloy and Ms. Kneale, to reflect their growth into the second year of their positions and the assumption of additional responsibilities in 2018 and 2019, respectively. See “-Changes for 2019-2019 Peer Group” for a description of the companies that comprise the 2019 Peer Group. In addition, for 2019 under our annual incentive bonus plan, the target bonus percentages for several of our named executive officers were increased in order to align their total direct compensation more closely with the total direct compensation provided to similarly situated officers at companies within our 2019 Peer Group, considering company size, and to reflect the changes in positions and responsibilities referenced above. For similar reasons, the long-term equity incentive award targets for 2019 for Messrs. Perkins, McDonie and Pryor and Ms. Kneale also increased.
Discussion and Analysis of Executive Compensation
Compensation Philosophy and Elements
The following compensation objectives guide the Compensation Committee in its deliberations about executive compensation matters:
Competition Among Peers. The Compensation Committee believes our executive compensation program should enable us to attract and retain key executives by providing a total compensation program that is competitive with the market in which we compete for executive talent, which encompasses not only diversified midstream companies but also other energy industry companies as described in “-Methodology and Process-Role of Peer Group and Market Analysis” below.
Accountability for Performance. The Compensation Committee believes our executive compensation program should ensure an alignment between our strategic, operational and financial performance and the total compensation received by our named executive officers. This includes providing compensation for performance that reflects individual and company performance both in absolute terms and relative to our Peer Group.
Alignment with Shareholder Interests. The Compensation Committee believes our executive compensation program should ensure a balance between short-term and long-term compensation while emphasizing at-risk or variable compensation as a valuable means of supporting our strategic goals and aligning the interests of our named executive officers with those of our shareholders.
Supportive of Business Goals. The Compensation Committee believes that our total compensation program should support our business objectives and priorities.
Consistent with this philosophy and the compensation objectives, our 2018 executive compensation program consisted of the following elements:
Compensation Element
Description
Role in Total Compensation
Base Salary
Competitive fixed-cash compensation based on an individual’s role, experience, qualifications and performance
• A core element of competitive total compensation, important in attracting and retaining key executives
Annual Incentive Bonus
Variable payouts tied to achievement of annual financial, operational and strategic business priorities and determined in the sole discretion of the Compensation Committee
• Aligns named executive officers with annual strategic, operational and financial results
• Recognizes individual and performance-based contributions to annual results
• Supplements base salary to help attract and retain executives
Long-Term Equity Incentive Awards
Restricted stock awards granted under our Stock Incentive Plan
Performance share unit awards granted under our Stock Incentive Plan
• Aligns named executive officers with sustained long-term value creation
• Creates opportunity for a meaningful and sustained ownership stake
• Combined with salary and annual bonus, provides a competitive target total direct compensation opportunity substantially contingent on our equity performance and performance relative to our LTIP peer group
Benefits
401(k) plan, health and welfare benefits
• Our named executive officers are eligible to participate in benefits provided to other Company employees
• Contributes toward financial security for various life events (e.g., disability or death)
• Generally competitive with companies in the midstream sector
Post-Termination Compensation
“Double trigger” change in control payments payable in cash
Accelerated vesting of equity awards upon certain change in control transactions and qualifying termination events
Continued vesting of equity awards following retirement, subject to provision of consulting services or compliance with non-compete obligations
• Helps mitigate possible disincentives to pursue value-added merger or acquisition transactions if employment prospects are uncertain
• Provides assistance with transition if post-transaction employment is not offered
• Allows the Company to benefit from employee non-compete obligations and ongoing access to cooperative employees
Perquisites
None, other than minimal parking subsidies
• The Compensation Committee’s policy is not to pay for perquisites for any of our named executive officers, other than minimal parking subsidies
Fiscal 2018 Total Direct Compensation
We review the mix of base salary, annual incentive bonuses and long-term equity incentive awards (i.e., total direct compensation) each year for the Company and for our Peer Group. We view the various components of total direct compensation as related but distinct and emphasize pay for performance, with a significant portion of total direct compensation reflecting a risk aspect tied to long- and short-term financial and strategic goals. Although we typically target annual long-term equity incentive awards as a percentage of base salary, we have historically not operated under any formal policies or specific guidelines for allocating compensation between long-term and currently paid out compensation, between cash and non-cash compensation, or among different forms of non-cash compensation. However, we believe that our compensation packages are representative of an appropriate mix of compensation components, and we anticipate that we will generally continue to utilize a similar, though not identical, mix of compensation in future years. As recommended by the Compensation Consultant, the Compensation Committee seeks to provide our named executive officers with a mix of base salary and short- and long-term incentives that is generally in line with that provided to similarly situated executives in our Peer Group, adjusted for company size.
The approximate allocation of target total direct compensation for our named executive officers in fiscal 2018 is presented below. This reflects (i) the salary rates in effect as of December 31, 2018, (ii) target annual incentive bonuses for services performed in fiscal 2018, and (iii) the grant date fair value of long-term equity incentive awards granted during fiscal 2018 (excluding the grant date fair value of equity awards granted in 2018 in lieu of 2017 annual incentive cash bonus payments).
Fiscal 2018 Target Total Direct Compensation
(1)
Mr. Perkins received 100% of his annual incentive bonus in the form of restricted stock unit awards that will vest in full three years after the date of the award, subject to his continued employment.
Over the last five calendar years, the target total direct compensation (base salary plus target annual incentive bonus plus grant date fair value of long-term equity incentive awards) as set by the Compensation Committee for our Chief Executive Officer has resulted in target levels that have been significantly below the total direct compensation levels of similarly situated executives at companies in our Peer Group. The implied market median compensation level is determined by the Compensation Consultant using a regression analysis for our Peer Group that considers company size and that predicts total direct compensation as correlated to market capitalization and total assets. The following chart illustrates the relationship between the target total direct compensation available to our Chief Executive Officer and the implied market median level and estimated top 25th percentile and top 10th percentile developed by our Compensation Consultant for the last five years:
Note: For the Total Direct Compensation Chart, the implied market median is shown as the solid blue bar, the estimated 75th percentile is shown as the light blue bar, the 90th percentile is shown as the gray bar and the target compensation for our Chief Executive Officer is shown as the orange bar.
Because incentive compensation (i.e., target annual incentive bonus and grant date fair value of long-term equity incentive awards) comprised 88% of our Chief Executive Officer’s total direct compensation opportunity for 2018, the amount of compensation our Chief Executive Officer ultimately realizes from these awards may be more or less than the cash he would have received for the target amounts, as determined in particular by our Compensation Committee’s evaluation of our performance and the long-term performance of our common stock.
Annual Total Shareholder Return
In the last five calendar years, we have delivered annual total returns to our shareholders (share price appreciation plus dividends) of -18.1% (for 2018), -7.2% (for 2017), 120.7% (for 2016), -71.3% (for 2015) and 23.3% (for 2014).
Methodology and Process
Role of Compensation Consultant in Setting Compensation
The Compensation Committee retained BDO as its independent Compensation Consultant to advise the Compensation Committee on matters related to executive and non-management director compensation for 2018. During 2017 and 2018, the Compensation Committee received advice from the Compensation Consultant with respect to the development and structure of our 2018 executive compensation program. As discussed above under “Meetings and Committees of Directors-Committees of the Board of Directors-Compensation Committee,” the Compensation Committee has concluded that we do not have any conflicts of interest with the Compensation Consultant.
Role of Peer Group and Market Analysis
When evaluating annual compensation levels for each named executive officer, the Compensation Committee, with the assistance of the Compensation Consultant and senior management, reviews publicly available compensation data and analysis for executives in our Peer Group as well as the results of compensation surveys. The Compensation Committee then uses that information to help set compensation levels for the named executive officers in the context of their roles, levels of responsibility, accountability and decision-making authority within our organization and in the context of company size relative to the other Peer Group members. While compensation data from other companies is considered, the Compensation Committee and senior management do not attempt to set compensation components to meet specific benchmarks.
The Peer Group company data and analysis that is reviewed by senior management and the Compensation Committee is simply one set of factors out of many that is used in connection with the establishment of compensation opportunities for our officers. The other factors considered include, but are not limited to, (i) other available compensation data, rankings and comparisons for similarly situated officers, (ii) effort and accomplishment on a group and individual basis, (iii) challenges faced and challenges overcome, (iv) unique skills, (v) contribution to the management team and (vi) the perception of both the Board of Directors and the Compensation Committee of performance relative to expectations and actual market/business conditions. All of these factors, including Peer Group company data and analysis, are utilized in a subjective assessment of each year’s decisions relating to base salary, annual incentive bonus and long-term equity incentive award decisions.
To reflect the market in which we compete for executive talent, the Peer Group considered by the Compensation Committee in consultation with senior management for compensation comparison purposes for 2018 included companies in three comparator groups: (1) midstream companies (“Midstream Companies”), (2) exploration and production companies (“E&Ps”), and (3) energy utilities, and our analysis placed greater weight on the compensation data reported by other publicly-traded Midstream Companies. E&Ps and utilities selected for the Peer Group, in the Compensation Committee’s opinion, provide relevant reference points because they have similar or related operations, compete in the same or similar markets, face similar regulatory challenges and require similar skills, knowledge and experience of their executive officers as we require of our executive officers.
In order to consider company size as a factor for companies in the Peer Group that are larger or smaller than we are as measured by market capitalization and total assets, with the assistance of the Compensation Consultant, compensation data for the Peer Group companies is analyzed using both traditional analysis which limits the companies that are considered to a reasonable range around our size and also with multiple regression analysis to develop a prediction of the total compensation that Peer Group companies of comparable size to us would offer similarly-situated executives. For 2018, the regressed data was analyzed separately for each of the three comparator groups and then weighted as follows to develop reference points for assessing our total executive pay opportunity relative to market practice: (1) Midstream Companies (given a 70% weighting), (2) E&Ps (given a 15% weighting) and (3) utility companies (given a 15% weighting). More traditional benchmarks of Midstream Companies without regression are also considered for the separate Peer groups with weighting and for the combined Peer groups without weighting. Additionally, we considered survey results, comparisons with individual companies and positions, and the distribution of such data and analysis. Periodically we make changes in the Peer Group to reflect the change in ownership status or size of some of the peer companies, to include additional companies and/or to create more balance in the make-up of the Peer Group. Largely due to mergers and acquisitions during the 2018 year, the Peer Group identified at the beginning of the 2018 year (and reflected as the proposed 2018 Peer Group within our 2018 proxy statement) and the Peer Group that remained relevant for our comparative purposes at the end of the 2018 differed slightly. The list below reflects the original 2018 Peer Group for purposes of determining 2018 compensation levels, although the table immediately following the original list reflects how the list was modified during the 2018 year.
Midstream Companies (the “2018 Midstream Peer Group”): Andeavor Logistics LP, Boardwalk Pipeline Partners, L.P., Buckeye Partners, L.P., DCP Midstream Partners, L.P., Enable Midstream Partners, L.P., Energy Transfer Equity, L.P., EnLink Midstream Partners, L.P., Enterprise Products Partners L.P., Genesis Energy, L.P., Kinder Morgan, Inc., Magellan Midstream Partners, L.P., NuStar Energy L.P., ONEOK, Inc., Plains GP Holdings, L.P., Tallgrass Energy Partners, LP, Tesoro Corporation and Williams Companies, Inc.
E&P peer companies: Apache Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Company, Concho Resources, Inc., Continental Resources, Inc., Devon Energy Corporation, Diamondback Energy, Inc., EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Parsley Energy, Inc., Pioneer Natural Resources Company, QEP Resources, Inc., Range Resources Corporation, RSP Permian, Inc., SM Energy Company, Southwestern Energy Company and WPX Energy, Inc.
Utility peer companies: Ameren Corporation, Atmos Energy Corporation, CenterPoint Energy, Inc., Dominion Resources, Inc., DTE Energy Company, Enbridge Inc., Entergy Corporation, EQT Corporation, MDU Resources Group, Inc., National Fuel Gas Company, NiSource Inc., Public Service Enterprise Group, Inc., SCANA Corporation, Sempra Energy, TransCanada Corporation and Xcel Energy Inc.
Based upon the recommendation of our Compensation Consultant, we made the following changes to our Peer Group during the 2018 year:
Removed from 2018 Peer Group
Added to 2018 Peer Group
Andeavor Logistics LP (Midstream)
The Southern Company (Utilities)
DCP Midstream Partners, L.P. (Midstream)
Tesoro Corporation (Midstream)
RSP Permian, Inc.(E&P)
SCANA Corporation (Utilities)
Our final 2018 Peer Group had a number of companies that overlapped with the companies comprising our 2017 Peer Group, although similar to the 2018 year, we made changes to the 2017 Peer Group during the 2017 year between the beginning and ending of the 2017 year. The final 2018 Peer Group differs from the final 2017 Peer Group as follows:
Removed from the Final 2017 Peer Group
Added to the Final 2017 Peer Group
The Southern Company (Originally removed from Midstream; later added to Utilities)
Andeavor Logistics LP (Midstream)
Tesoro Corporation (Midstream)
SCANA Corp. (Utilities)
Senior management and the Compensation Committee review our compensation-setting practices and Peer Group companies on at least an annual basis. See “-Changes for 2019-2019 Peer Group” for a description of the changes that were made to the Peer Group for 2019 compensation purposes.
Role of Senior Management in Establishing Compensation for Named Executive Officers
Typically, under the direction of the Compensation Committee, senior management consults with the Compensation Consultant and reviews market data and evaluates relevant compensation levels and compensation program elements towards the end of each fiscal year. Based on these consultations and assessments of performance relative to our business priorities, senior management and the Compensation Consultant submits emerging conclusions to the Chairman of the Compensation Committee, meets periodically with the full Compensation Committee together with Compensation Consultant relative to process and performance, and subsequently, provides a proposal to the Chairman of the Compensation Committee. The proposal includes a recommendation of base salary, target annual incentive bonus opportunity and long-term equity incentive awards to be paid or awarded to executive officers for the next fiscal year. In addition, the proposal includes a recommendation regarding the annual incentive bonus amount to be paid for the current fiscal year.
The Chairman of the Compensation Committee reviews and discusses the proposal with senior management and the Compensation Consultant and may discuss it with the other members of the Compensation Committee, other members of the Board of Directors and/or the full Board of Directors. The Chairman of the Compensation Committee may request that senior management and/or the Compensation Consultant provide him with additional information or reconsider or revise the proposal. The resulting recommendations are then submitted for consideration to the full Compensation Committee, which typically meets separately with the Compensation Consultant and typically discusses the recommendations with the other members of the Board of Directors. The final compensation decisions for the named executive officers are made by the Compensation Committee and reported to the Board of Directors.
Our senior management members typically have no other role in determining compensation for our named executive officers. The Compensation Committee may delegate the approval of equity-based award grants and other transactions and responsibilities regarding the administration of our equity compensation program to the Executive Chairman of the Board or the Chief Executive Officer with respect to employees and officers other than our Section 16 officers. Our executive officers are delegated the authority and responsibility to determine the compensation for all other employees.
Components of Executive Compensation Program for Fiscal 2018
Base Salary
The base salaries for our named executive officers are set and reviewed annually by the Compensation Committee. Base salaries for our named executive officers have been established based on Peer Group analysis and historical salary levels for these officers, as well as the relationship of their salaries to those of our other executive officers, taking into consideration the value of the total direct compensation opportunities available to our executive officers, including the annual incentive bonus and long-term equity incentive award components of our compensation program. The other factors listed above under “-Methodology and Process-Role of Peer Group and Market Analysis” are also considered.
For 2018, the Compensation Committee authorized base salary increases for all of the named executive officers in order to align the total direct compensation of these individuals more closely with the total direct compensation provided to similarly situated executives at companies within our 2018 Peer Group, considering company size, and to reflect professional growth and the assumption of additional responsibilities. The 2018 base salary rates for our named executive officers were as follows:
Annual Incentive Bonus
For 2018, our named executive officers were eligible to receive annual incentive bonuses under the 2018 Annual Incentive Compensation Plan (the “2018 Bonus Plan”), which was approved by the Compensation Committee in January 2018. The funding of the bonus pool and the payment of individual bonuses to executive management, including our named executive officers, are subject to the sole discretion of the Compensation Committee (following recommendations from our Chief Executive Officer) and will generally be determined near or following the end of the year to which the bonus relates.
Target Bonus Amounts. Each named executive officer’s target bonus amount is equal to the product of the officer’s base salary (at the rate in effect as of the last day of the year to which the bonus relates) and the officer’s target bonus percentage. For purposes of the 2018 Bonus Plan, the percentage of base salary that was set as the “target” amount for each named executive officer’s bonus was as follows:
For 2018, the target bonus percentage for each of the named executive officers (other than Mr. Chung) was increased to align their total direct compensation more closely with the total direct compensation provided to similarly situated executives.
The Chief Executive Officer and the Compensation Committee relied on the Compensation Consultant and market data from Peer Group companies and broader industry compensation practices to establish the target bonus percentages for the named executive officers and the applicable threshold, target and maximum percentage levels for funding the bonus pool, which are generally consistent with both Peer Group company and broader energy compensation practices.
2018 Bonus Plan Funding Level and Assessment of Business Priorities. The Compensation Committee, after consultation with the Chief Executive Officer, established the following overall threshold, target and maximum levels for the 2018 Bonus Plan: (i) 50% of the target amount of the bonus pool would be funded in the event that the Compensation Committee determined that our business priorities had been met for the year at a threshold level; (ii) 100% of the target amount of the bonus pool would be funded in the event that the Compensation Committee determined that our business priorities had been met for the year at a target level; and (iii) 200% of the target amount of the bonus pool would be funded in the event that the Compensation Committee determined that our business priorities had been met for the year at a maximum level. While the established threshold, target and maximum levels provide general guidelines in determining the funding level of the bonus pool each year, senior management recommends a funding level to the Compensation Committee based on our achievement of specified business priorities for the year and other factors, and the Compensation Committee ultimately determines the total amount to be allocated to the bonus pool in its sole discretion based on its assessment of the business priorities and our overall performance for the year.
For purposes of determining the actual funding level of the bonus pool and the amount of individual bonus awards under the 2018 Bonus Plan, the Compensation Committee focused on the business priorities listed in the table below. The 2018 business priorities are the same eight business priorities as in effect for 2017, except that the priority related to execution on major capital and development projects has been modified to add staffing for the new facilities. These priorities are not objective in nature - they are subjective, and performance in regard to these priorities is ultimately evaluated by the Compensation Committee in its sole discretion, informed by monthly and quarterly reports from management and ongoing dialogue concerning the priorities. As such, success does not depend on achieving a particular target; rather, success is evaluated based on past norms, expectations and unanticipated obstacles or opportunities that arise. For example, hurricanes and deteriorating or changing market conditions may alter the priorities initially established by the Compensation Committee such that certain performance that would otherwise be deemed a negative may, in context, be a positive result. This subjectivity allows the Compensation Committee to account for the full industry and economic context of our actual performance and that of our personnel. The Compensation Committee considers all strategic priorities and reviews performance against the priorities and context but does not apply a formula or assign specific weightings to the strategic priorities in advance.
2018 Business Priority
Committee Consensus
Overall Assessment
Execute on all business dimensions, including the 2018 business plan and public guidance
Exceeded
• Excellent execution across our businesses
• Year-over-year volume growth of about 17% for Field G&P including 24% growth for the Permian; fractionation volumes increased 20%
• Met guidance for volumes in both G&P and for our LPG exports
• Achieved dividend coverage guidance of about 1.0x
• Excellent balance sheet and liquidity management while funding approximately $2.7 billion in net growth investments and maintaining flat dividend per share
• Very strong commercial and operational customer focus during the year
Continue priority emphasis and strong performance relative to a safe workplace
Achieved
• Strong track record and performance regarding safety and compliance in all aspects of our business, including ongoing training and environmental and regulatory compliance; continued industry recognition through safety awards
Reinforce business philosophy and mindset that promote compliance in all aspects of our business including environmental and regulatory compliance
Exceeded
• Improved ES&H organization and processes to respond to growth including enhanced communication, industry advocacy and compliance tracking; received industry recognition and awards for safety and compliance practices
Continue to attract and retain the operational and professional talent needed in our businesses
Exceeded
• Successful talent hiring and retention while continuing organizational realignments to streamline operations, manage growth and to provide development opportunities for employees
Continue to control all costs-operating, capital and general and administrative (“G&A”) consistent with the existing business environment
Achieved
• Continued focus on controlling costs despite significant increase in assets and volumes
Execute on major capital and development projects-finalizing negotiations, completing projects on time and on budget, and optimizing economics and capital funding, and staffing for the new facilities
Exceeded
• 2018 net growth investments of about $2.7 billion completed or on track to be completed generally on schedule and on budget, including
• Start-up of 250 MMcf/d Wildcat Plant in Permian Delaware
• Start-up of 200 MMcf/d Joyce Plant in Permian Midland
• Start-up of 200 MMcf/d Johnson Plant in Permian Midland
• Start-up of 150 MMcf/d Hickory Hills Plant in Southern Oklahoma
• Significant progress on Grand Prix pipeline
• Significant progress on Targa Fractionation Train 6
• Significant progress on several other processing plants including Hopson, Pembrook, Little Missouri IV and others
Pursue selected growth opportunities, including gathering and processing (“G&P”) build outs, fee-based capital expenditure projects, and potential purchases of strategic assets
Strongly Exceeded
• Continued success growing Targa’s footprint in Gathering and Processing and continued to expand customer relationships across all areas
• Agreements for several strategic joint ventures, completed in 2018
• JV in Badlands with Hess Midstream
• Expanded JV with Sanchez in South Texas
• Continued development of our potential future expansion project portfolio including the Williams NGL agreement and related expansion of Grand Prix executed in early 2019
Pursue commercial and financial approaches to achieve maximum value and manage risks, including contract, credit, inventory, interest rate and commodity price exposures
Exceeded
• Strong credit, inventory, hedging and balance sheet management
• Insignificant write offs and proactive management of contractual relationships associated with customer financial issues
• Increased volumes and margins in Field G&P through contract renewals and new dedications
After assessing the results of the 2018 business priorities as summarized above, the Compensation Committee determined in January 2019 that overall performance relative to the 2018 business priorities substantially exceeded expectations. This subjective assessment that performance substantially exceeded expectations was based on a qualitative business assessment rather than a mechanical, quantitative determination of results across each of the business priorities, and occurred with the background and ongoing context of (i) refinements of the 2018 business priorities by the Board of Directors and the Compensation Committee, (ii) continued discussion and active dialogue among the Board of Directors and the Compensation Committee and management about priorities and performance, including routine reports sent to the Board of Directors and the Compensation Committee, (iii) detailed monthly performance communications to the Board of Directors, (iv) presentations and discussions in subsequent Board of Directors and Compensation Committee meetings, and (v) further discussion among the Board of Directors and Compensation Committee of our performance relative to expectations near the end and following the end of 2018. The extensive business and board of director experience of the members of the Compensation Committee and of our Board of Directors provides the perspective to make this subjective assessment in a qualitative manner and to evaluate overall management performance and the performance of individual executive officers.
Based on the Compensation Committee’s assessment of overall performance of the 2018 business priorities, the Compensation Committee, in its sole discretion, approved an annual bonus pool equal to 170% of the target level under the 2018 Bonus Plan.
Individual Performance Multiplier. The Compensation Committee also evaluated the executive group and each officer’s individual performance for the year and determined that there were no special circumstances that would be quantified applicable to any named executive officer’s performance for 2018 other than Ms. Kneale. As a result, the Compensation Committee determined that a performance multiplier of 1.0x should be applied to each named executive officer (other than Ms. Kneale) for 2018 based on the officer’s individual performance and performance as part of the executive team. Ms. Kneale received an individual multiplier of 1.25x due to her significant contributions during 2018.
Settlement of 2018 Bonus Awards. In light of the current industry market conditions and the Company’s resulting focus on reducing cash expenses, the Compensation Committee also approved settlement of the 2018 bonuses solely in restricted stock units awards for our Chief Executive Officer and our Chairman, instead of all-cash bonuses.
Specifically, the Compensation Committee determined that 100% of our Chief Executive Officer’s total bonus would be settled in the form of restricted stock unit awards, resulting in him receiving restricted stock unit awards corresponding to approximately 170% of his target bonus amounts under the 2018 Bonus Plan. The number of restricted stock units awarded to the Chief Executive Officer was determined by dividing the total dollar value allocated to the bonus amount by the ten-day average closing price of the shares of common stock measured over a period of time prior to the date of grant ($41.04). These restricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officer through that date or fulfillment of certain service related requirements following retirement and he will receive a cash payment during the period that the awards are outstanding equal to each dividend paid with respect to a share of common stock times the number of restricted stock units awarded. The following table reflects the awards actually received by our named executive officers under the 2018 Bonus Plan, including the value of restricted stock unit awards received:
Long-Term Equity Incentive Awards
In connection with our initial public offering in December 2010, we adopted the 2010 Stock Incentive Plan (the “Stock Incentive Plan”) under which we may grant to the named executive officers, other key employees, consultants and directors certain equity-based awards, including restricted stock, restricted stock units, bonus stock and performance-based awards. At the 2017 Annual Meeting, our shareholders approved the amendment and restatement of the Stock Incentive Plan in order to extend the term of the Stock Incentive Plan and make available additional shares of common stock for the future grant of equity-based awards to our officers, employees, consultants and directors.
In addition, prior to the TRC/TRP Merger, the General Partner sponsored and maintained the Targa Resources Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”), under which the General Partner could grant equity-based awards related to the Partnership’s common units to individuals, including the named executive officers, who provide services to the Partnership. In connection with the TRC/TRP Merger, we adopted and assumed the Long-Term Incentive Plan and outstanding awards thereunder, and amended and restated the plan and renamed it the Targa Resources Corp. Equity Compensation Plan (the “Equity Compensation Plan”). We continued to maintain the Equity Compensation Plan during 2018. However, since the number of shares reserved under the Equity Compensation Plan had been substantially exhausted as of the end of 2016, the Company no longer intends to continue making grants under the Equity Compensation Plan. As of the end of 2018, none of our named executive officers held outstanding awards pursuant to the Equity Compensation Plan.
Form and Amount of Equity Awards. Long-term equity incentive awards to our named executive officers under the Stock Incentive Plan are generally made near the beginning of each year. For 2018, the Compensation Committee awarded long-term equity incentive awards in the form of both restricted stock unit and performance share unit awards under our Stock Incentive Plan. The vesting of the performance share units is dependent on the satisfaction of a combination of certain service-related conditions and the Company’s total shareholder return (“TSR”) relative to the TSR of a specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periods. For 2018, the value of the long-term equity incentive component of our named executive officers’ compensation was allocated approximately (i) fifty percent (50%) to restricted stock unit awards under the Stock Incentive Plan and (ii) fifty percent (50%) to equity-settled performance share unit awards under the Stock Incentive Plan.
The Compensation Committee determines the amount of long-term equity incentive awards under the Stock Incentive Plan that it believes are appropriate as a component of total compensation for each named executive officer based on its decisions regarding each named executive officer’s total compensation targets. The total dollar value of long-term equity incentive awards for each named executive officer for a given year is typically equal to a specified percentage of the officer’s base salary; however, the Compensation Committee may, in its discretion, award additional long-term equity incentive awards if deemed appropriate. The number of shares subject to each award is determined by dividing the total dollar value allocated to the award by the ten-day average closing price of the shares measured over a period of time prior to the date of grant. For executive awards granted in 2018, the specified percentage of each named executive officer’s base salary used for purposes of determining the amount of long-term equity incentive awards granted and the corresponding dollar values are set forth in the following table:
For 2018, the Compensation Committee approved increases in the percentage of base salary used to determine the total dollar value of the annual long-term equity incentive awards granted to certain of the named executive officers.
2018 Restricted Stock Unit Awards. On January 17, 2018, our named executive officers were awarded equity-settled restricted stock units under the Stock Incentive Plan in the following amounts: (i) 46,987 restricted stock units to Mr. Perkins, (ii) 26,383 restricted stock units to Mr. Meloy, (iii) 7,915 restricted stock units to Ms. Kneale, (iv) 11,935 restricted stock units to Mr. McDonie, (v) 11,935 restricted stock units to Mr. Pryor and (vi) 13,191 restricted stock units to Mr. Chung. These restricted stock units vest in full on the third anniversary of the grant date, subject to the officer’s continued service or if, from the date of the executive’s retirement through the third anniversary of the grant date, the executive has either performed consulting services for us or refrained from working for one of our competitors or in a similar role for another company (however, directorships at non-competitors are permitted). The Compensation Committee believes these continued vesting provisions following retirement allow the Company to benefit from employee non-compete obligations and ongoing access to cooperative employees, further align our executives’ interests with those of our shareholders and help attract and retain key employees.
Accelerated vesting provisions applicable to these awards in the event of certain terminations of employment and/or a change in control are described in detail below under “Executive Compensation-Potential Payments Upon Termination or Change in Control-Stock Incentive Plan.” During the period the restricted stock units are outstanding and unvested, we accrue any dividends paid by us in an amount equal to the dividends paid with respect to a share of common stock times the number of restricted stock units awarded. At the time the restricted stock units vest, the named executive officers will receive a cash payment equal to the amount of dividends accrued with respect to such named executive officer’s vested restricted stock units.
Equity-Settled Performance Share Units. On January 17, 2018, our named executive officers were awarded equity-settled performance share units under the Stock Incentive Plan in the following target amounts: (i) 46,987 performance share units to Mr. Perkins, (ii) 26,383 performance share units to Mr. Meloy, (iii) 7,915 performance share units to Ms. Kneale, (iv) 11,935 performance share units to Mr. McDonie, (v) 11,935 performance share units to Mr. Pryor and (vi) 13,191 performance share units to Mr. Chung. The number of shares subject to each award is determined by dividing the total dollar value allocated to the award by the ten-day average closing price of the shares measured over a period prior to the date of grant. The performance share units, which are designed to settle in shares of Company common stock, are intended to further align the interests of the named executive officers and other executive officers with those of the Company’s shareholders and provide meaningful incentives to the management team to consistently increase shareholder value over the long term.
The vesting of these awards is dependent on the satisfaction of certain service-related conditions and the Company’s TSR relative to the TSR of the members of the LTIP Peer Group measured over designated periods. For the 2018 performance share units, the LTIP Peer Group is composed of the Company and the following other companies:
Boardwalk Pipeline Partners L.P.
NuStar Energy, L.P.
Buckeye Partners, L.P.
ONEOK, Inc.
DCP Midstream Partners L.P.
Plains GP Holdings, L.P.
Enable Midstream Partners L.P.
Tallgrass Energy Partners, L.P.
EnLink Midstream Partners L.P.
Williams Companies, Inc.
Genesis Energy, L.P.
The LTIP Peer Group is a subset of the 2018 Midstream Peer Group modified to include only those companies closest in size to the Company for purpose of the TSR comparison. The Compensation Committee has the ability to modify the LTIP Peer Group in the event a company listed above ceases to be publicly traded or another significant event occurs and a company is determined to no longer be one of the Company’s peers. Boardwalk Pipeline Partners L.P. (“Boardwalk”) and Tallgrass Energy Partners, L.P. (“Tallgrass”) were both acquired during 2018 and ceased to be publicly traded. A decision whether or not to replace Boardwalk and Tallgrass will be determined by the Compensation Committee on or prior to the vesting of the awards.
The overall performance period for the 2018 performance share units begins on January 1, 2018 and is designated to end on December 31, 2020, and the TSR performance factor is determined by the Compensation Committee at the end of the overall performance period based on relative performance over the designated weighting periods as follows: (i) 25% based on annual relative TSR for the first year, (ii) 25% based on annual relative TSR for the second year, (iii) 25% based on annual relative TSR for the third year, and (iv) the remaining 25% based on cumulative relative TSR over the entirety of the three-year performance period. With respect to each weighting period, the Compensation Committee determines the “guideline performance percentage,” which could range from 0% to 250%, based upon the Company’s relative TSR performance for the applicable period compared to the LTIP Peer Group. For performance results in an applicable weighting period that fall between (i) the 1st percentile and the 25th percentile of the LTIP Peer Group, the guideline performance percentage would be 0%, (ii) the 25th percentile and the 50th percentile, the guideline performance percentage would be interpolated between 50% and 100%, and (iii) the 50th percentile and 75th percentile, the guideline performance percentage would be interpolated between 100% and 250%. If the Company’s performance was above the 75th percentile of the LTIP Peer Group for the applicable period, the guideline performance percentage would be 250%.
The overall TSR performance factor guideline will be calculated by averaging the guideline performance percentage for each weighting period, and the average percentage may then be decreased or increased by the Compensation Committee in its discretion in order to address factors such as changes to the performance peers, anomalies in trading during the selected trading days or other business performance matters. For these purposes, relative TSR performance is generally determined based on the comparison of “total return” of a share of the Company’s common stock for the applicable period to the “total return” of a common share/unit of each member of the LTIP Peer Group for the performance period, measured based on (i) the average closing price of each company’s share/unit for the first ten trading days of the applicable period, and (ii) the sum of (a) the average closing price for each company’s share/unit for the first ten trading days immediately following the last day of the applicable period (or, in the discretion of the Compensation Committee, for a specified consecutive ten day trading period during the last month of the applicable period), plus (b) the aggregate amount of dividends/distributions paid with respect to such share/unit during such period.
Provided a named executive officer remains continuously employed through the end of 2020, then vesting will occur, as soon as practicable following December 31, 2020, in a number of performance share units equal to the target number awarded multiplied by the final Compensation Committee determined TSR performance factor, and vested performance share units will be settled by the issuance of Company common stock. In addition, a named executive officer will be considered to have remained continuously employed if, from the date of the executive’s retirement through the end of 2020, the executive either performed consulting services for us or refrained from working for one of our competitors or in a similar role for another company (however, directorships at non-competitors would be permitted). The performance share units would remain subject to the applicable performance-based vesting requirements described above during such period.
Accelerated vesting provisions applicable to these awards in the event of certain terminations of employment and/or a change in control are described in detail below under “Executive Compensation-Potential Payments Upon Termination or Change in Control-Stock Incentive Plan.” During the overall performance period for which the performance share units are outstanding, the Company accrues any cash dividends paid by the Company to holders of common stock in an amount equal to the cash dividends paid with respect to a share of common stock times the target number of performance share units awarded. At the time the performance share units are settled, the named executive officers would also receive a cash payment equal to the product of the amount of cash dividends accrued with respect to a share of common stock times the TSR performance factor.
Performance/Retention Awards. In recognition of past performance and to enhance retention, on January 12, 2018, the Compensation Committee also awarded a special grant to Mr. Perkins. The special performance/retention award was granted in the form of restricted stock units that vest 50% on December 31, 2018 and 50% on December 31, 2019, subject to his continued employment through the applicable vesting date. Mr. Perkins is the only named executive officer who received a special performance/retention award, and he received 80,000 restricted stock units.
Severance and Change in Control Benefits
The Executive Officer Change in Control Program (the “Change in Control Program”), in which each of our named executive officers is eligible to participate, provides for post-termination payments following a qualifying termination of employment in connection with a change in control event, or what is commonly referred to as a “double trigger” benefit. The vesting of certain of our long-term equity incentive compensation awards accelerates upon a change in control irrespective of whether the officer is terminated, and/or upon certain termination of employment events, such as death or disability. Please see “Executive Compensation-Potential Payments Upon Termination or Change in Control” below for further information.
We believe that the Change in Control Program and the accelerated vesting provisions of our long-term equity incentive awards are important retention tools for us and are consistent with practices common among our industry peers. Accelerated vesting of long-term equity incentive awards upon a change in control enables our named executive officers to realize value from these awards consistent with value created for investors upon the closing of a transaction. In addition, we believe that post-termination benefits may, in part, mitigate some of the potential uncertainty created by a potential or actual change in control transaction, including with respect to the future employment of the named executive officers, thus allowing management to focus on the business transaction at hand.
Retirement, Health and Welfare, and Other Benefits
We offer eligible employees participation in a section 401(k) tax-qualified, defined contribution plan (the “401(k) Plan”) to enable employees to save for retirement through a tax-advantaged combination of employee and company contributions and to provide employees the opportunity to directly manage their retirement plan assets through a variety of investment options. Our employees, including our named executive officers, are eligible to participate in our 401(k) Plan and may elect to defer up to 30% of their eligible compensation on a pre-tax basis (or on a post-tax basis via a Roth contribution) and have it contributed to the 401(k) Plan, subject to certain limitations under the Internal Revenue Code of 1986, as amended (the “Code”). In addition, we make the following contributions to the 401(k) Plan for the benefit of our employees, including our named executive officers: (i) 3% of the employee’s eligible compensation, and (ii) an amount equal to the employee’s contributions to the 401(k) Plan up to 5% of the employee’s eligible compensation. In addition, we may also make discretionary contributions to the 401(k) Plan for the benefit of employees depending on our performance. Company contributions to the 401(k) Plan may be subject to certain limitations under the Code for certain employees. We do not maintain a defined benefit pension plan or a nonqualified deferred compensation plan for our named executive officers or other employees.
All full-time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, life insurance, dental coverage and disability insurance. It is the Compensation Committee’s policy not to pay for perquisites for any of our named executive officers, other than minimal parking subsidies.
Changes for 2019
In consultation with the Compensation Consultant, the Compensation Committee has reviewed our executive compensation program and has made certain changes for 2019, which are described in more detail below. The analysis provided by the Compensation Consultant indicated that the total target direct compensation of our Chief Executive Officer, President, Chief Financial Officer and other named executive officers was below the total direct compensation levels of similarly situated executives at companies in our Peer Group, evaluating for example, the Peer Group pay programs considering company size using a regression analysis along with traditional compensation peer group analysis, other available surveys and analysis.
In order to align the total compensation of our named executive officers more closely with that of similarly situated officers the Compensation Committee has approved increases in the salary levels and the incentive-based compensation opportunities of the named executive officers as described below.
2019 Peer Group
In light of changes to companies in the overall industries in which we operate and compete for executive talent and based upon the recommendation of our Compensation Consultant, during our annual reconsideration of the Peer Group, we made certain changes to the final 2018 Peer Group used for compensation comparison purposes to create the 2019 Peer Group. We believe the 2019 Peer Group provides a relevant and complete set of peers based on changes in the current circumstances of the included companies, including such companies’ size, organization, operations, market presence, business challenges and completed or announced corporate transactions.
Specifically, we removed Boardwalk Pipeline Partners, L.P. from our Midstream Companies group, Dominion Resources, Inc. from our utilities group and RSP Permian, Inc. from our E&P Group. In addition, we added Enbridge Energy Partners, L.P. to the Midstream Companies group. As a result of the above changes, the 2019 Peer Group companies (for purposes of determining 2019 compensation levels) are:
Midstream Companies: Buckeye Partners, L.P., Enable Midstream Partners, L.P., L.P., Energy Transfer Equity, L.P., Enbridge Energy Partners, L.P., EnLink Midstream Partners, L.P., Enterprise Products Partners L.P., Genesis Energy, L.P., Kinder Morgan, Inc., Magellan Midstream Partners, L.P., NuStar Energy L.P., ONEOK, Inc., Plains GP Holdings, L.P., Tallgrass Energy Partners, L.P. and Williams Companies, Inc.
E&P peer companies: Apache Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Company, Concho Resources, Inc., Continental Resources, Inc., Devon Energy Corporation, Diamondback Energy, Inc., EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Parsley Energy, Inc., Pioneer Natural Resources Company, QEP Resources, Inc., Range Resources Corporation, SM Energy Company, Southwestern Energy Company and WPX Energy, Inc.
Utility peer companies: Ameren Corporation, Atmos Energy Corporation, CenterPoint Energy, Inc., DTE Energy Company, Enbridge Inc., Entergy Corporation, EQT Corporation, MDU Resources Group, Inc., National Fuel Gas Company, NuSource Inc., Public Service Enterprise Group Inc., Sempra Energy, TransCanada Corporation, Xcel Energy Inc. and The Southern Company.
Base Salary
The Compensation Committee has authorized, and executive management will implement, the following base salaries for our named executive officers effective March 1, 2019:
The Compensation Committee authorized base salary increases for the named executive officers, along with certain adjustments in annual bonus incentive targets and grant date fair values of long-term equity incentive awards (as described below), in order to align the total direct compensation of these individuals more closely with the total direct compensation provided to similarly situated executives and the assumption of additional responsibilities.
Annual Incentive Bonus
In preparing our business plan for 2019, senior management developed and proposed a set of business priorities to the Compensation Committee. The Compensation Committee discussed and adopted the business priorities proposed by senior management for purposes of the 2019 Annual Incentive Compensation Plan (the “2019 Bonus Plan”). The 2019 business priorities are the same eight business priorities as in effect for 2018.
The overall threshold, target and maximum funding percentages for the 2019 Bonus Plan remain the same as for the 2018 Bonus Plan. The target bonus percentages of certain of the named executive officers have been increased for 2019. The following table shows the target bonus percentages for our named executive officers effective March 1, 2019:
As with the 2018 Bonus Plan, funding of the bonus pool and the payment of individual bonuses to executive management, including our named executive officers, is subject to the sole discretion of the Compensation Committee.
Long-Term Equity Incentive Awards
The Compensation Committee also approved increases in the percentage of base salary used to determine the total dollar value of the annual long-term equity incentive awards granted to certain of the named executive officers. The following table shows the new percentages approved for long-term incentive awards for our named executive officers effective for 2019:
For 2019, the Compensation Committee determined to grant a combination of restricted stock units and performance share units to our named executive officers under the Stock Incentive Plan. Specifically, for 2019, the value of the long-term equity incentive component of our named executive officers’ compensation was allocated approximately (A) 50% to restricted stock units and (B) 50% to performance share units.
Restricted Stock Unit Awards. On January 17, 2019, our named executive officers were awarded equity-settled restricted stock units under the Stock Incentive Plan in the following amounts: (i) 79,496 restricted stock units to Mr. Perkins, (ii) 36,550 restricted stock units to Mr. Meloy, (iii) 19,493 restricted stock units to Ms. Kneale, (iv) 19,798 restricted stock units to Mr. McDonie, (v) 19,798 restricted stock units to Mr. Pryor and (vi) 17,057 restricted stock units to Mr. Chung. The number of shares subject to each award is determined by dividing the total dollar value allocated to the award by the ten-day average closing price of the shares measured over a period prior to the date of grant. These restricted stock units vest in full on the third anniversary of the grant date, subject to the officer’s continued service or fulfillment of certain service related requirements following retirement.
Equity-Settled Performance Share Units. Our named executive officers also received an annual award of equity-settled performance share units under the Stock Incentive Plan for 2019. On January 17, 2019, our named executive officers were awarded equity-settled performance share units under the Stock Incentive Plan in the following target amounts: (i) 79,496 performance share units to Mr. Perkins, (ii) 36,550 performance share units to Mr. Meloy, (iii) 19,493 performance share units to Ms. Kneale, (iv) 19,798 performance share units to Mr. McDonie, (v) 19,798 performance share units to Mr. Pryor and (vi) 17,057 performance share units to Mr. Chung. The number of shares subject to each award is determined by dividing the total dollar value allocated to the award by the ten-day average closing price of the shares measured over a period prior to the date of grant. The performance share units, which are designed to settle in shares of Company common stock, are intended to further align the interests of the named executive officers and other executive officers with those of the Company’s shareholders and provide meaningful incentives to the management team to consistently increase shareholder value over the long term. Please see “-Components of Executive Compensation Program for Fiscal 2018-Long-Term Equity Incentive Awards- Equity-Settled Performance Share Units.”
The vesting of these awards is dependent on the satisfaction of certain service-related conditions and the Company’s TSR relative to the TSR of the members of the LTIP Peer Group measured over designated periods. As a result of peer companies included in our 2018 LTIP Peer Group being acquired by other companies during 2018 and 2019 we did not include Boardwalk Pipeline Partners L.P., Enlink Midstream Partners LP (to be acquired by Enlink Midstream LLC in 2019) and Tallgrass Energy Partners LP and we added Crestwood Equity Partners LP, Enlink Midstream LLC and Tallgrass Energy, LP. For the 2019 performance share units, the LTIP Peer Group is composed of the Company and the following other companies:
Buckeye Partners, L.P.
NuStar Energy, L.P.
Crestwood Equity Partners LP
ONEOK, Inc.
DCP Midstream Partners L.P.
Plains GP Holdings, L.P.
Enable Midstream Partners, LP
Tallgrass Energy, LP
Enlink Midstream LLC
Williams Companies, Inc.
Genesis Energy, L.P.
This peer group is a subset of the Midstream Peer Group which considers company size and is restricted to companies closer to the size of the Company for the purpose of the TSR comparison. The Compensation Committee has the ability to modify the LTIP Peer Group each year for new grants and for evaluation upon vesting in the event a company listed above ceases to be publicly traded or another significant event occurs and a company is determined to no longer be one of the Company’s peers.
Other Compensation Matters
Accounting Considerations. We account for the equity compensation expense for our employees, including our named executive officers, under the rules of Financial Accounting Standards Board (“FASB”), Accounting Standards Codification (“ASC”) Topic 718, which requires us to estimate and record an expense for each award of long-term equity incentive compensation over the vesting period of the award. Accounting rules also require us to record cash compensation as an expense at the time the obligation is accrued.
Clawback Policy. To date, we have not adopted a formal clawback policy to recoup incentive-based compensation upon the occurrence of a financial restatement, misconduct, or other specified events. However, awards granted pursuant to the Stock Incentive Plan are subject to any written clawback policies that the Company may choose to adopt. Furthermore, restricted stock, restricted stock unit and performance share unit agreements covering grants made to our named executive officers and other employees in 2011 and later years, as applicable, include language providing that any compensation, payments or benefits provided under such an award (including profits realized from the sale of earned shares) are subject to clawback to the extent required by applicable law.
Securities Trading Policy. All of our officers, employees and directors are subject to our Insider Trading Policy, which, among other things, prohibits officers, employees and directors from engaging in certain short-term or speculative transactions involving our securities. Specifically, the policy provides that officers, employees and directors may not engage in the following transactions: (i) the purchase of our common stock on margin, (ii) short sales of our common stock, or (iii) the purchase or sale of options of any kind, whether puts or calls, or other derivative securities, relating to our common stock.
Stock Ownership Guidelines. In May 2017, our Compensation Committee adopted Stock Ownership Guidelines for our independent directors and officers. We believe that our Stock Ownership Guidelines align the interests of our named executive officers and independent directors with the interests of our stockholders. The guidelines provide that our Chief Executive Officer should own common stock of the Company having a market value of five times base salary, the other named executive officers should own common stock of the Company having a market value of three times their respective base salaries, and our independent directors should own common stock of the Company having a market value of five times their respective annual cash retainers. The guidelines were established with advice from the Compensation Consultant.
The CEO and executive officers have five years from the adoption of the Stock Ownership Guidelines to meet the applicable ownership levels (or with respect to new executive officers, from such later date as they are appointed an executive officer). The directors have five years from the adoption of the guidelines to meet the applicable ownership levels (or with respect to new directors, from such later date as they are elected a director). Stock owned directly by an officer or independent director as well as unvested restricted stock units will count for purposes of determining stock ownership levels.
Tax Considerations. With respect to the 2018 year, Section 162(m) of the Internal Revenue Code (“Section 162(m)”) generally limited the deductibility by a corporation of compensation in excess of $1,000,000 paid to certain executive officers for services provided to that corporation. Due to the fact that our applicable executive officers provide services to both us and to certain non-corporate subsidiaries, we have historically designed incentive awards that are not subject to the deduction limitations of Section 162(m).
Compensation Risk Assessment
The Compensation Committee reviews the relationship between our risk management policies and compensation policies and practices each year and, for 2018, has concluded that we do not have any compensation policies or practices that expose us to excessive or unnecessary risks that are reasonably likely to have a material adverse effect on us. Because our Compensation Committee retains the sole discretion for determining the actual amount paid to executives pursuant to our annual incentive bonus program, our Compensation Committee is able to assess the actual behavior of our executives as it relates to risk-taking in awarding bonus amounts. In addition, the performance objectives applicable to our annual bonus program consist of a combination of six or more diverse company-wide and business unit goals, including commercial, operational and financial goals to support our business plan and priorities, which we believe lessens the potential incentive to focus on meeting certain short-term goals at the expense of longer-term risk. Further, our use of long-term equity incentive compensation for 2018 with three-year vesting periods serves our executive compensation program’s goal of aligning the interests of executives and shareholders, thereby reducing the incentives to unnecessary risk-taking.
Compensation Committee Report
In fulfilling its oversight responsibilities, the board of directors of our General Partner has reviewed and discussed with management the Compensation Discussion and Analysis contained in our Annual Report on Form 10-K for the year ended December 31, 2018. Based on these reviews and discussions, the board of directors of our General Partner recommended that the Compensation Discussion and Analysis be included in our Annual Report on Form 10-K for the year ended December 31, 2018 for filing with the SEC.
The information contained in this report shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act.
Charles R. Crisp
Ershel C. Redd Jr.
Rene R. Joyce
James W. Whalen
Joe Bob Perkins
Waters S. Davis, IV
Laura C. Fulton
Robert B. Evans
Chris Tong
Michael A. Heim
Beth A. Bowman
EXECUTIVE COMPENSATION
Summary Compensation Table for 2018
The following Summary Compensation Table sets forth the compensation of our named executive officers for 2018, 2017 and 2016. Additional details regarding the applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table.
(1)
For 2018, amounts reported in the “Bonus” column represents the portion of the bonus awarded pursuant to our 2018 Bonus Plan that was paid to the named executive officers in cash. The Compensation Committee approved settlement of the 2018 bonuses in a combination of cash and restricted stock unit awards. Specifically, the Compensation Committee determined that 100% of our Chief Executive Officer’s total bonus would be settled in the form of restricted stock unit awards, resulting in the Chief Executive Officer receiving restricted stock unit awards corresponding to approximately 170% of his target bonus amounts under the 2018 Bonus Plan. The Compensation Committee also determined that each other named executive officer’s total bonus amount would be settled in cash. The restricted stock unit awards granted to the Chief Executive Officer will vest in full three years after the date of award, subject to continued employment of the Chief Executive Officer through that date. These awards were granted on January 17, 2019 and will therefore be reported as equity award compensation in the Summary Compensation Table for 2019 in accordance with SEC rules. Please see “Compensation Discussion and Analysis-Components of Executive Compensation Program for Fiscal 2018-Annual Incentive Bonus.” As discussed above, payments pursuant to our Bonus Plan are discretionary and not based on specific objective performance measures.
(2)
Amounts reported in the “Stock Awards” column represent the aggregate grant date fair value of restricted stock unit and performance share unit awards granted under our Stock Incentive Plan in 2018 (including restricted stock unit awards granted on January 17, 2018 in connection with 100% of the bonus for the Chief Executive Officer and the 50% portion of bonuses for the other named executive officers under the 2017 Bonus Plan that we granted in the form of restricted stock units) computed in accordance with FASB ASC Topic 718, disregarding the estimate of forfeitures. Assumptions used in the calculation of these amounts are included in Note 23-Compensation Plans to our “Consolidated Financial Statements” included in our Annual Report on Form 10-K for fiscal year 2018. Detailed information about the value attributable to specific awards is reported in the table under “-Grants of Plan-Based Awards for 2018” below. The grant date fair value of each restricted stock unit subject to the restricted stock unit awards granted on January 17, 2018, assuming vesting will occur, is $51.09. The grant date fair value of each performance share unit subject to the performance share unit awards granted on January 17, 2018, assuming vesting will occur, is $81.02, which is the per unit fair value determined using a Monte Carlo Simulation valuation methodology in accordance with FASB ASC Topic 718. Assuming, instead, a payout percentage for these performance unit awards of 250%, which is the maximum payout percentage under the awards, the aggregate grant date fair value of the equity-settled performance unit awards granted on January 17, 2018 for each named executive officer is as follows: Mr. Perkins - $6,001,415; Mr. Meloy - $3,369,769; Ms. Kneale - $1,010,943; Mr. McDonie - $1,524,398; Mr. Pryor - $1,524,398; and Mr. Chung - $1,684,820. For 2017, the Compensation Committee provided that bonuses to our named executive officers under the 2017 Bonus Plan would be (i) 100% restricted stock unit awards equal to the Chief Executive Officer’s total bonus amount and (ii) a combination of cash equal to 50% of each of the other named executive officer’s total bonus amount and restricted stock unit awards equal to each of the other named executive officer’s
total bonus amount. These restricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officers through that date. Because these awards were granted on January 17, 2018, they are reported as compensation in the Summary Compensation Table for 2018 in accordance with SEC rules. For 2016, the Compensation Committee provided that bonuses to our named executive officers under the 2016 Bonus Plan would be a combination of cash equal to 50% of each officer’s total bonus amount and restricted stock unit awards equal to each officer’s total bonus amount under the 2016 Bonus Plan. These restricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officers through that date. Because these awards were granted on February 28, 2017, they are reported as compensation in the Summary Compensation Table for 2017 in accordance with SEC rules.
(3)
On January 12, 2018, the Compensation Committee awarded a special performance/retention award to Mr. Perkins. The special performance/retention award consisting of 80,000 units was granted in the form of restricted stock units that vest 50% on December 31, 2018 and 50% on December 31, 2019, subject to continued employment.
(4)
For 2018, “All Other Compensation” includes (i) the aggregate value of all employer-provided contributions to our 401(k) plan and (ii) the dollar value of life insurance premiums paid by the Company with respect to life insurance for the benefit of each named executive officer.
Grants of Plan-Based Awards for 2018
The following table and the footnotes thereto provide information regarding grants of plan-based equity awards made to the named executive officers during 2018:
(1)
The award disclosed in this row reflects a special performance/retention award granted on January 12, 2018 to Mr. Perkins.
(2)
The grants on January 17, 2018 are the annual long-term equity incentive awards for 2018 granted to our named executive officers in the form of restricted stock unit and performance share unit awards granted under our Stock Incentive Plan. For a detailed description of how performance achievements will be determined for performance share units, see “Compensation Discussion and Analysis - Components of Executive Compensation Program for Fiscal 2018 - Equity Settled Performance Share Units.
(3)
The grants on January 17, 2018 are restricted stock unit awards granted in lieu of a portion of cash payments under the 2017 Bonus Plan and in the case of Mr. Perkins, 100% of the cash payments under the 2017 Bonus Plan.
(4)
The value within the “Grant Date Fair Value of Equity Awards” column was determined by multiplying the shares awarded by the grant date fair value per share computed in accordance with FASB ASC Topic 718: $50.95 for the January 12, 2018 special performance/incentive award; $51.09 for the January 17, 2018 restricted stock unit awards; and $81.02 for the January 17, 2018 performance share units.
Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table
A discussion of 2018 salaries, bonuses, incentive plans and awards is set forth in “Compensation Discussion and Analysis,” including a discussion of the material terms and conditions of the 2018 restricted stock unit and performance share unit awards under our Stock Incentive Plan. Further discussion regarding restricted stock units granted in January 2018 in lieu of all or a portion of cash payments under our 2017 Bonus Plan are described in our proxy statement for our 2018 annual meeting of stockholders, filed with the Securities and Exchange Commission on March 29, 2018 (“2018 Proxy Statement”).
Outstanding Equity Awards at 2018 Fiscal Year-End
The following table and the footnotes related thereto provide information regarding equity-based awards outstanding as of December 31, 2018 for each of our named executive officers. None of our named executive officers held any outstanding stock option awards as of December 31, 2018.
(1)
Represents the following shares of restricted stock units under our Stock Incentive Plan held by our named executive officers:
(a)
The restricted stock units awarded January 6, 2016 vest: (i) 50% on January 6, 2020 and 50% on January 6, 2021, contingent upon continuous employment through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(b)
The restricted stock units awarded January 19, 2016 are subject to the following vesting schedule: 100% of the restricted stock units vest on January 19, 2019, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(c)
The restricted stock units awarded February 29, 2016 in settlement of awards under the 2015 Bonus Plan are subject to the following vesting schedule: 100% of the restricted stock units vest on February 28, 2019, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(d)
The restricted stock units awarded March 2, 2016 in settlement of awards under the 2015 Bonus Plan are subject to the following vesting schedule: 100% of the restricted stock units vest on February 28, 2019, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(e)
The restricted stock units awarded August 1, 2016 are subject to the following vesting schedule: 100% of the restricted stock units vest on August 1, 2019, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(f)
The restricted stock units awarded January 20, 2017 are subject to the following vesting schedule: 100% of the restricted stock units vest on January 20, 2020, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(g)
The restricted stock units awarded January 20, 2017 as a retention grant vest (i) 30% on January 20, 2021, (ii) 30% on January 20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment through the end of the performance period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(h)
The restricted stock units awarded February 28, 2017 in partial settlement of awards under the 2016 Bonus Plan are subject to the following vesting schedule: 100% of the restricted stock units vest February 28, 2020, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(i)
The restricted stock units awarded August 1, 2017 are subject to the following vesting schedule: 100% of the restricted stock units vest on August 1, 2020, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(j)
The restricted stock units awarded January 12, 2018 as a special performance/incentive grant vest on December 31, 2019, contingent upon continuous employment through the end of the performance period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(k)
The restricted stock units awarded January 17, 2018 are subject to the following vesting schedule: 100% of the restricted stock units vest on January 17, 2021, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
(l)
The restricted stock units awarded January 17, 2018 in settlement (with respect to our Chief Executive Officer) and in partial settlement (with respect to the other named executive officers) of awards under the 2017 Bonus Plan are subject to the following vesting schedule: 100% of the restricted stock units vest January 17, 2021, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.
The treatment of the outstanding restricted stock unit awards upon certain terminations of employment (including retirement) or the occurrence of a change in control is described below under “-Potential Payments Upon Termination or Change in Control.”
(2)
The dollar amounts shown are determined by multiplying the number of shares of restricted stock units reported in the table by the closing price of a share of our common stock on December 31, 2018 ($36.02), which was the last trading day of fiscal 2018. The amounts do not include any related dividends accrued with respect to the awards.
(3)
Represents the following performance share units linked to the performance of the Company’s common stock held by our named executive officers:
(a)
Reflects the target number of performance share units granted to the named executive officers on January 20, 2017 multiplied by a performance percentage of 125%, which in accordance with SEC rules is the next higher performance level under the award that exceeds 2018 performance. Vesting of these awards is contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the performance period, which ends December 31, 2019, and the Company’s performance over the applicable performance period measured against a peer group of companies. The underlying shares of stock are not issued until vesting at the end of the performance period.
(b)
Reflects the target number of performance share units granted to the named executive officers on January 17, 2018 multiplied by a performance percentage of 125%, which in accordance with SEC rules is the next higher performance level under the award that exceeds 2018 performance. Vesting of these awards is contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the performance period, which ends December 31, 2020, and the Company’s performance over the applicable performance period measured against a peer group of companies. The underlying shares of stock are not issued until vesting at the end of the performance period. The treatment of the outstanding performance share unit awards upon certain terminations of employment (including retirement) or the occurrence of a change in control is described below under “-Potential Payments Upon Termination or Change in Control.”
(4)
The dollar amounts shown are determined by multiplying the number of shares of performance share units reported in the table by the closing price of a share of our common stock on December 31, 2018 ($36.02), which was the last trading day of fiscal 2018. The amounts do not include any related dividends accrued with respect to the awards.
Option Exercises and Stock Vested in 2018
The following table provides the amount realized during 2018 by each named executive officer upon the vesting of restricted stock and restricted stock units. None of our named executive officers exercised any option awards during the 2018 year and, currently, there are no options outstanding under any of our plans.
(1)
Computed: (i) with respect to the restricted stock awards granted under our Stock Incentive Plan by multiplying the number of shares of stock vesting by the closing price of a share of common stock on the January 15, 2018 vesting date ($51.44), the August 5, 2018 vesting date ($51.63) and the December 31, 2018 vesting date ($36.02) and does not include associated dividends accrued during the vesting period, (ii) with respect to the restricted stock units (former equity-settled performance unit awards) by multiplying the number of restricted stock units vesting by the closing price of a share of common stock on June 29, 2018 ($49.49), the last trading day before the June 30, 2018 vesting date, and does not include associated distributions or dividends accrued during the vesting period, and (iii) with respect to certain of Mr. McDonie’s restricted stock units (former equity-settled performance unit awards), by multiplying the number of restricted stock units vesting by the closing price of a share of common stock on the June 26, 2018 vesting date ($49.01) and the closing price of a share of common stock on the June 28, 2018 vesting date ($50.21) and does not include associated distributions or dividends accrued during the vesting period.
Pension Benefits
Other than our 401(k) Plan, we do not have any plan that provides for payments or other benefits at, following, or in connection with, retirement.
Non-Qualified Deferred Compensation
We do not have any plan that provides for the deferral of compensation on a basis that is not tax qualified.
Potential Payments Upon Termination or Change in Control
Aggregate Payments
The table below reflects the aggregate amount of payments and benefits that we believe our named executive officers would have received under the Change in Control Program (described below) and Stock Incentive Plan upon certain specified termination of employment and/or a change in control events, in each case, had such event occurred on December 31, 2018. None of our named executive officers held awards pursuant to the Equity Compensation Plan as of December 31, 2018, therefore this plan is not described below. Details regarding individual plans and arrangements follow the table. The amounts below constitute estimates of the amounts that would be paid to our named executive officers upon each designated event, and do not include any amounts accrued through fiscal 2018 year-end that would be paid in the normal course of continued employment, such as accrued but unpaid salary and benefits generally available to all salaried employees. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time a named executive officer is actually terminated and/or a change in control actually occurs. Therefore, such amounts and disclosures should be considered “forward-looking statements.”
Executive Officer Change in Control Severance Program
We adopted the Change in Control Program on and effective as of January 12, 2012. Each of our named executive officers was an eligible participant in the Change in Control Program during the 2018 calendar year.
The Change in Control Program is administered by our Senior Vice President-Human Resources. The Change in Control Program provides that if, in connection with or within 18 months after a “Change in Control,” a participant suffers a “Qualifying Termination,” then the individual will receive a severance payment, paid in a single lump sum cash payment within 60 days following the date of termination, equal to three times (i) the participant’s annual salary as of the date of the Change in Control or the date of termination, whichever is greater, and (ii) the amount of the participant’s annual salary multiplied by the participant’s most recent “target” bonus percentage specified by the Compensation Committee prior to the Change in Control. In addition, the participant (and his eligible dependents, as applicable) will receive the continuation of their medical and dental benefits until the earlier to occur of (a) three years from the date of termination, or (b) the date the participant becomes eligible for coverage under another employer’s plan.
For purposes of the Change in Control Program, the following terms will generally have the meanings set forth below:
Cause means discharge of the participant by us on the following grounds: (i) the participant’s gross negligence or willful misconduct in the performance of his duties, (ii) the participant’s conviction of a felony or other crime involving moral turpitude, (iii) the participant’s willful refusal, after 15 days’ written notice, to perform his material lawful duties or responsibilities, (iv) the participant’s willful and material breach of any corporate policy or code of conduct, or (v) the participant’s willfully engaging in conduct that is known or should be known to be materially injurious to us or our subsidiaries.
Change in Control means any of the following events: (i) any person (other than the Partnership) becomes the beneficial owner of more than 20% of the voting interest in us or in the General Partner, (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company or the General Partner (other than to the Partnership or its affiliates), (iii) a transaction resulting in a person other than Targa Resources GP LLC or an affiliate being the General Partner of the Partnership, (iv) the consummation of any merger, consolidation or reorganization involving us or the General Partner in which less than 51% of the total voting power of outstanding stock of the surviving or resulting entity is beneficially owned by the stockholders of the Company or the General Partner, immediately prior to the consummation of the transaction, or (v) a majority of the members of the Board of Directors or the board of directors of the General Partner is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the applicable Board of Directors before the date of the appointment or election.
Good Reason means: (i) a material reduction in the participant’s authority, duties or responsibilities, (ii) a material reduction in the participant’s base compensation, or (iii) a material change in the geographical location at which the participant must perform services. The individual must provide notice to us of the alleged Good Reason event within 90 days of its occurrence and we have the opportunity to remedy the alleged Good Reason event within 30 days from receipt of the notice of such allegation.
Qualifying Termination means (i) an involuntary termination of the individual’s employment by us without Cause or (ii) a voluntary resignation of the individual’s employment for Good Reason.
All payments due under the Change in Control Program will be conditioned on the execution and non-revocation of a release for our benefit and the benefit of our related entities and agents. The Change in Control Program will supersede any other severance program for eligible participants in the event of a Change in Control, but will not affect accelerated vesting of any equity awards under the terms of the plans governing such awards.
If amounts payable to a named executive officer under the Change in Control Program, together with any other amounts that are payable by us as a result of a Change in Control (collectively, the “Payments”), exceed the amount allowed under section 280G of the Code for such individual, thereby subjecting the individual to an excise tax under section 4999 of the Code, then, depending on which method produces the largest net after-tax benefit for the recipient, the Payments shall either be: (i) reduced to the level at which no excise tax applies or (ii) paid in full, which would subject the individual to the excise tax.
The following table reflects payments that would have been made to each of the named executive officers under the Change in Control Program in the event there was a Change in Control and the officer incurred a Qualifying Termination, in each case as of December 31, 2018.
(1)
Includes 3 years’ worth of continued participation in our medical and dental plans, calculated based on the monthly employer-paid portion of the premiums for our medical and dental plans as of December 31, 2018 for each named executive officer and the officer’s eligible dependents in the following amounts: (a) Mr. Perkins - $42,489, (b) Mr. Meloy - $56,514, (c) Ms. Kneale- $0, (d) Mr. McDonie - $56,514, (e) Mr. Pryor - $56,514, and (f) Mr. Chung-$60,996.
Stock Incentive Plan
Our named executive officers held outstanding restricted stock units under our form of restricted stock unit agreement (the “Stock Agreement”), and performance share units under our form of performance share unit agreement (the “Performance Agreement”) and the Stock Incentive Plan as of December 31, 2018. If a “Change in Control” occurs and the named executive officer has (i) remained continuously employed by us from the date of grant to the date upon which such Change in Control occurs or (ii) retired following the date of grant and either performed consulting services for us or refrained from working for one of our competitors or in a similar role for another company (however, directorships at non-competitors are permitted), through the date of the Change in Control, then, in either case, (a) the restricted stock units granted to the officer under the Stock Agreement, and related dividends then credited to the officer, will fully vest on the date upon which such Change in Control occurs, and (b) the performance share units granted to the officer under the Performance Agreement and related dividends credited to the officer will vest based on a performance factor as of the date of the Change in Control determined by the Compensation Committee. The 2018 performance share units have four separate performance periods: (1) the 2018 calendar year, (2) the 2019 calendar year, (3) the 2020 calendar year, and (4) the entirety of the performance period between January 1, 2018 and December 31, 2020. Upon a Change in Control transaction, the Compensation Committee will take into account the average of the performance level achieved for each of the four performance periods, using the actual performance level achieved with respect to any completed period, and a deemed performance percentage of 100% for any performance period that has not been completed. The average percentage may then be decreased or increased by the Compensation Committee in its discretion.
Restricted stock units and performance share units granted to a named executive officer under the Stock Agreement and Performance Agreement, and related dividends then credited to the officer, will also fully vest if the named executive officer’s employment is terminated by reason of death or a “Disability” (as defined below). If a named executive officer’s employment with us is terminated for any reason other than death or Disability, then the officer’s unvested restricted stock units and performance share units are forfeited to us for no consideration, except that (other than with respect to retention grants for Mr. Perkins, Mr. Meloy, Ms. Kneale, Mr. McDonie and Mr. Pryor), if a named executive officer retires or otherwise has a voluntary resignation, the officer’s awards will continue to vest on the original vesting schedule if, from the date of the officer’s retirement or termination through the applicable vesting date, the named executive officer has either performed consulting services for us or refrained from working for one of our competitors or in a similar role for another company (however, directorships at non-competitors are permitted).
The following terms generally have the following meanings for purposes of the Stock Incentive Plan and Stock Agreements:
Affiliate means an entity or organization which, directly or indirectly, controls, is controlled by, or is under common control with, us.
Change in Control means the occurrence of one of the following events: (i) any person or group acquires or gains ownership or control (including, without limitation, the power to vote), by way of merger, consolidation, recapitalization, reorganization or otherwise, of more than 50% of the outstanding shares of our voting stock or more than 50% of the combined voting power of the equity interests in the Partnership or the General Partner, (ii) any person, including a group as contemplated by section 13(d)(3) of the Exchange Act, acquires in any twelve-month period (in one transaction or a series of related transactions) ownership, directly or indirectly, of 30% or more of the outstanding shares of our voting stock or of the combined voting power of the equity interests in the Partnership or the General Partner, (iii) the completion of a liquidation or dissolution of us or the approval by the limited partners of the Partnership, in one or a series of transactions, of a plan of complete liquidation of the Partnership, (iv) the sale or other disposition by us of all or substantially all of our assets in one or more transactions to any person other than an Affiliate, (v) the sale or disposition by either the Partnership or the General Partner of all or substantially all of its assets in one or more transactions to any person other than to an Affiliate, (vi) a transaction resulting in a person other than Targa Resources GP LLC or an Affiliate being the General Partner of the Partnership, or (vii) as a result of or in connection with a contested election of directors, the persons who were our directors before such election shall cease to constitute a majority of our Board of Directors.
Disability means a disability that entitles the named executive officer to disability benefits under our long-term disability plan.
The following table reflects amounts that would have been received by each of the named executive officers under the Stock Incentive Plan and related Stock Agreements and Performance Agreements in the event there was a Change in Control or their employment was terminated due to death or Disability, each as of December 31, 2018. The amounts reported below assume that the price per share of our common stock was $36.02, which was the closing price per share of our common stock on December 31, 2018 (the last trading day of fiscal 2018). No amounts are reported assuming retirement as of December 31, 2018, since additional conditions must be met following a named executive officer’s retirement in order for any restricted stock awards or restricted stock units to become vested.
(1)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:
(a) $3,691,474, and $1,119,125, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019;
(b) $1,020,086 and $283,483, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the 2015 Bonus Plan which are scheduled to vest February 28, 2019;
(c) $927,227 and $187,402, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;
(d) $888,747 and $183,513, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December 31, 2019;
(e) $276,490 and $48,896, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016 Bonus Plan, which are scheduled to vest on February 28, 2020;
(f) $1,440,800 and $145,600, respectively relate to the restricted stock units as a special performance/incentive grant and related dividend rights granted on January 12, 2018, which are scheduled to vest December 31, 2019;
(g) $1,692,472, and $171,033, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;
(h) $1,650,833 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in settlement of awards under the 2017 Bonus Plan, which are scheduled to vest January 17, 2021; and
(i) $1,657,353 and $167,484, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December 31, 2019.
(2)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:
(a) $1,271,470 and $385,465, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019;
(b) $450,250 and $125,125, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the 2015 Bonus Plan, which are scheduled to vest February 28, 2019;
(c) $367,044 and $74,183, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;
(d) $351,811 and $72,644 respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December 31, 2019;
(e) $1,801,000 and $364,000 relate to restricted stock units awarded January 20, 2017 as a retention grant which vest (i) 30% on January 20, 2021, (ii) 30% on January 20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment;
(f) $157,876 and $27,920, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016 Bonus Plan, which are scheduled to vest on February 28, 2020;
(g) $950,316 and $96,034 respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;
(h) $302,640 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017 Bonus Plan, which are scheduled to vest January 17, 2021; and
(i) $930,597 and $94,041, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December 31, 2019.
(3)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:
(a) $360,200 and $109,200, respectively, relate to the restricted stock units and related dividend rights granted on January 6, 2016, which are scheduled to vest January 6, 2019;
(b) $148,222 and $41,191, respectively, relate to the restricted stock units and related dividend rights granted on March 2, 2016, in settlement of awards under the 2015 Bonus Plan, which are scheduled to vest February 28, 2019;
(c) $136,516 and $34,489, respectively, relate to the restricted stock units and related dividend rights granted on August 1, 2016, which are scheduled to vest August 1, 2019;
(d) $1,080,600 and $218,400 relate to restricted stock units awarded January 20, 2017 as a retention grant which vest (i) 30% on January 20, 2021, (ii) 30% on January 20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment;
(f) $25,934 and $4,586, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016 Bonus Plan, which are scheduled to vest on February 28, 2020;
(g) $255,020 and $51,542, respectively, relate to the restricted stock units and related dividend rights granted on August 1, 2017, which are scheduled to vest August 1, 2020;
(h) $285,098 and $28,811, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;
(i) $85,151 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017 Bonus Plan which are scheduled to vest January 17, 2021; and
(j) $279,183 and $28,213, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December 31, 2019.
(4)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:
(a) $956,187 and $289,882, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019;
(b) $346,801 and $96,376, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the 2015 Bonus Plan, which are scheduled to vest February 28, 2019;
(c) $249,583 and $50,443, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;
(d) $239,225 and $49,396, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December 31, 2019;
(e) $1,620,900 and $327,600 relate to restricted stock units awarded January 20, 2017 as a retention grant which vest (i) 30% on January 20, 2021, (ii) 30% on January 20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment;
(f) $94,012 and $16,626, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016 Bonus Plan, which are scheduled to vest on February 28, 2020;
(g) $429,899 and $43,443, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;
(h) $160,001 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017 Bonus Plan which are scheduled to vest January 17, 2021; and
(i) $420,978 and $42,542, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December 31, 2019.
(5)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:
(a) $1,077,971 and $326.803, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019;
(b) $329,259 and $91,501, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the 2015 Bonus Plan, which are scheduled to vest February 28, 2019;
(c) $249,583 and $50,443, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;
(d) $239,225 and $49,396, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December 31, 2019;
(e) $1,620,900 and $327,600 relate to restricted stock units awarded January 20, 2017 as a retention grant which vest (i) 30% on January 20, 2021, (ii) 30% on January 20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment;
(f) $89,258 and $15,785, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016 Bonus Plan, which are scheduled to vest on February 28, 2020;
(g) $429,899 and $43,443, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;
(h) $160,001 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017 Bonus Plan, which are scheduled to vest January 17, 2021; and
(i) $420,978 and $42,542, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December 31, 2019.
(6)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:
(a) $1,425,672 and $432,214, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019;
(b) $620,517 and $172,442, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the 2015 Bonus Plan, which are scheduled to vest February 28, 2019;
(c) $347,701 and $70,274, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;
(d) $333,271 and $68,816, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December 31, 2019;
(e) $168,177 and $29,742, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016 Bonus Plan, which are scheduled to vest on February 28, 2020;
(f) $475,140 and $48,015, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;
(g) $289,637 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017 Bonus Plan which are scheduled to vest January 17, 2021; and
(h) $465,281 and $47,019, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December 31, 2019.
Director Compensation
The following table sets forth the compensation earned by our non-employee directors for 2018:
(1)
Amounts reported in the “Stock Awards” column represent the aggregate grant date fair value of restricted shares of our common stock with a one year vesting period awarded to the non-employee directors under our Stock Incentive Plan, computed in accordance with FASB ASC Topic 718, disregarding the estimate of forfeitures. For a discussion of the assumptions and methodologies used to value the awards reported in this column, see the discussion contained in the Notes to Consolidated Financial Statements at Note 23 - Compensation Plans included in our Annual Report on Form 10-K for the year ended December 31, 2018. On January 17, 2018, each director serving at that time received 2,312 restricted shares of our common stock in connection with their 2018 service on our Board of Directors, and the grant date fair value of each share of common stock computed in accordance with FASB ASC Topic 718 was $51.09. On September 7, 2018, Ms. Bowman, received 771 restricted shares of our common stock in connection with her 2018 service on our Board of Directors, and the grant date fair value of each share of common stock computed in accordance with FASB ASC Topic 718 was $53.73. As of December 31, 2018, each of the directors still held the outstanding restricted shares granted to them in 2018, and none of our non-employee directors held any outstanding stock options.
(2)
Ms. Bowman was appointed effective September 7, 2018.
Narrative to Director Compensation Table
For 2018, all non-employee directors, except for Ms. Beth A. Bowman, received a cash retainer of $76,000. Ms. Bowman received a cash retainer of $25,333 in September 2018 when she was appointed to the Board of Directors. The lead director received an additional annual retainer of $15,000, the Chairman of the Audit Committee received an additional annual retainer of $20,000, the Chairman of the Compensation Committee received an additional annual retainer of $15,000 and the Chairman of the Nominating and Governance Committee received an additional retainer of $10,000. All of our non-employee directors receive $1,500 for each Board of Directors, Audit Committee, Compensation Committee and Nominating and Governance Committee meeting attended and beginning September 24, 2018, each Risk Management Committee meeting attended. Meeting fees may also be paid for certain other informational or review sessions that non-employee directors attended. Payment of non-employee director fees is generally made twice annually, at the second regularly scheduled meeting of the Board of Directors and at the final regularly scheduled meeting of the Board of Directors for the fiscal year. All non-employee directors are reimbursed for out-of-pocket expenses incurred in attending Board of Director and committee meetings.
A director who is also an employee receives no additional compensation for services as a director. Accordingly, Messrs. Whalen, Perkins and Heim have been omitted from the table. Because Mr. Perkins is a named executive officer for 2018, the Summary Compensation Table reflects the total compensation he received for services performed for us and our affiliates. Mr. Whalen, who serves as Executive Chairman of the Board, and Mr. Heim, who serves as Vice Chairman of the Board, are executive officers who do not receive any additional compensation for services provided as a director. Due to the fact that Messrs. Whalen and Heim are not named executive officers, their employee compensation is omitted from the table above and the Summary Compensation Table herein.
Director Long-term Equity Incentives. We granted equity awards in January 2018 to our non-employee directors serving at that time under the Stock Incentive Plan. Each of these directors received an award of 2,312 restricted shares of our common stock with a one year vesting period. In September 2018, we granted to Ms. Bowman, 771 restricted shares of our common stock with a one year vesting period. These grants reflect our intent to provide our directors with a target value of approximately $115,000 in annual long-term incentive awards. The awards are intended to align the long-term interests of our directors with those of our shareholders.
Changes for 2019
Director Compensation. In January 2019, the Board of Directors approved changes to our non-employee director compensation for the 2019 fiscal year. For 2019, the annual cash retainer was increased to $100,000, the equity compensation portion of the retainer was increased to $130,000, meeting fees were eliminated and directors will receive a $7,500 retainer for each committee on which they serve. The lead director retainer was increased to $20,000 per year and the Chairman of the Risk Management Committee will receive an annual retainer of $10,000.
Director Long-term Equity Incentives. In January 2019, each of our non-employee directors received an award of 3,168 restricted shares of our common stock under the Stock Incentive Plan with a one year vesting period, which reflects our desire to increase the target value of the annual awards to approximately $130,000 per year.
Pay Ratio Disclosures
As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Joe Bob Perkins, our Chief Executive Officer (our “CEO”).
For 2018, our last completed fiscal year:
•
The median of the annual total compensation of all employees of our company (other than the CEO) was $102,427 and
•
The annual total compensation of Mr. Perkins was $13,481,602.
•
Based on this information, for 2018 the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all employees (“CEO Pay Ratio”) was reasonably estimated to be 132 to 1.
To calculate the CEO Pay Ratio we must identify the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our median employee and our CEO. To these ends, we took the following steps:
•
As permitted by the regulations, because there have not been major changes in the distribution of our employee population, we selected the same median employee that was utilized for our 2017 Pay Ratio Disclosures.
•
We combined all of the elements of the median employee’s compensation for the 2018 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $102,427.
•
With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2018 Summary Compensation Table included in Item 11 of Part III of this Annual Report.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
The following table sets forth information regarding the beneficial ownership of TRC common stock as of February 1, 2019 (unless otherwise indicated) held by:
•
each person who beneficially owns 5% or more of TRC’s then outstanding shares of common stock;
•
each of TRC’s named executive officers;
•
each of TRC’s directors; and
•
all of TRC’s executive officers and directors as a group.
TRC owns all of our outstanding common units. As of February 1, 2019, none of TRC’s directors or executive officers owned any preferred shares of TRC or Preferred Units.
Beneficial ownership is determined under the rules of the SEC. In general, these rules attribute beneficial ownership of securities to persons who possess sole or shared voting power and/or investment power with respect to those securities and include, among other things, securities that an individual has the right to acquire within 60 days. Unless otherwise indicated, the stockholders identified in the table below have sole voting and investment power with respect to all securities shown as beneficially owned by them. Percentage ownership calculations for any security holder listed in the table below are based on 232,143,230 shares of TRC’s common stock outstanding on February 1, 2019.
*
Less than 1%.
(1)
Unless otherwise indicated, the address for all beneficial owners in this table is 811 Louisiana, Suite 2100, Houston, Texas 77002.
(2)
As reported on Schedule 13G/A as of December 31, 2018 and filed with the SEC on February 13, 2019, the business address for The Vanguard Group is 100 Vanguard Blvd. Malvern, PA 19355. The Vanguard Group has sole voting power over 154,775 shares of common stock, shared voting power over 56,668 shares of common stock, sole dispositive power over 21,106,619 shares of common stock and shared dispositive power over 209,787 shares of common stock.
(3)
As reported on Schedule 13G/A as of December 31, 2018 and filed with the SEC on February 6, 2019, the business address for BlackRock, Inc. is 55 East 52nd Street New York, NY 10055. BlackRock, Inc. has sole voting power over 11,612,275 shares of common stock and sole dispositive power over 13,209,410 shares of common stock.
(4)
As reported on Schedule 13G/A as of December 31, 2018 and filed with the SEC on February 14, 2019, the business address for Harvest Fund Advisors LLC is s 100 W. Lancaster Avenue, Suite 200, Wayne, PA 19087. Harvest Fund Advisors LLC has sole voting power and sole dispositive power over 12,866,569 shares of common stock.
(5)
Shares of common stock beneficially owned by Mr. Perkins include: (i) 338,174 shares issued to the Perkins Blue House Investments Limited Partnership (“PBHILP”) and (ii) 93 shares held by Mr. Perkins’ wife. Mr. Perkins is the sole member of JBP GP, L.L.C., one of the general partners of the PBHILP.
(6)
Shares of common stock beneficially owned by Mr. Chung include (i) 189,904 shares issued to the Paul Chung 2008 Family Trust, of which Mr. Chung serves as trustee, (ii) 189,904 shares issued to the Helen Chung 2007 Family Trust, of which Mr. Chung's spouse and Mr. Chung's sister-in-law serve as co-trustees and (iii) 18,052 shares held for the benefit of Mr. Chung's daughter in an account of which Mr. Chung is the custodian.
(7)
Shares of common stock beneficially owned by Mr. Joyce include: (i) 223,759 shares issued to The Rene Joyce 2010 Grantor Retained Annuity Trust, of which Mr. Joyce and his wife are co-trustees and have shared voting and investment power; and (ii) 561,292 shares issued to The Kay Joyce 2010 Family Trust, of which Mr. Joyce’s wife is trustee and has sole voting and investment power.
(8)
Shares of common stock beneficially owned by Mr. Whalen include (i) 345,999 shares issued to the Whalen Family Investments Limited Partnership and (ii) 148,850 shares issued to the Whalen Family Investments Limited Partnership 2.
(9)
Shares of common stock beneficially owned by Mr. Heim include: (i) 124,878 shares issued to The Michael Heim 2009 Family Trust, of which Mr. Heim and his son are co-trustees and have shared voting and investment power; (ii) 81,672 shares issued to The Patricia Heim 2009 Grantor Retained Annuity Trust, of which Mr. Heim and his wife are co-trustees and have shared voting and investment power; (iii) 57,973 shares issued to the Pat Heim 2012 Family Trust, of which Mr. Heim’s wife and son serve as co-trustees and have shared voting and investment power; (iv) 38,400 shares issued to the Heim 2012 Children’s Trust, of which Mr. Heim serves as trustee; and (v) 19,472 shares held by Mr. Heim’s wife.
(10)
Shares of common stock beneficially owned by Mr. Tong include 434 shares held by Mr. Tong’s wife.
(11)
Shares of common stock beneficially owned by Mr. Evans include 5,580 shares held by Mr. Evan’s wife.
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth certain information as of December 31, 2018 regarding TRC’s long-term incentive plans, under which TRC common stock is authorized for issuance to employees, consultants and directors of TRC, our general partner and their affiliates. TRC’s sole equity compensation plan, under which it will make equity grants, is its Amended and Restated 2010 Stock Incentive Plan, which was approved by TRC stockholders on May 22, 2017.
(1)
Generally, awards of restricted stock, restricted stock units and performance share units to our officers and employees under the Stock Incentive Plan are subject to vesting over time as determined by the Compensation Committee of TRC and, prior to vesting, are subject to forfeiture. Stock incentive plan awards may vest in other circumstances, as approved by the Compensation Committee and reflected in an award agreement. Restricted stock, restricted stock units and performance share units are issued, subject to vesting, on the date of grant. The Compensation Committee of TRC may provide that dividends on restricted stock, restricted stock units or performance share units are subject to vesting and forfeiture provisions, in which cash such dividends would be held, without interest, until they vest or are forfeited.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
As a result of the TRC/TRP Merger, which was completed on February 17, 2016, Targa owns all of our outstanding common units. In addition, Targa owns a 2% general partner interest in us. Our total outstanding common units as of February 10, 2017 totaled 236,595,048. In addition, Targa owns a 2% general partner interest in us, which is held through a 100% ownership interest in our general partner.
Distributions and Payments to Targa and its Affiliates
The following table summarizes the distributions and payments made and to be made by us to Targa and its affiliates in connection with our ongoing operation and any liquidation of us. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Partnership Agreement
Our Partnership Agreement with Targa governs the reimbursement of Targa and its affiliates for costs incurred on our behalf, competition and indemnification matters. The Partnership Agreement provides that Targa and its affiliates are reimbursed for all direct and indirect expenses, as well as expenses otherwise allocable to us in connection with the operation of our business, incurred on our behalf.
Reimbursement of Operating and General and Administrative Expense
Under the terms of our Partnership Agreement, we reimburse Targa for all direct and indirect expenses, as well as expenses otherwise allocable to us in connection with the operation of our business, incurred on our behalf, which includes certain operating and direct expenses, including compensation and benefits of operating personnel, including 401(k), pension and health insurance benefits, and for the provision of various general and administrative services for our benefit. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Other than Targa’s direct costs of being a public reporting company, substantially all of Targa’s general and administrative costs have been and will continue to be allocated to us, so long as Targa’s only cash-generating assets consist of its interest in us.
Competition
Targa is not restricted under our Partnership Agreement from competing with us. Targa may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
Indemnification Agreements
Indemnification Agreements with Directors and Officers
We and our general partner have entered into Indemnification Agreements (each, an “Indemnification Agreement”) with individuals who were independent directors of Targa Resources GP LLC (each, an “Indemnitee”) prior to the TRC/TRP Merger. Each Indemnification Agreement provides that each of us and Targa Resources GP LLC will indemnify and hold harmless each Indemnitee against Expenses (as defined in the Indemnification Agreement) to the fullest extent permitted or authorized by law, including the Delaware Revised Uniform Limited Partnership Act and the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee. If such indemnification is unavailable as a result of a court decision and if we or Targa Resources GP LLC are jointly liable in the proceeding with the Indemnitee, we and Targa Resources GP LLC will contribute funds to the Indemnitee for his or her Expenses (as defined in the Indemnification Agreement) in proportion to relative benefit and fault of us or Targa Resources GP LLC on the one hand and Indemnitee on the other in the transaction giving rise to the proceeding.
Each Indemnification Agreement also provides that we and Targa Resources GP LLC will indemnify and hold harmless the Indemnitee against Expenses incurred for actions taken as a director or officer of us or Targa Resources GP LLC or for serving at the request of us or Targa Resources GP LLC as a director or officer or another position at another corporation or enterprise, as the case may be, but only if no final and non-appealable judgment has been entered by a court determining that, in respect of the matter for which the Indemnitee is seeking indemnification, the Indemnitee acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal proceeding, the Indemnitee acted with knowledge that the Indemnitee’s conduct was unlawful. Each Indemnification Agreement also provides that we and Targa Resources GP LLC must advance payment of certain Expenses to the Indemnitee, including fees of counsel, subject to receipt of an undertaking from the Indemnitee to return such advance if it is ultimately determined that the Indemnitee is not entitled to indemnification.
Targa Resources Corp., the holder of all of our common units, has entered into Indemnification Agreements (each, a “Parent Indemnification Agreement”) with each director and officer of Targa (each, a “Parent Indemnitee”). Each Parent Indemnification Agreement provides that Targa Resources Corp. will indemnify and hold harmless each Parent Indemnitee for Expenses (as defined in the Parent Indemnification Agreements) to the fullest extent permitted or authorized by law, including the Delaware General Corporation Law, in effect on the date of the agreement or as it may be amended to provide more advantageous rights to the Parent Indemnitee. If such indemnification is unavailable as a result of a court decision and if Targa Resources Corp. and the Indemnitee are jointly liable in the proceeding, Targa Resources Corp. will contribute funds to the Parent Indemnitee for his or her expenses in proportion to relative benefit and fault of Targa Resources Corp. and Parent Indemnitee in the transaction giving rise to the proceeding.
Each Indemnification Agreement also provides that Targa Resources Corp. will indemnify the Parent Indemnitee for monetary damages for actions taken as a director or officer of Targa Resources Corp. or for serving at Targa’s request as a director or officer or another position at another corporation or enterprise, as the case may be but only if (i) the Parent Indemnitee acted in good faith and, in the case of conduct in his or her official capacity, in a manner he reasonably believed to be in the best interests of Targa Resources Corp. and, in all other cases, not opposed to the best interests of Targa Resources Corp. and (ii) in the case of a criminal proceeding, the Parent Indemnitee must have had no reasonable cause to believe that his or her conduct was unlawful. Each Parent Indemnification Agreement also provides that Targa Resources Corp. must advance payment of certain Expenses to the Parent Indemnitee, including fees of counsel, subject to receipt of an undertaking from the Parent Indemnitee to return such advance if it is ultimately determined that the Parent Indemnitee is not entitled to indemnification.
Transactions with Related Persons
Relationship with Sajet Resources LLC
In December 2010, immediately prior to Targa’s initial public offering, Sajet Resources LLC (“Sajet”) was spun-off from Targa. Rene Joyce, James Whalen and Joe Bob Perkins, directors of Targa, are also directors of Sajet. Joe Bob Perkins, James Whalen, Michael Heim, Jeffrey McParland, Paul Chung, and Matthew Meloy, executive officers of Targa, are also executive officers of Sajet. The primary assets of Sajet are real property. Sajet also holds (i) an ownership interest in Floridian Natural Gas Storage Company, LLC, (ii) an ownership interest in Allied CNG Ventures LLC and (iii) certain technology rights. Former holders of our pre-IPO common equity, including certain of our current and former executives, managers and directors collectively own an 18% interest in Sajet. We provide general and administrative services to Sajet and are reimbursed for these amounts. Services provided to Sajet totaled less than $0.1 million in January and February of 2018.
In March 2018, we acquired the 82% interest in Sajet that was held by Warburg Pincus sponsored funds for $5.0 million in cash (the “Warburg Funds Transaction”) and extinguished Sajet’s third-party debt in exchange for a promissory note from Sajet of $9.9 million. Minority shareholders had the right to join the transaction and sell up to 100% of their membership interests in Sajet to us at substantially the same terms and price as the Warburg Funds Transaction (the “Tag-Along Rights”). Minority shareholders who currently hold, or formerly held, executive positions at Targa, and minority shareholders who are board members of Targa, agreed not to exercise their Tag-Along Rights resulting from the Warburg Funds Transaction. Certain minority shareholders chose to sell interests totaling 1.6% for approximately $0.1 million in April 2018.
Since March 2018, Sajet has been accounted for on a consolidated basis in our consolidated financial statements.
Relationship with Apache Corp.
Rene R. Joyce, a director of Targa and of our general partner, is also a director of Apache Corporation (“Apache”) with whom we purchase and sell natural gas and NGLs and engage in construction services. During 2018, we made sales to Apache of $1.3 million and purchases of $189.4 million from Apache.
Relationship with Kansas Gas Service
Robert B. Evans, a director of Targa and our general partner, is also a director of ONE Gas, Inc. (“ONE”). We have commercial arrangements with Kansas Gas Service (“Kansas Gas”), a division of ONE. During 2018, we transacted sales of $19.6 million with Kansas Gas.
Relationships with Southern Company Gas, EOG Resources Inc., and IntercontinentalExchange, Inc.
Charles R. Crisp, a director of the Company and of our general partner, is a director of Southern Company Gas, parent company of Sequent Energy Management, LP (“Sequent”) and Northern Illinois Gas Company d/b/a NICOR Energy (“NICOR”). We purchase and sell natural gas and NGL products from and to Sequent and sell natural gas products to NICOR. In addition, we purchase electricity from Mississippi Power (“MS Power”), an affiliate of Southern Company, parent company of Southern Company Gas. Mr. Crisp also serves as a director of EOG Resources, Inc. (“EOG”), from whom we purchase natural gas and from whom, together with EOG’s subsidiary EOG Resources Marketing, Inc. (“EOG Marketing”), we purchase crude oil. We also bill EOG and EOG Marketing for well connections to our gathering systems and associated equipment, and for services to operate certain EOG and jointly owned gas and crude oil gathering facilities. Mr. Crisp is also a director of Intercontinental Exchange, Inc. (“ICE Group”), parent company of ICE US OTC Commodity Markets LLC from whom we purchase brokerage services, New York Stock Exchange and ICE NGX Canada Inc., which provide platform services utilized by us for the purchase and sale of physical gas and natural gas liquids with third parties. The following table shows our transactions with each of these entities during 2018:
These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
Relationship with Southwest Energy LP
Ershel C. Redd Jr., a director of Targa and of our general partner, has an immediate family member who is an officer and part owner of Southwest Energy LP (“Southwest Energy”) from and to whom we purchase and sell natural gas and NGL products. During 2018, we made sales to Southwest Energy of $22.7 million and purchases of $2.8 million from Southwest Energy.
Relationship with Intercontinental Exchange, Inc.
Jennifer R. Kneale, Chief Financial Officer of Targa and of our general partner, has an immediate family member who is an officer of ICE Group. During 2018, we made sales to ICE Group of $23.5 million and purchases of $16.3 million from ICE Group.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Targa) on the one hand and our partnership and our limited partners, on the other hand. The directors and officers of Targa Resources GP LLC have fiduciary duties to manage Targa and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.
Whenever a conflict arises between our general partner and its affiliates on the one hand and us or any other partner on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:
•
approved by the conflicts committee, although our general partner is not obligated to seek such approval;
•
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points 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 of the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership.
Review, Approval or Ratification of Transactions with Related Persons
If a conflict or potential conflict of interest arises between our general partner and its affiliates (including Targa) on the one hand and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under “−Conflicts of Interest.”
Pursuant to Targa’s Code of Conduct, our officers and directors are required to abandon or forfeit any activity or interest that creates a conflict of interest between them and Targa or any of its subsidiaries, unless the conflict is pre-approved by the Board of Directors.
Director Independence
The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee. Our general partner has a standing Audit Committee that consists of three directors: Messrs. Tong and Redd and Ms. Fulton. The board of directors of our general partner has affirmatively determined that Messrs. Tong and Redd and Ms. Fulton are independent as described in the rules of the NYSE and the Exchange Act for purposes of serving on the board of directors and the Audit Committee.
To be independent under the NYSE rules, a company’s board of directors must affirmatively determine that the director has no material relationship with the company (directly as a partner, stockholder or officer of an organization that has a relationship with the company). The board of directors of our general partner has made no such determination with respect to Messrs. Joyce, Perkins, Whalen and Heim because the NYSE rules do not require us to have a majority of independent directors. As such, Messrs. Joyce, Perkins, Whalen and Heim are not independent under NYSE rules applicable to service on compensation and nominating/governance committees.
Item 14.
Item 14. Principal Accounting Fees and Services.
We have engaged PricewaterhouseCoopers LLP as our independent principal accountant. The following table summarizes fees we were billed by PricewaterhouseCoopers LLP (or included in Targa’s general and administrative expense allocation to us) for independent auditing, tax and related services for each of the last two fiscal years:
________________
(1)
Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the integrated audit of our annual financial statements and internal control over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this Annual Report.
(2)
Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews of our financial statements and are not reported under audit fees.
(3)
Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance.
(4)
All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above.
All services provided by our independent principal accountant are subject to pre-approval by the Audit Committee of our general partner. The Audit Committee of our general partner is informed of each engagement of the independent principal accountant to provide services under the policy. The Audit Committee of our general partner has approved the use of PricewaterhouseCoopers LLP as our independent principal accountant. All of the services of PricewaterhouseCoopers LLP for 2018 and 2017 described above were pre-approved by the Audit Committee.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a)(1) Financial Statements
Our Consolidated Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Consolidated Financial Statements” on Page in this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
Number
Description
2.1***
Purchase and Sale Agreement, dated September 18, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 21, 2007 (File No. 001-33303)).
2.2
Amendment to Purchase and Sale Agreement, dated October 1, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)).
2.3
Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (File No. 001-33303)).
2.4
Purchase and Sale Agreement, dated March 31, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC and Targa Midstream Holdings LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 1, 2010 (File No. 001-33303)).
2.5
Purchase and Sale Agreement, dated August 6, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 9, 2010 (File No. 001-33303)).
2.6
Purchase and Sale Agreement, dated September 13, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 17, 2010 (File No. 001-33303)).
2.7***
Membership Interest Purchase and Sale Agreement, dated November 14, 2012, by and among Targa Resources Partners LP, Saddle Butte Pipeline LLC, Saddle Butte Fort Berthold Gathering, LLC and Saddle Butte Assets, LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 15, 2012 (File No. 001-33303)).
2.8***
Agreement and Plan of Merger, by and among Targa Resources Corp., Trident GP Merger Sub LLC, Atlas Energy, L.P. and Atlas Energy GP, LLC, dated October 13, 2014 (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 20, 2014 (File No. 001-33303)).
2.9***
Agreement and Plan of Merger, by and among Targa Resources Corp., Targa Resources Partners LP, Targa Resources GP LLC, Trident MLP Merger Sub LLC, Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Atlas Pipeline Partners GP, LLC, dated October 13, 2014 (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 20, 2014 (File No. 001-33303)).
2.10***
Agreement and Plan of Merger, dated as of November 2, 2015, by and among Targa Resources Corp., Spartan Merger Sub LLC, Targa Resources Partners LP and Targa Resources GP LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 6, 2015 (File No. 001-33303)).
2.11***
Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Delaware Midstream, LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).
2.12***
Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Energy, LLC (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).
2.13***
Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Midland Midstream, LLC (incorporated by reference to Exhibit 2.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).
3.1
Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
3.2
Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
3.3
Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP, effective December 1, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 21, 2016 (File No. 001-33303)).
3.4
Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 12, 2017(File No. 001-33303)).
3.5
Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
4.1
Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
4.2
Indenture dated as of October 25, 2012 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation and the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 26, 2012 (File No. 001-33303)).
4.3
Registration Rights Agreement dated as of October 25, 2012 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC, Barclays Capital Inc. and RBS Securities Inc., as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 26, 2012 (File No. 001-33303)).
4.4
Registration Rights Agreement dated as of December 10, 2012 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC, Barclays Capital Inc. and RBS Securities Inc., as representatives of the several initial purchasers. (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 10, 2012 (File No. 001-33303)).
4.5
Supplemental Indenture dated March 10, 2017 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)).
4.6
Supplemental Indenture dated June 16, 2017 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-33303)).
4.7
Supplemental Indenture dated December 18, 2017 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.8
Supplemental Indenture dated January 9, 2018 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.9
Supplemental Indenture dated July 24, 2018 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-33303)).
4.10
Indenture dated as of May 14, 2013 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 14, 2013 (File No. 001-33303)).
4.11
Registration Rights Agreement dated as of May 14, 2013 among the Issuers, the Guarantors and Wells Fargo Securities, LLC, Barclays Capital Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC, as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 14, 2013 (File No. 001-33303)).
4.12
Supplemental Indenture dated March 10, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)).
4.13
Supplemental Indenture dated June 16, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-33303)).
4.14
Supplemental Indenture dated December 18, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.13 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.15
Supplemental Indenture dated January 9, 2018 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.14 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.16
Supplemental Indenture dated July 24, 2018 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-33303)).
4.17
Indenture dated as of October 28, 2014 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 29, 2014 (File No. 001-33303)).
4.18
Registration Rights Agreement dated as of October 28, 2014 by and among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBS Securities Inc., Wells Fargo Securities, LLC, Goldman, Sachs & Co. and UBS Securities LLC, as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 29, 2014 (File No. 001-33303)).
4.19
Supplemental Indenture dated March 10, 2017 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)).
4.20
Supplemental Indenture dated June 16, 2017 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-33303)).
4.21
Supplemental Indenture dated December 18, 2017 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.19 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.22
Supplemental Indenture dated January 9, 2018 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.20 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.23
Supplemental Indenture dated July 24, 2018 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-33303)).
4.24
Indenture, dated as of September 14, 2015, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 15, 2015 (File No. 001-33303)).
4.25
Registration Rights Agreement, dated as of September 14, 2015, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 15, 2015 (File No. 001-33303)).
4.26
Supplemental Indenture dated March 10, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)).
4.27
Supplemental Indenture dated June 16, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-33303)).
4.28
Supplemental Indenture dated December 18, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.25 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.29
Supplemental Indenture dated January 9, 2018 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.26 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.30
Supplemental Indenture dated July 24, 2018 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-33303)).
4.31
Indenture dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-33303)).
4.32
Registration Rights Agreement dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and Wells Fargo Securities, LLC, as representative of the several initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-33303)).
4.33
Registration Rights Agreement dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and Wells Fargo Securities, LLC, as representative of the several initial purchasers party thereto (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-33303)).
4.34
Supplemental Indenture dated March 10, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)).
4.35
Supplemental Indenture dated June 16, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-33303)).
4.36
Supplemental Indenture dated December 18, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.32 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.37
Supplemental Indenture dated January 9, 2018 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.33 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.38
Supplemental Indenture dated July 24, 2018 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-33303)).
4.39
Indenture dated as of October 17, 2017 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed October 17, 2017).
4.40
Registration Rights Agreement dated as of October 17, 2017 among the Issuers, the Guarantors and Citigroup Global Markets Inc., as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed October 17, 2017).
4.41
Supplemental Indenture dated December 18, 2017 to Indenture dated October 17, 2017, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.36 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.42
Supplemental Indenture dated January 9, 2018 to Indenture dated October 17, 2017, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.37 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-33303)).
4.43
Supplemental Indenture dated July 24, 2018 to Indenture dated October 17, 2017, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-33303)).
4.44
Indenture dated as of April 12, 2018 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed April 16, 2018).
4.45
Registration Rights Agreement dated as of April 12, 2018 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed April 16, 2018).
4.46
Supplemental Indenture dated July 24, 2018 to Indenture dated April 12, 2018, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-33303)).
4.47
Indenture dated as of January 17, 2019 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed January 23, 2019).
4.48
Registration Rights Agreement dated as of January 17, 2019 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed January 23, 2019).
4.49
Registration Rights Agreement dated as of January 17, 2019 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed January 23, 2019).
4.50
Specimen Unit Certificate for the Series A Preferred Units (attached as Exhibit B to the Second Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP and incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 15, 2015 (File No. 001-33303)).
10.1
Third Amendment and Restatement Agreement dated as of June 29, 2018, by and among Targa Resources Partners LP, Bank of America, N.A., and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 3, 2018 (File No. 001-33303)).
10.2
Contribution, Conveyance and Assumption Agreement, dated February 14, 2007, by and among Targa Resources Partners LP, Targa Resources Operating LP, Targa Resources GP LLC, Targa Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa Regulated Holdings LLC, Targa North Texas GP LLC and Targa North Texas LP (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
10.3
Contribution, Conveyance and Assumption Agreement, dated October 24, 2007, by and among Targa Resources Partners LP, Targa Resources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa LA LLC, Targa LA PS LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)).
10.4
Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)).
10.5
Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC, Targa Midstream Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa Resources Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
10.6
Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 26, 2010 (File No. 001-33303)).
10.7
Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 4, 2010 (File No. 001-33303)).
10.8
Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)).
10.9
First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
10.10
Purchase Agreement dated as of April 5, 2018, among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed April 6, 2018).
10.11
Purchase Agreement dated as of January 10, 2019, among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed January 15, 2019).
10.12
Receivables Purchase Agreement, dated January 10, 2013, by and among Targa Receivables LLC, the Partnership, as initial Servicer, the various conduit purchasers from time to time party thereto, the various committed purchasers from time to time party thereto, the various purchaser agents from time to time party thereto, the various LC participants from time to time party thereto and PNC Bank, National Association as Administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 14, 2013 (File No. 001-33303)).
10.13
Purchase and Sale Agreement, dated January 10, 2013, between the originators from time to time party thereto as Originators and Targa Receivables LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 14, 2013 (File No. 001-33303)).
10.14
Second Amendment to Receivables Purchase Agreement, dated December 13, 2013, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 17, 2013 (File No. 001-33303)).
10.15
Fourth Amendment to Receivables Purchase Agreement, dated December 11, 2015, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 15, 2015 (File No. 001-33303)).
10.16
Fifth Amendment to Receivables Purchase Agreement, dated December 9, 2016, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 6, 2017 (File No. 001-33303)).
10.17
Seventh Amendment to Receivables Purchase Agreement, dated December 7, 2018, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 10, 2018 (File No. 001-33303)).
10.18
Commitment Increase Request, dated February 23, 2017, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, and PNC Bank, National Association, as administrator, purchaser agent and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 24, 2017 (File No. 001-33303)).
10.19+
Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 1, 2007 (File No. 333-138747)).
10.20+
First Amendment to the Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.21+
Form of Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by reference to Exhibit 10.93 of Targa Investment’s Inc.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
10.22+
Targa Resources Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 1, 2007 (File No. 333-138747)).
10.23+
Amendment to Targa Resources Partners LP Long-Term Incentive Plan dated December 18, 2008 (incorporated by reference to Exhibit 10.10 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)).
10.24+
Form of Restricted Unit Grant Agreement - 2010 (incorporated by reference to Exhibit 10.15 to Targa Resources Partners LP’s Annual Report on Form 10-K filed March 4, 2010 (File No. 001-33303)).
10.25+
Targa Resources Partners LP Performance Unit Grant Agreement (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.26+
Targa Resources Partners LP Performance Unit Grant Agreement under the Targa Resources Corp. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.27+
Targa Resources Partners LP Amendment to Outstanding Performance Units (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.28+
Targa Resources Corp. Amendment to Targa Resources Partners LP Outstanding Performance Units (incorporated by reference to Exhibit 10.5 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.29+
Targa Resources Corp. 2015 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 20, 2015 (File No. 001-33303)).
10.30+
Targa Resources Corp. 2016 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 22, 2016 (File No. 001-33303)).
10.31+
Targa Resources Corp. 2017 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 25, 2017 (File No. 001-33303)).
10.32
Targa Resources Corp. 2018 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 18, 2018 (File No. 001-33303)).
10.33
Targa Resources Corp. 2019 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 22, 2019 (File No. 001-33303)).
10.34+
Targa Resources Executive Officer Change In Control Severance Program (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 19, 2012 ((File No. 001-33303)).
10.35+
First Amendment to the Targa Resources Executive Officer Change in Control Severance Program, dated December 3, 2015 (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 8, 2015 ((File No. 001-33303)).
10.36+
Form of Indemnification Agreement between Targa Resources Investments Inc. and each of the directors and officers thereof (incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 8, 2010 (File No. 333-169277)).
10.37+
Targa Resources Partners LP Indemnification Agreement for Robert B. Evans dated February 14, 2007 (incorporated by reference to Exhibit 10.11 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
10.38+
Targa Resources Partners LP Indemnification Agreement for Barry R. Pearl dated February 14, 2007 (incorporated by reference to Exhibit 10.12 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
10.39+
Indemnification Agreement by and between Targa Resources Corp. and Laura C. Fulton, dated February 26, 2013 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 1, 2013 (File No. 001-34991)).
10.40+
Indemnification Agreement by and between Targa Resources Corp. and Waters S. Davis, IV, dated July 23, 2015 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed July 24, 2015 (File No. 001-34991)).
10.41+
Indemnification Agreement by and between Targa Resources Corp. and D. Scott Pryor, dated November 12, 2015 (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-33303)).
10.42+
Indemnification Agreement by and between Targa Resources Corp. and Patrick J. McDonie, dated November 12, 2015 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-33303)).
10.43+
Indemnification Agreement by and between Targa Resources Corp. and Clark White, dated November 12, 2015 (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-33303)).
10.44+
Indemnification Agreement by and between Targa Resources Corp. and Robert Muraro, dated February 22, 2017 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February 27, 2017 (File No. 001-34991)).
10.45
Gas Gathering and Purchase Agreement by and between Burlington Resources Oil & Gas Company LP, Burlington Resources Trading Inc. and Targa Midstream Services Limited Partnership (portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) (incorporated by reference to Exhibit 10.5 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 8, 2007 (File No. 333-138747)).
21.1*
List of Subsidiaries of Targa Resources Partners LP.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1***
First Amendment to Membership Interest Purchase and Sale Agreement, dated December 20, 2012, by and among the Partnership, Saddle Butte Pipeline LLC, Saddle Butte Fort Berthold Gathering, LLC and Saddle Butte Assets, LLC (incorporated by reference to Exhibit 99.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 4, 2013 (File No. 001-33303)).
101.INS*
XBRL Instance Document
101.SCH*
XBRL Taxonomy Extension Schema Document
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
XBRL Taxonomy Extension Label Linkbase Document
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase Document
*
Filed herewith
**
Furnished herewith
***
Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted exhibit or Schedule to the SEC upon request
+
Management contract or compensatory plan or arrangement
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on March 1, 2019.
Signature
Title (Position with Targa Resources GP LLC)
/s/ Joe Bob Perkins
Chief Executive Officer and Director
Joe Bob Perkins
(Principal Executive Officer)
/s/ Jennifer R. Kneale
Chief Financial Officer
Jennifer R. Kneale
(Principal Financial Officer)
/s/ John R. Klein
Senior Vice President and Chief Accounting Officer
John R. Klein
(Principal Accounting Officer)
/s/ James W. Whalen
Executive Chairman of the Board and Director
James W. Whalen
/s/ Michael A. Heim
Vice Chairman of the Board and Director
Michael A. Heim
/s/ Charles R. Crisp
Director
Charles R. Crisp
/s/ Waters S. Davis, IV
Director
Waters S. Davis, IV
/s/ Robert B. Evans
Director
Robert B. Evans
/s/ Laura C. Fulton
Director
Laura C. Fulton
/s/ Ershel C. Redd Jr.
Director
Ershel C. Redd Jr.
/s/ Chris Tong
Director
Chris Tong
/s/ Rene R. Joyce
Director
Rene R. Joyce
/s/ Beth A. Bowman
Director
Beth A. Bowman
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
TARGA RESOURCES PARTNERS LP AUDITED CONSOLIDATED FINANCIAL STATEMENTS
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in 2013 to evaluate the effectiveness of the internal control over financial reporting. Based on that evaluation, management has concluded that the internal control over financial reporting was effective as of December 31, 2018.
The effectiveness of our internal control over financial reporting as of December 31, 2018 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page.
/s/ Joe Bob Perkins
Joe Bob Perkins
Chief Executive Officer
(Principal Executive Officer)
/s/ Jennifer R. Kneale
Jennifer R. Kneale
Chief Financial Officer
(Principal Financial Officer)
Report of Independent Registered Public Accounting Firm
To the Board of Directors of Targa Resources GP LLC and the Partners of Targa Resources Partners LP
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Targa Resources Partners LP and its subsidiaries as of December 31, 2018 and 2017, and the related consolidated statements of operations, of comprehensive income (loss), of changes in owners’ equity, and of cash flows for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Partnership’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Partnership’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Partnership’s consolidated financial statements and on the Partnership’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2019
We have served as the Partnership’s auditor since 2005.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
See notes to consolidated financial statements.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
See notes to consolidated financial statements.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY
See notes to consolidated financial statements.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
See notes to consolidated financial statements.
TARGA RESOURCES PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.
Note 1 - Organization and Operations
Our Organization
Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TRP,” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.
On February 17, 2016, TRC completed the previously announced transactions contemplated pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transaction, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.
At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.
Pursuant to the TRC/TRP Merger Agreement, TRC agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by our general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (the “Special GP Interest” as defined in the Third A&R Partnership Agreement) held by our general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.
Our Operations
We are engaged in the business of:
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gathering, compressing, treating, processing, transporting and selling natural gas;
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storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;
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gathering, storing, terminaling and selling crude oil; and
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storing, terminaling and selling refined petroleum products.
See Note 24 - Segment Information for certain financial information regarding our business segments.
The employees supporting our operations are employed by Targa. Our consolidated financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services.
Note 2 - Basis of Presentation
These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2018 and 2017, and the results of operations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2018, 2017 and 2016.
We have prepared these consolidated financial statements in accordance with GAAP. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.
Note 3 - Significant Accounting Policies
Consolidation Policy
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas gathering and processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.
We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within equity earnings (loss) in our Consolidated Statements of Operations.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing goodwill and long-lived assets for possible impairment, (4) estimating the useful lives of assets, (5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemable preferred interests. Actual results, therefore, could differ materially from estimated amounts.
Cash and Cash Equivalents
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. Checks outstanding at the end of a period are included in accounts payable, as we extinguish liabilities when the creditor receives our payment and we are relieved of our obligation (which generally occurs when our bank honors that check).
Allowance for Doubtful Accounts
Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.
Inventories
Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or net realizable value using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are included in Property, Plant and Equipment. Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued at cost using the specific identification method.
Product Exchanges
Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities.
Gas Processing Imbalances
Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or net realizable value using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
Derivative Instruments
We utilize derivative instruments to manage the volatility of cash flows due to fluctuating energy prices. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives. As a result, the revenues and expenses associated with such contracts are recognized during the period when volumes are physically delivered or received.
If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues.
If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss resulting from the change in fair value on the derivative is recognized currently in earnings as a component of revenues.
We formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis.
We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
For balance sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fair values and any related collateral by counterparty on a gross basis.
Property, Plant and Equipment
Property, plant and equipment are stated at acquisition value less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs.
The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs.
We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of additional impairments. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations.
Goodwill
Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Goodwill must be attributed to reporting units for the purpose of impairment testing. A reporting unit is an operating segment or one level below an operating segment (also known as a component).
Our annual goodwill impairment test is performed as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not that the fair value of the reporting unit is less than the carrying amount. Prior to us conducting the goodwill impairment test, we complete a review of the carrying values of our long-lived assets, including property, plant and equipment and other intangible assets and if it is determined that the carrying values are not recoverable, we reduce the carrying values of the long-lived assets pursuant to our policy on property, plant and equipment.
We are permitted to first assess qualitative factors for a reporting unit to determine if the quantitative goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or otherwise determine that a goodwill impairment test is required, our annual goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount (including attributed goodwill). Prior to our adoption of Accounting Standards Update (“ASU”) 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, if a reporting unit’s carrying amount exceeded the reporting unit’s fair value, we then compared the implied fair value of goodwill to its carrying value. We recognize an impairment loss in our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reporting unit’s fair value, or prior to our adoption of ASU 2017-04, the amount by which the carrying amount exceeded the reporting unit’s implied fair value. The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, we consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.
Intangible Assets
Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with business and asset acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortization expense attributable to these assets is recorded in a manner that closely resembles the expected benefit pattern of the intangible assets, or where such pattern is not readily determinable, on a straight-line basis, over the periods in which we benefit from services provided to customers.
Asset Retirement Obligations
We record the fair value of estimated asset retirement obligations (“ARO”) associated with tangible long-lived assets. Retirement obligations associated with long-lived assets are only recognized for those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction. These obligations, which are estimated based on discounted cash flow estimates, are accreted to full value over time as a period cost. In addition, asset retirement costs are capitalized as part of the related asset’s carrying value and are depreciated over the asset’s respective useful life.
At least annually, we review the projected timing and amount of asset retirement obligations. Changes resulting from revisions to the timing or the amount of the undiscounted cash flows are recognized as an increase or decrease in the carrying amount of the retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, any difference between the recorded amount and the actual settlement cost will be recognized at a gain or loss.
Debt Issuance Costs
Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt, as are any original issue discount or premium. Debt issuance costs related to revolving credit facilities are presented as other long-term assets and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction from the carrying amount of long-term debt on the Consolidated Balance Sheets. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs.
Accounts Receivable Securitization Facility
Proceeds from the sale or contribution of certain receivables under the accounts receivable securitization facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities in our Consolidated Statements of Cash Flows.
Environmental Liabilities and Other Loss Contingencies
Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to operating expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.
Income Taxes
We generally are not subject to federal income taxes. For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners. The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the Consolidated Statements of Operations.
As part of the APL merger, we acquired TPL Arkoma, Inc. a corporate subsidiary subject to federal and state income tax. The Partnership’s corporate subsidiary accounts for income taxes using the asset and liability method and provides deferred income taxes for all significant temporary differences.
As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes for our taxable corporate subsidiary. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets.
We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income. If we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.
The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level. We are also subject to the Texas margin tax, consisting generally of a 0.75% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. See Note 21 - Income Tax for discussion of the Partnership’s federal and state income tax expense (benefits) of its taxable subsidiary as well as the Partnership’s net deferred income tax assets (liabilities).
Dividends
Preferred and Common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital.
Mandatorily Redeemable Preferred Interests
Mandatorily redeemable preferred interests are included in other long-term liabilities on our Consolidated Balance Sheets. Mandatorily redeemable preferred interests with multiple or indeterminate redemption dates are reported at their estimated redemption value as of the reporting date. This point-in-time value does not represent the amount that ultimately would be redeemed in the future. Changes in the redemption value are included in interest expense, net in our Consolidated Statements of Operations.
Comprehensive Income
Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges.
Noncontrolling Interests
Third-party ownership (other than mandatorily redeemable interests) in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of our Consolidated Balance Sheets. In our Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income, noncontrolling interests reflects the attribution of results to third-party investors.
Revenue Recognition
Our operating revenues are primarily derived from the following activities:
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sales of natural gas, NGLs, condensate, crude oil and petroleum products;
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services related to compressing, gathering, treating, and processing of natural gas; and
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services related to NGL fractionation, terminaling and storage, transportation and treating.
We have multiple types of contracts with commercial counterparties and many of these may result in cash inflows to Targa due to the structure of settlement provisions with embedded fees. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases.
Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues.
We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis.
Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price.
Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract.
The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation.
Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue.
We have certain long-term contractual arrangements under which we have received consideration, but for which all conditions for revenue recognition have not been met. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided.
Significant Judgments
Certain provisions of our service contracts (i.e., tiered price structures) require further assessment to determine if the allocation exception for variable consideration is met. If the allocation exception is not met, we estimate the total consideration that we expect to be entitled to for the applicable term of the contract, based on projections of future activity. In such instance, revenue is recognized using an output method of progress based on the volume of commodities serviced during the reporting period. Our estimate of total consideration is reassessed each reporting period until contract completion.
For contracts with minimum volume commitments, we generally expect the customer to meet the commitment. However, such contracts are reassessed throughout the term of the commitment, and if we no longer expect the customer to meet the commitment, the allocation exception for variable consideration would not be met. That is, from that point onwards, an allocation based on the applicable fee applied to the volumes serviced does not depict the amount of consideration which we expect to be entitled to, in exchange for the service. In such instance, revenue will be recognized up to the minimum volume commitment in proportion to the days of service elapsed and the remaining duration of the commitment.
Contract Assets
We classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold or services performed at the end of reporting period.
Unit-Based and Share-Based Compensation
Prior to the TRC/TRP Merger, we awarded unit-based compensation to employees of Targa and to directors and non-management directors of our General Partner in the form of restricted common units and performance units. We withheld units to satisfy employees’ tax withholding obligations on vested awards. The withheld shares were recorded as treasury units at cost. In connection with the TRC/TRP Merger, the unit-based compensation was converted to comparable share-based TRC awards and share-based compensation is now awarded in the form of TRC restricted stock, and TRC restricted stock units. Compensation expense on awards that qualify as equity arrangements are measured by the fair value of the award as determined at the date of grant. Compensation expense on awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is allocated to us from TRC and recognized in general and administrative expense over the requisite service period of each award.
Recent Accounting Pronouncements
Recently issued accounting pronouncements not yet adopted
Leases
In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other items, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted.
In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendments in this update permit an entity to elect an optional transition practical expedient to not evaluate land easements that existed or expired before the entity’s adoption of Topic 842 and that were not previously accounted for as leases under Topic 840.
In July 2018, the FASB issued ASU 2018-10, Codification Improvements to Topic 842, Leases. The amendments in this update affect narrow aspects of the guidance issued in ASU 2016-02 and are intended to alleviate unintended consequences from applying the new standard. The amendments do not make substantive changes to the core provisions or principles of the new standard and have been considered during our implementation process.
In July 2018, the FASB also issued ASU 2018-11, Leases (Topic 842): Targeted Improvements. The amendments in this update provide entities with an optional transition method, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption and not recast prior periods. In addition, the amendments in this update also provide lessors with a practical expedient (provided certain conditions are met), by class of underlying asset, to not separate the nonlease component(s) from the associated lease component and instead to account for the arrangement under either Topic 842 or Topic 606 depending on the predominant component.
We expect to adopt Topic 842 on January 1, 2019 and intend to elect the land easement practical expedient as well as the optional transition method. We also expect to adopt the package of practical expedients permitting us to not reassess under the new standard our prior conclusions regarding lease identification, lease classification and initial direct costs, the practical expedient to not separate lease and non-lease components for all of our existing lessee and lessor arrangements, and to elect an accounting policy to not apply the recognition requirements of Topic 842 to our short-term leases. We do not expect to elect the practical expedient for use of hindsight in determining the lease term and assessing impairment of our right-of-use assets.
We established a cross-functional team to implement the new standard and are currently in the process of implementing a leases software solution, evaluating the impact of the new standard on our consolidated financial statements and implementing appropriate changes to our internal processes and controls to support the accounting and disclosure requirements of the new standard.
Based on our evaluation to-date and from the perspective as the lessee, our leasing activity primarily consists of office space, vehicles, railcars, and tractors. We expect to recognize upon adoption of ASC 842 at January 1, 2019 an estimated right-of-use asset and a lease liability on our consolidated balance sheet. These amounts would represent less than 2% of our total consolidated asset and liabilities, respectively. At this time, we do not expect a material cumulative effect adjustment to retained earnings on January 1, 2019.
Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The amendments in this update change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments affect investments in loans, investments in debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The amendments also replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2019, with early adoption permitted. We do not expect a material impact on our consolidated financial statements.
Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract
In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. The amendments in this update require customers in a cloud computing arrangement that is a service contract to assess related implementation costs for capitalization using the same approach as implementation costs associated with internal-use software. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.
Recently adopted accounting pronouncements
Revenue from Contracts with Customers
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The amendments in this update supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The amendments also create a new Subtopic 340-40, Other Assets and Deferred Costs - Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The core principal of Topic 606 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to, in exchange for those goods or services. We adopted Topic 606 on January 1, 2018 by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption of Topic 606 did not result in a material cumulative effect adjustment to retained earnings on January 1, 2018. However, the adoption did have an impact on the classification between “Fees from midstream services” and “Product purchases,” as well as the reporting of gross versus net revenues, as discussed below:
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Embedded fees within commodity supply contracts where the counterparty is not deemed to be a customer are now reported as a reduction of “Product purchases.” Historically, such fees were reported as “Fees from midstream services.”
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Noncash consideration in the form of commodities received in-kind from a customer is now recognized as service revenue within “Fees from midstream services” when the service is performed. Historically, the noncash consideration was only recognized as revenue upon sale to a third party without corresponding “Product purchases.”
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For certain contracts structured as a purchase where we do not control the commodities, but rather are acting as an agent for the supplier, revenue is now recognized for the net amount of consideration we expect to retain in exchange for our service. Historically, the purchase from the supplier and subsequent sale were reported gross.
The following tables summarize the effects of adoption on our consolidated financial statements:
See Note 19 - Revenue for information regarding our performance obligations and Note 24 - Segment Information for further disaggregation of our revenues.
Cash Flow Classification
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). The amendments in this update clarify how entities should classify certain cash receipts and cash payments in the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. The amendments were effective for us on January 1, 2018 and were adopted on a retrospective basis, with no material effect on our consolidated financial statements. In addition, we elected to continue to apply our historical cumulative earnings approach to classify distributions received from equity method investees.
Business Combinations
In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this update clarify the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process are present. The amendments were effective for us on January 1, 2018 and were adopted on a prospective basis.
Other Income
In February 2017, FASB issued ASU 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20). The amendments in this update clarify the scope of Subtopic 610-20 and add guidance for partial sales of nonfinancial assets. Subtopic 610-20 was issued in May 2014 as part of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and provides guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with noncustomers. Specifically, the amendments clarify that the guidance applies to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance nonfinancial asset" as an asset or group of assets for which substantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. These amendments also impact the accounting for partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset but retains a noncontrolling ownership interest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. These amendments were effective for us on January 1, 2018; however, we did not have sales or transfers of nonfinancial assets that were incomplete as of the adoption date and, therefore, we did not have a cumulative effect adjustment to retained earnings.
Targeted Improvements to Accounting for Hedge Activities
In August 2017, FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities. The amendments in this update are intended to better align risk management activities and financial reporting for hedging relationships. The amendments cover multiple aspects of hedge accounting including: (1) change the way in which ineffectiveness is accounted; (2) allow for new hedge strategies; and (3) change hedge disclosures. Under the new guidance, companies will have the option to perform a qualitative quarterly effectiveness assessment once the initial quantitative test has been performed. In addition, any ineffectiveness that exists is required to be recorded in other comprehensive income instead of in earnings as was required under prior guidance. Several new hedging strategies qualify for hedge accounting treatment, most of these strategies involving the hedging of contractually specified components. Lastly, disclosure requirements have been updated to: (1) require that hedge income be presented on the same line item as the related hedged item; (2) require hedge program objectives to be disclosed; and (3) eliminate the requirement to separately disclose ineffectiveness. These amendments are effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted. We early adopted the amendments on January 1, 2018, with the changes to ineffectiveness resulting in no effect on retained earnings, as we had no accumulated ineffectiveness at December 31, 2017. See updated disclosures as a result of these amendments in Note 13 - Derivative Instruments and Hedging Activities and Note 24 - Segment Information.
Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures
Joint Ventures
Grand Prix Joint Venture
In May 2017, we announced plans to construct the Grand Prix pipeline (“Grand Prix”), a new common carrier NGL pipeline. Grand Prix will transport volumes from the Permian Basin and our North Texas system to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported by our volumes and other third-party customer volume commitments, and is expected to be fully in service in the third quarter of 2019.
In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”), which owns the portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas, to funds managed by Blackstone Energy Partners ("Blackstone"). We are the operator and construction manager of Grand Prix. We account for Grand Prix on a consolidated basis in our consolidated financial statements.
Concurrent with the sale of the 25% interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin.
In March 2018, we announced an extension of Grand Prix from North Texas into southern Oklahoma. The pipeline expansion is supported by long-term commitments for both transportation and fractionation from our existing processing plants in the Arkoma area in our SouthOK system and from third-party commitments, including a long-term commitment for transportation and fractionation with Valiant Midstream, LLC. The extension of Grand Prix into southern Oklahoma is not part of the Grand Prix Joint Venture and its expected cost of approximately $350 million will be funded exclusively by Targa.
The capacity of the 24-inch pipeline segment from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d. The pipeline segment from the Permian Basin will be connected to a 30-inch diameter pipeline segment in North Texas, where Permian, North Texas and Oklahoma volumes will be connected to Mont Belvieu, and will have capacity of approximately 450 MBbl/d, expandable to 950 MBbl/d. The capacity from Oklahoma to North Texas will vary based on telescoping pipe size.
In February 2019, we announced an extension of Grand Prix from southern Oklahoma to the STACK region of Central Oklahoma where it will connect with Williams’ new Bluestem Pipeline and link the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. Williams will also have an initial option to purchase a 20% equity interest in one of our recently announced fractionation trains (Train 7 or Train 8) in Mont Belvieu. This Grand Prix extension is expected to be completed in the first quarter of 2021 and is not part of the Grand Prix Joint Venture.
Grand Prix volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in the Blackstone and Grand Prix Development LLC (“Grand Prix DevCo JV”) joint venture arrangements (described below), while the volumes flowing from North Texas and Oklahoma to Mont Belvieu solely benefit us.
The total cost for Grand Prix, including the extension into Oklahoma, is expected to be approximately $1.9 billion.
Cayenne Joint Venture
In July 2017, we entered into the Cayenne Pipeline, LLC joint venture (“Cayenne Joint Venture”) with American Midstream LLC to convert an existing 62-mile gas pipeline to an NGL pipeline connecting the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline at Toca, Louisiana, for delivery to Enterprise’s Norco Fractionator. We acquired a 50% interest in the Cayenne Joint Venture for $5.0 million. The project commenced operations in December 2017. See Note 8 - Investments in Unconsolidated Affiliates for activity related to the Cayenne Joint Venture.
Gulf Coast Express Joint Venture
In December 2017, we entered into definitive joint venture agreements with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP (“DCP”) with respect to the joint development of the Gulf Coast Express Pipeline (“GCX”), a natural gas pipeline from the Waha hub to Agua Dulce in South Texas. The pipeline will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. GCX is designed to transport up to 1.98 Bcf/d of natural gas and the total cost of the project is estimated to be approximately $1.75 billion. GCX is expected to be in service in the fourth quarter of 2019, pending regulatory approvals.
We and DCP each own a 25% interest, and KMTP owns a 35% interest in GCX. In December 2018, Altus Midstream Company exercised their option to purchase the remaining 15% interest, which was originally held by KMTP. KMTP will serve as the construction manager and operator of GCX. We have committed significant volumes to GCX. In addition, Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin system, has committed volumes to the project. See Note 8 - Investments in Unconsolidated Affiliates for activity related to the GCX Joint Venture.
Little Missouri 4 Joint Venture
In January 2018, we formed a 50/50 joint venture with Hess Midstream Partners LP to construct a new 200 MMcf/d natural gas processing plant (“LM4 Plant”) at Targa’s existing Little Missouri facility (“Little Missouri 4”). The LM4 Plant is anticipated to be completed in the second quarter of 2019. Targa is managing the construction of, and will operate, the LM4 Plant. See Note 8 - Investments in Unconsolidated Affiliates for activity related to the Little Missouri 4 Joint Venture.
DevCo Joint Ventures
In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix, GCX and an approximately 100 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). Stonepeak owns a 95% interest in the Grand Prix DevCo JV, which owns a 20% interest in the Grand Prix Joint Venture (which does not include the extension into southern Oklahoma). Stonepeak owns an 80% interest in both Targa GCX Pipeline LLC (“GCX DevCo JV”), which owns our 25% interest in GCX, and Targa Train 6 LLC (“Train 6 DevCo JV”), which owns a 100% interest in certain assets associated with Train 6. The Train 6 DevCo JV does not include certain fractionation-related infrastructure such as brine and storage, which will be funded and owned 100% by us. We hold the remaining interests in the DevCo JVs as well as control the management, construction and operation of Grand Prix and Train 6.
The following diagram displays the ownership structure of the DevCo JVs:
For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, we have the option to acquire all or part of Stonepeak’s interests in the DevCo JVs. Targa may acquire up to 50% of Stonepeak’s invested capital in multiple increments with a minimum of $100 million, and Stonepeak’s remaining 50% interest in a single final purchase. The purchase price payable for such partial or full interests is based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs. Targa will control the management of the DevCo JVs unless and until Targa declines to exercise its option to acquire Stonepeak's interests. Train 6 is expected to begin operations in the second quarter of 2019. Grand Prix is expected to be fully in service in the third quarter of 2019. GCX is expected to be in service in the fourth quarter of 2019, pending regulatory approvals.
We hold a controlling interest in each of the DevCo JVs, as we have the majority voting interest and the supermajority voting provisions of the joint venture agreements do not represent substantive participating rights and are protective in nature to Stonepeak. As a result, we have consolidated each of the DevCo JVs in our financial statements. We continue to account for Grand Prix and Train 6 on a consolidated basis in our consolidated financial statements, and continue to account for GCX as an equity method investment as disclosed in Note 8 - Investments in Unconsolidated Affiliates.
Agua Blanca Joint Venture
In April 2018, we joined WhiteWater Midstream, LLC (“WhiteWater Midstream”), WPX Energy, Inc., and Markwest Energy Partners, L.P., as joint venture partners in WhiteWater Midstream’s Delaware Basin Agua Blanca pipeline (“Agua Blanca Joint Venture”). The Agua Blanca pipeline is an approximately 160 mile natural gas residue pipeline with an initial capacity of 1.4 Bcf/d. The pipeline, which commenced operations in April 2018, runs from Orla, Texas to the Waha hub, servicing portions of Culberson, Loving, Pecos, Reeves and Ward counties with multiple direct downstream connections including to the Trans-Pecos Header. We acquired a 10% interest in the Agua Blanca Joint Venture for $3.5 million. See Note 8 - Investments in Unconsolidated Affiliates for activity related to the Agua Blanca Joint Venture.
Carnero Joint Venture
In May 2018, Sanchez Midstream Partners LP and we merged our respective 50% interests in the Carnero gathering and Carnero processing joint ventures, which own the high-pressure Carnero gathering line and Raptor natural gas processing plant, to form an expanded 50/50 joint venture in South Texas (the “Carnero Joint Venture”). In connection with the joint venture merger transactions, the Carnero Joint Venture acquired our 200 MMcf/d Silver Oak II natural gas processing plant located in Bee County Texas, which increased the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d. Additional enhancements to the prior joint ventures include dedication of over 315,000 additional gross acres in the Western Eagle Ford, operated by Sanchez Energy Corporation, under a new long-term firm gas gathering and processing agreement. Including the approximately 105,000 Catarina acreage, the joint venture now has over 420,000 gross acres dedicated long term. We operate the gas gathering and processing facilities in the joint venture. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.
Whistler Pipeline
In August 2018, we announced that we were involved in the development of the Whistler Pipeline (“Whistler”), consisting of a proposed pipeline designed to transport natural gas from the Waha area of the Permian Basin to Agua Dulce in South Texas, with an additional segment continuing from Agua Dulce to Wharton County, TX. In February 2019, we announced that we do not expect to have any meaningful ownership interest in Whistler but will continue to work to commercialize the project as it provides strategic residue takeaway for us and our customers.
Acquisitions
Permian Acquisition
On March 1, 2017, Targa completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”).
We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the “initial purchase price”). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments. The first earn-out payment due in May 2018 expired with no required payment. The second potential earn-out payment would occur in May 2019 and will be based upon a multiple of realized gross margin through February 28, 2019 from contracts that existed on March 1, 2017.
New Delaware’s gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties in Texas. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Delaware system. Since March 1, 2017, financial and statistical data of New Delaware have been included in Sand Hills operations.
New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Midland system. Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations.
New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and the New Midland’s gas gathering and processing assets were connected to our WestTX system in the fourth quarter of 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and is expected to afford enhanced flexibility in serving our producer customers.
On January 26, 2017, Targa completed a public offering of 9,200,000 shares of its common stock (including the shares sold pursuant to the underwriters’ overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. Targa used the net proceeds from this public offering to fund the cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes.
The acquired businesses, which contributed revenues of $127.9 million and a net loss of $31.5 million to us for the period from March 1, 2017 to December 31, 2017, are included in our Gathering and Processing segment. As of December 31, 2017, we had incurred $5.6 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the year ended December 31, 2017.
Pro Forma Impact of Permian Acquisition on Consolidated Statements of Operations
The following summarized unaudited pro forma Consolidated Statements of Operations information for the years ended December 31, 2017 and December 31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future.
The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated:
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Reflect the amortization expense resulting from the fair value of intangible assets recognized as part of the Permian Acquisition.
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Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisition’s property, plant and equipment, net, and the fair value of property, plant and equipment acquired.
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Exclude $5.6 million of acquisition-related costs incurred as of December 31, 2017 from pro forma net income for the year ended December 31, 2017. Pro forma net income for the year ended December 31, 2016 was adjusted to include those charges.
The following table summarizes the consideration transferred to acquire New Delaware and New Midland:
We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair value of the assets acquired and liabilities assumed at the acquisition date is shown below:
Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Such excess of purchase price over the fair value of net assets acquired was approximately $46.6 million, which was recorded as goodwill. The goodwill is attributable to expected operational and capital synergies. The goodwill is amortizable for tax purposes.
The fair value of assets acquired included trade receivables of $6.7 million, all of which has been subsequently collected. The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 - Fair Value Measurements. These inputs require significant judgments and estimates.
During the three months ended June 30, 2017, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs, including forecasts of future volumes, capital expenditures and operating expenses. The measurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the amounts recognized at that date. We recognized these measurement period adjustments in the three months ended June 30, 2017, with the effect in our Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at March 1, 2017. During the three months ended June 30, 2017, the acquisition date fair value of contingent consideration liability decreased by $45.3 million, intangible assets increased by $66.7 million, and other assets, net, increased by $0.4 million, which resulted in a decrease in goodwill of $112.4 million. These adjustments resulted in an increase in depreciation and amortization expense of $0.4 million recorded for the three months ended June 30, 2017.
During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional measurement period adjustments.
Contingent Consideration
A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its fair value. We agreed to pay up to an additional $935.0 million in aggregate potential earn-out payments in May 2018 and May 2019. The acquisition date fair value of the potential earn-out payments of $416.3 million was originally recorded within Other long-term liabilities on our Consolidated Balance Sheets. As discussed in Note 11 - Other Long-term Liabilities, changes in the fair value of the liability (that were not accounted for as revisions of the acquisition date fair value) have been included in Other income (expense).
Flag City Acquisition and Centrahoma Contributions
On May 9, 2017, we purchased all of the equity interests in Flag City Processing Partners, LLC ("FCPP") from Boardwalk Midstream, LLC (“Boardwalk”) and all of the equity interests in FCPP Pipeline, LLC from Boardwalk Field Services, LLC (“BFS”) for a base purchase price of $60.0 million subject to customary closing adjustments. The final adjustment to the base purchase price paid to Boardwalk was an additional $3.6 million. As part of the acquisition (the “Flag City Acquisition”), we acquired a natural gas processing plant with 150 MMcf/d of operating capacity (the “Flag City Plant”) located in Jackson County, Texas; 24 miles of gas gathering pipeline systems and related rights of ways located in Bee and Karnes counties in Texas; 102.1 acres of land surrounding the Flag City Plant; and a limited number of gas supply contracts.
In 2017, the gas processing activities under the Flag City Plant contracts were redirected to our Silver Oak Plants, and the Flag City Plant was decommissioned in order to move the plant and its component parts to other Targa locations. In December 2017, Targa contributed the Flag City Plant assets to Centrahoma Processing, LLC (“Centrahoma”), a consolidated subsidiary and joint venture that we operate, in which we have a 60% ownership interest. The remaining 40% ownership interest in Centrahoma is held by MPLX LP (“MPLX”). In 2018, utilizing the Flag City Plant assets, Centrahoma constructed the Hickory Hills Plant in Hughes County, Oklahoma (the “Hickory Hills Plant”). The Hickory Hills Plant processes growing natural gas production from the Arkoma Woodford Basin and began operations in December 2018. In October 2018, Targa also contributed the 120 MMcf/d cryogenic Tupelo Plant in Coal County, Oklahoma (the “Tupelo Plant”) to Centrahoma. In conjunction with Targa’s contribution of both the Flag City Plant assets and the Tupelo Plant, MPLX made cash contributions to Centrahoma in order to maintain its 40% ownership interest.
We accounted for the Flag City Acquisition as an asset acquisition and capitalized less than $0.1 million of acquisition related costs as a component of the cost of assets acquired, which resulted in an allocation of $52.3 million of property, plant and equipment, $7.7 million of intangible assets for customer contracts and $3.6 million of current assets and liabilities, net.
Purchase of Outstanding Silver Oak II Interest
Effective as of June 1, 2017, we repurchased from SN Catarina, LLC (a subsidiary of Sanchez Energy Corp.) its 10% interest in our consolidated Silver Oak II Gas processing facility located in Bee County, Texas for a purchase price of $12.5 million. The change in our ownership interest was accounted for as an equity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our Consolidated Statements of Operations as a result.
Purchase of Outstanding Versado Membership Interest
On October 31, 2016, we executed a Membership Interest Sale and Purchase Agreement with Chevron U.S.A. Inc. to acquire the remaining 37% membership interest in our consolidated subsidiary Versado Gas Processors, L.L.C. (“Versado”). As we continue to control Versado, the change in our ownership interest was accounted for as an equity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our Consolidated Statements of Operations.
Divestitures
Sale of Venice Gathering System, L.L.C.
Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer. VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. Targa Midstream Services LLC continued to operate the Venice gathering system for four months after closing pursuant to a Transition Services Agreement with VGS. As a result of the sale, we recognized a loss of $16.1 million in our Consolidated Statements of Operations for the year ended December 31, 2017 as part of our Other operating (income) expense.
Sale of Refined Products and Crude Oil Storage and Terminaling Facilities
On September 12, 2018, we executed agreements to sell our Downstream refined products and crude oil storage and terminaling facilities in Tacoma, Washington, and Baltimore, Maryland, to a third party for approximately $165 million. The sale closed on October 31, 2018 and we used the proceeds to repay debt and to fund a portion of our growth capital program. In relation to the sale, we classified our Tacoma and Baltimore refined products and crude oil storage and terminaling facilities assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $57.5 million included within Other operating income (expense) in our Consolidated Statements of Operations in the third quarter of 2018. In the fourth quarter, we recognized an additional $1.6 million loss upon closing of the sale. The sale of these businesses does not qualify for reporting as discontinued operations as it did not represent a strategic shift that would have a major effect on our operations and financial results.
Subsequent Event
In February 2019, we entered into definitive agreements to sell a 45% interest in Targa Badlands LLC, the entity that holds all of our assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities for $1.6 billion. We will continue to be the operator of Targa Badlands LLC and will hold majority governance rights. Future growth capital is expected to be funded on a pro rata basis. Targa Badlands LLC will pay a minimum quarterly distribution to Blackstone and to Targa based on their initial investments, and Blackstone’s capital contributions will have a liquidation preference upon a sale of Targa Badlands LLC. We will continue to present Targa Badlands LLC on a consolidated basis in our consolidated financial statements. We expect to use the net cash proceeds to pay down debt and for general corporate purposes, including funding our growth capital program. The transaction is expected to close in the second quarter of 2019 and is subject to customary regulatory approvals and closing conditions.
Note 5 - Inventories
Note 6 - Property, Plant and Equipment and Intangible Assets
Property, Plant and Equipment
For each of the years ended December 31, 2018, 2017 and 2016 depreciation expense was $633.3 million, $621.3 million and $601.5 million.
2017 Impairment of North Texas Gathering and Processing Assets
We recorded a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017 for the partial impairment of gas processing facilities and gathering systems associated with our North Texas operations in our Gathering and Processing segment. The impairment was a result of our assessment that forecasted undiscounted future net cash flows from operations, while positive, would not be sufficient to recover the existing total net book value of the underlying assets. Given the price environment at the time, we projected a continuing decline in natural gas production across the Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins. We measured the impairment of property, plant and equipment using discounted estimated future cash flow analysis (“DCF”) including a terminal value (a Level 3 fair value measurement). The future cash flows were based on our estimates of future revenues, income from operations and other factors, such as timing of capital expenditures. We took into account current and expected industry and market conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis was based on a weighted average cost of capital determined from relevant market comparisons. These carrying value adjustments are included in Impairment of property, plant and equipment in our Consolidated Statements of Operations.
Intangible Assets
Intangible assets consist of customer contracts and customer relationships acquired in the Permian Acquisition and the acquisition of the Flag City Plant assets in SouthTX in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in 2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers.
The intangible assets acquired in the Permian Acquisition were recorded at a fair value of $692.3 million. We are amortizing these intangible assets over a 15-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified.
The intangible assets acquired in the Flag City Acquisition were recorded at a fair value of $7.7 million. We are amortizing these intangible assets over a 10-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified.
The intangible assets acquired in the Atlas mergers were recorded at a fair value of $1,354.9 million. We are amortizing these intangible assets over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified.
The intangible assets acquired in the Badlands acquisition were recorded at a fair value of $679.6 million. Amortization expense attributable to these intangible assets is recorded using a method that closely reflects the cash flow pattern underlying the intangible asset valuation over a 20-year life.
For each of the years ended December 31, 2018, 2017 and 2016 amortization expense for our intangible assets was $182.6 million, $188.2 million and $156.1 million. The estimated annual amortization expense for intangible assets is approximately $171.6 million, $159.4 million, $149.5 million, $141.2 million and $136.0 million for each of the years 2019 through 2023. As of December 31, 2018, the weighted average amortization period for our intangible assets was approximately 14.9 years.
The changes in our intangible assets are as follows:
Asset Sales
During the second quarter of 2018, we sold our inland marine barge business, which was included in our Logistics and Marketing segment, to a third party for $69.3 million. As a result of the sale, we recognized a gain of $48.1 million in our Consolidated Statements of Operations for the year ended December 31, 2018 as part of Other operating (income) expense. We continue to own and operate two ocean-going barges.
During the fourth quarter of 2018, we exchanged a portion of our Versado gathering system, located primarily in Yoakum County, Texas, and Lea County, New Mexico, and associated contracts and assets, with a third party for consideration that includes 1) a gathering system located primarily in Lea County, New Mexico, and associated contracts and assets, 2) an initial cash payment and 3) deferred payments due semi-annually beginning on June 30, 2019, through December 31, 2022. The acquired gathering system has been integrated into the Versado gathering system. Due to the significant monetary portion of the consideration received, the exchange of these assets was accounted for as a derecognition of nonfinancial assets, and a gain of $44.4 million was recognized in our Consolidated Statements of Operations for the year ended December 31, 2018 as part of Other operating (income) expense. The gain was calculated as the difference between the fair value of the consideration received, including the fair value of acquired gathering system, less our book basis of the assets transferred.
The fair value of the acquired assets was determined using the indirect cost method of valuation, adjusted for any physical and economic obsolescence, and other management estimates. The fair value measurements of assets acquired are based on inputs that are a combination of Level 2 and Level 3 inputs, as defined in Note 14 - Fair Value Measurements.
Note 7 - Goodwill
Goodwill related to the 2015 Atlas mergers was attributable to the WestTX and SouthTX reporting units in our Gathering and Processing segment. We also recognized goodwill of approximately $46.6 million related to the Permian Acquisition on March 1, 2017, which was attributed to the New Midland and New Delaware reporting units in our Gathering and Processing segment.
Changes in the net amounts of our goodwill are as follows:
The future cash flows and resulting fair values of these reporting units are sensitive to changes in crude oil, natural gas and NGL prices. The direct and indirect effects of significant declines in commodity prices from the date of acquisition would likely cause the fair values of these reporting units to fall below their carrying values, and could result in an impairment of goodwill.
As described in Note 3 - Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. Our annual evaluations utilized an income approach including a terminal value to estimate the fair values of our reporting units based on a discounted cash flow (“DCF”) analysis. The future cash flows for our reporting units are based on our estimates, at that time, of future revenues, income from operations and other factors, such as working capital and timing of capital expenditures. We take into account current and expected industry and market conditions, including commodity pricing and volumetric forecasts in the basins in which the reporting units operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital determined from relevant market comparisons.
The fair value measurements utilized for the evaluation of goodwill for impairment are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 - Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.
As of December 31, 2015, we had not completed our November 30, 2015 impairment assessment of the goodwill resulting from the February 2015 Atlas mergers. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment in our Consolidated Statements of Operations during the fourth quarter of 2015. During the first quarter of 2016, we finalized our 2015 impairment assessment and recorded additional impairment expense of $24.0 million in our Consolidated Statements of Operations. The impairment of goodwill was primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas.
Our 2016 annual evaluation of goodwill for impairment was completed in the fourth quarter of 2016. Due to the impact of lower forecasted commodity prices and a refinement in the valuation methodology used to determine fair values of our reporting units, we recorded impairment expense of $183.0 million in our Consolidated Statements of Operations.
We did not record any goodwill impairment charges for the year ended December 31, 2017, as the fair values of all reporting units exceeded their accounting carrying values.
Our 2018 annual evaluation of goodwill for impairment was completed in the fourth quarter of 2018. Due to the impact of lower forecasted commodity prices and a reduction in forecasted volumes as a result of changes in producers’ drilling activity, we recorded impairment expense of $210.0 million in our Consolidated Statements of Operations, representing the impairment of the remaining goodwill for WestTX and SouthTX.
Note 8 - Investments in Unconsolidated Affiliates
Our investments in unconsolidated affiliates consist of the following:
•
a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”);
•
three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), a gas gathering company; a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), a gas gathering company; and prior to December 31, 2018, a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 EF Cogen”), which owns a cogeneration facility, (together the “T2 Joint Ventures”);
•
a 50% operated ownership interest in the Cayenne Joint Venture;
•
a 25% non-operated ownership interest in GCX;
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a 50% operated ownership interest in Little Missouri 4; and
•
a 10% non-operated ownership interest in the Agua Blanca Joint Venture.
Investments in GCF, Cayenne Joint Venture, GCX and Agua Blanca Joint Venture are included in the total assets of Logistics and Marketing segment. Investments in T2 Joint Ventures and Little Missouri 4 are included in the total assets of Gathering and Processing segment. See Note 24 - Segment Information for more information regarding our segment assets.
The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting.
The T2 Joint Ventures were formed to provide services for the benefit of their joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with their joint interest owners, which cover costs of operations (excluding depreciation and amortization).
See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the formation of our GCX Joint Venture and Little Missouri 4 Joint Venture, and our acquisition of interests in the Cayenne Joint Venture and the Agua Blanca Joint Venture.
The following table shows the activity related to our investments in unconsolidated affiliates:
(1)
Includes $5.5 million, $0.2 million and $4.1 million in distributions received from GCF and the T2 Joint Ventures in excess of our share of cumulative earnings for the years ended December 31, 2018, 2017 and 2016. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in our Consolidated Statements of Cash Flows in the period in which they occur.
(2)
Includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures.
(3)
Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4. See Note 22 - Supplemental Cash Flow Information.
(4)
As discussed in Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures, our 25% interest in GCX is owned by GCX DevCo JV, of which we own a 20% interest. GCX DevCo JV is accounted for on a consolidated basis in our consolidated financial statements.
Our equity loss for the year ended December 31, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As a result of the decrease in current and expected future utilization of the underlying cogeneration assets, we determined that factors indicated that a decrease in the value of our investment occurred that was other than temporary. As a result of this evaluation, we recorded an impairment loss of approximately $12.0 million in the first quarter of 2017, which represented our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as our impairment of the unamortized excess fair value resulting from the Atlas mergers.
Effective December 31, 2018: (i) we conveyed our 50% ownership interest in T2 EF Cogen to our joint venture partner and received a distribution of certain assets from the joint venture; and, (ii) we were named as operator of T2 LaSalle and T2 Eagle Ford.
The carrying values of the T2 Joint Ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of December 31, 2018, $24.6 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets.
The following tables summarize the combined financial information of our investments in unconsolidated affiliates (all data presented on a 100% basis):
Note 9 - Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities includes $52.2 million and $49.7 million of liabilities to creditors to whom we have issued checks that remain outstanding as of December 31, 2018 and December 31, 2017. The current portion of the Permian Acquisition contingent consideration represents the estimated fair value of the earn-out payments due within twelve months of the respective balance sheet dates.
Note 10 - Debt Obligations
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(1)
As of December 31, 2018, we had $340.0 million of qualifying receivables under our $400.0 million accounts receivable securitization facility, resulting in availability of $60.0 million.
(2)
The 4⅛% Senior Notes due 2019 were redeemed in full on February 11, 2019.
(3)
As of December 31, 2018, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $1,420.5 million.
The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2018, for the next five years, and in total thereafter:
________________________________________________________________________________________
(1)
The 4⅛% Senior Notes due 2019 were redeemed in full on February 11, 2019.
The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2018:
Compliance with Debt Covenants
As of December 31, 2018, we were in compliance with the covenants contained in our various debt agreements.
Debt Obligations
Revolving Credit Facility
In June 2018, we entered into an agreement to amend and restate the TRP Revolver, which extended the maturity date from October 2020 to June 2023, increased available commitments from $1.6 billion to $2.2 billion and lowered the applicable margin range and commitment fee range used in the calculation of interest. Our ability to request additional commitments of $500.0 million remained unchanged.
The TRP Revolver provides for certain changes to occur upon the Partnership receiving an investment grade credit rating from Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Corporation (“S&P”), including the release of the security interests in all collateral at the request of the Partnership.
The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin (a) before the collateral release date, ranging from 0.25% to 1.25% dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (b) upon and after the collateral release date, ranging from 0.125% to 0.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The Eurodollar rate is equal to LIBOR rate plus an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings.
We are required to pay a commitment fee equal to an applicable rate ranging from (a) before the collateral release date, 0.25% to 0.375% (dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and (b) upon and after the collateral release date, 0.125% to 0.35% (dependent on our non-credit-enhanced senior unsecured long-term debt ratings) times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings.
The TRP Revolver is collateralized by a pledge of assets and equity from certain of the Partnership’s subsidiaries. Borrowings are guaranteed by our restricted subsidiaries.
The TRP Revolver requires us to maintain a total leverage ratio (the ratio of consolidated indebtedness to our consolidated Adjusted EBITDA, in each case as defined in the TRP Revolver), determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, of no more than (a) before the collateral release date, 5.50 to 1.00 and (b) upon and after the collateral release date, 5.25 to 1.00 (or 5.50 to 1.00 during a specified acquisition period).
The TRP Revolver generally removes the requirement that we maintain a maximum senior leverage ratio (the ratio of consolidated indebtedness, excluding indebtedness arising in connection with unsecured debt to consolidated Adjusted EBITDA) of no more than 4.00 to 1.00, except that we may not incur second lien indebtedness or consummate an acquisition of, or investment in, any included unrestricted subsidiary that would cause our senior leverage ratio to exceed 4.00 to 1.00 and we may not redeem our preferred units if doing so would cause our senior leverage ratio to exceed 3.50 to 1.00.
The TRP Revolver also requires us to maintain an interest coverage ratio of no less than 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination. For any four-fiscal quarter period during which a material acquisition or disposition occurs, the total leverage ratio and interest coverage ratio will be determined on a pro forma basis as though such event had occurred as of the first day of such four-fiscal quarter period.
The TRP Revolver restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in the TRP Revolver) exists or would result from such distribution. In addition, the TRP Revolver contains various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates (in each case, subject to our right to incur indebtedness or grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing, the aggregate principal of which shall not exceed $400,000,000).
During the year ended December 31, 2018, we incurred a loss of $1.3 million to partially write-off debt issuance costs associated with the TRP Revolver amendment as a result of a change in syndicate members. The remaining debt issuance costs, along with debt issuance costs incurred with this amendment, will be amortized on a straight-line basis over the TRP Revolver’s new term.
Accounts Receivable Securitization Facility
On December 7, 2018, we amended and extended the accounts receivable securitization facility to increase the facility size from $350.0 million to $400.0 million with a termination date of December 6, 2019. As of December 31, 2018, total funding under the Securitization Facility was $280.0 million.
The Securitization Facility provides up to $400.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 6, 2019. Under the Securitization Facility, certain Partnership subsidiaries sell or contribute certain qualifying receivables, without recourse, to another of its consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of the Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to third-party financial institutions. Sold or contributed receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of the selling or contributing subsidiaries or the Partnership. Any excess receivables are eligible to satisfy the claims.
Senior Unsecured Notes
All issues of unsecured senior notes are pari passu with existing and future senior indebtedness. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by us and our restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver and the Securitization Facility, which is secured by accounts receivable pledged under the facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears.
Our senior unsecured notes and associated indenture agreements restrict our ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notes are rated investment grade by either Moody’s or S&P and no Default or Event of Default (each as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Partnership and its subsidiaries will cease to be subject to such covenants.
We may redeem up to 35% of the aggregate principal amount of the notes in the table below at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days of the date of the closing of such equity offering.
We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed.
Senior Unsecured Notes Issuances
In October 2016, the Partnership Issuers issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes due February 2027 (collectively, the “2016 Senior Notes”), resulting in net proceeds after costs of approximately $496.2 million and $496.2 million respectively. The 2016 Senior Notes have substantially similar covenants as our other series of senior notes. The net proceeds from the offering of the 2016 Senior Notes (the “October 2016 Offering”), along with borrowings under the TRP Revolver were used to fund concurrent tender offers for certain other series of senior notes and to fund redemption payments for certain note balances remaining after the tender offers. See “Debt Repurchases and Extinguishments” for further details of the concurrent tender offers.
In October 2017, we issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 (the “5% Senior Notes due 2028”). We used the net proceeds of $744.1 million after costs from this offering to redeem our 5% Senior Notes, reduce borrowings under our credit facilities, and for general partnership purposes.
In April 2018, we issued $1.0 billion aggregate principal amount of 5⅞% senior notes due April 2026 (the “5⅞% Senior Notes due 2026”). We used net proceeds of $991.9 million after costs from this offering to repay borrowings under our credit facilities and for general partnership purposes.
Subsequent Event
In January 2019, we issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of $744.4 million and $744.4 million, respectively. The net proceeds from the offerings were used to redeem in full our outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date and the remainder is expected to be used for general partnership purposes, which may include repaying borrowings under its credit facilities or other indebtedness, funding growth investments and acquisitions and working capital.
Debt Repurchases & Extinguishments
In June 2017, we redeemed our outstanding 6⅜% Senior Notes due August 2022 (“6⅜% Senior Notes”), totaling $278.7 million in aggregate principal amount, at a price of 103.188% of the principal amount plus accrued interest through the redemption date. The redemption resulted in a $10.7 million loss, which is reflected as Loss from financing activities in our Consolidated Statements of Operations for the year ended December 31, 2017, consisting of premiums paid of $8.9 million and a non-cash loss to write-off $1.8 million of unamortized debt issuance costs.
In October 2017, we redeemed our outstanding 5% Senior Notes due 2018 at par value plus accrued interest through the redemption date. The redemption resulted in a non-cash Loss from financing activities to write-off $0.2 million of unamortized debt issuance costs during the year ended December 31, 2017.
During the year ended December 31, 2016, we repurchased on the open market a portion of our outstanding senior notes as follows:
During the years ended December 31, 2018 and 2017, we did not repurchase any of our outstanding senior notes on the open market.
We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Senior Notes Tender Offers
Concurrently with the October 2016 Offering, we commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of our 5% Senior Notes, 6⅝% Senior Notes due October 2020 (the “6⅝% Senior Notes”) and 6⅞% Senior Notes due February 2021 (the “6⅞% Senior Notes” and together with the 5% Senior Notes and 6⅝% Senior Notes, the “Tender Notes”). The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date.
The results of the Tender Offers, which closed in October 2016, were:
As a result of the Tender Offers, we recorded during the fourth quarter of 2016 a loss due to debt extinguishment of approximately $59.2 million comprised of the $41.8 million premium paid, the write-off of $5.8 million of debt issuance costs, $15.1 million of debt discounts less $3.5 million of debt premiums.
Note Redemptions
Subsequent to the closing of the Tender Offers in October 2016, we issued notices of full redemption (the “Note Redemptions”) to the trustees and noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition, we issued notice of full redemption to the trustees of the 6⅝% Senior Notes of Targa Pipeline Partners LP due October 2020 (the “2020 TPL Notes”). The redemption price for the 6⅝% Notes and the 2020 TPL Notes was 103.313% of the principal amount, while the redemption price for the 6⅞% Notes was 103.438% of the principal amount. The aggregate principal amount outstanding of all three series of notes totaling $146.2 million was redeemed on November 15, 2016 for a total redemption payment of $151.1 million, excluding accrued interest. As a result of the Note Redemptions, we recorded during the fourth quarter of 2016 a loss due to debt extinguishment of approximately $9.7 million comprised of the $4.9 million premium paid, the write-off of $1.1 million of debt issuance costs, $4.2 million of debt discounts less $0.5 million of debt premiums.
Debt Repurchases and Extinguishments Summary
The following table summarizes the debt repurchases and extinguishments that are included in our Consolidated Statements of Operations:
Note 11 - Other Long-term Liabilities
Other long-term liabilities are comprised of the following obligations:
Asset Retirement Obligations
Our ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows:
Mandatorily Redeemable Preferred Interests
Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.
The joint ventures, collectively, hold $1.9 billion face value in notes receivable from our partner, which are due July 2042. The interest rate payable under the notes receivable is a variable LIBOR-based rate. For the years ended December 31, 2018, 2017 and 2016, interest earned on the notes receivable of $9.7 million, $10.3 million, and $10.5 million, exclusive of the priority return payable to our partner, is reflected within Interest expense, net in our Consolidated Statements of Operations. We have accounted for the notes receivable at fair value. Upon redemption: (i) the distributable value of our partner’s interest in each joint venture is required to be adjusted by mutual agreement or under a valuation procedure outlined in each joint venture agreement based, among other things, on changes in the market value of the joint venture’s assets allocable to our partner (including the value of the notes receivable); and (ii) the parties are obligated to set off the value of the notes receivable from our partner against the value of our partner’s interest in the applicable joint venture. For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Because redemption will not be required until at least 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of December 31, 2018. The aggregate fair values of the notes receivable and the estimated redemption values of our partner’s interest in the joint ventures as of the reporting date are presented on the Consolidated Balance Sheets on a net basis.
In February 2018, the parties amended the agreements governing each joint venture to: (i) increase the priority return for capital contributions made on or after January 1, 2017; and (ii) add a non-consent feature effective with respect to certain capital projects undertaken on or after January 1, 2017. During the year ended December 31, 2018, the change in estimated redemption value of the mandatorily redeemable preferred interests is primarily attributable to the amendments.
The following table shows the changes attributable to mandatorily redeemable preferred interests:
Deferred Revenue
Deferred revenue includes consideration received related to the construction and operation of a crude oil and condensate splitter. On December 27, 2015, Targa Terminals LLC and Noble Americas Corp., a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we would build and operate a crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 Bbl of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d of crude oil and condensate into its various components, including naphtha, distillate, gas oil, kerosene/jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude and condensate and each of their components. In January 2018, Vitol US Holding Co. acquired Noble Americas Corp.
The first three annual payments of $43.0 million due under the Splitter Agreement were received in 2016, 2017 and 2018 and have been recorded as deferred revenue. The deferred revenue was expected to be recognized over the contractual term of seven years, commencing with start-up of operations. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is currently dependent upon resolution of the dispute with Vitol.
The Channelview Splitter is currently in the process of start-up and commissioning and has an estimated total cost of approximately $160 million. We are working on third-party contracts and commercialization of the Channelview Splitter.
Deferred revenue also includes nonmonetary consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the gathering assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. In December 2017, we received monetary consideration to further amend the terms of the gas gathering and processing agreement. The deferred revenue related to these amendments is being recognized on a straight-line basis through the end of the agreement’s term in 2035.
Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related to these other construction activities is being recognized over the periods that future performance will be provided, which extend through 2023.
For the years ended December 31, 2018, 2017 and 2016, we recognized approximately $3.9 million, $3.1 million and $3.1 million of revenue for these transactions.
The following table shows the components of deferred revenue:
The following table shows the changes in deferred revenue:
Permian Acquisition Contingent Consideration
Upon closing of the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fair value. See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures. The first potential earn-out payment would have occurred in May 2018 while the second potential earn-out payment would occur in May 2019. The acquisition date fair value of the contingent consideration of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets. For the period from the acquisition date to December 31, 2017, the fair value of the contingent consideration decreased by $99.3 million, primarily related to reductions in forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date, bringing the total Permian Acquisition contingent consideration to $317.0 million at December 31, 2017, of which $6.8 million was a current liability.
The portion of the earn-out due in 2018 expired with no required payment. For the period from December 31, 2017 to December 31, 2018, the fair value of the contingent consideration decreased by $8.8 million, primarily attributable to lower actual and forecasted volumes for the remainder of the earn-out period, partially offset by a shorter discount period. As of December 31, 2018, the fair value of the second potential earn-out payment of $308.2 million has been recorded as a component of accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets.
The following table shows the changes in the fair value of the contingent consideration related to the Permian Acquisition discussed in Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures:
See Note 14 - Fair Value Measurements for additional discussion of the fair value methodology.
Note 12 - Partnership Units and Related Matters
TRC/TRP Merger
On February 17, 2016, TRC completed the TRC/TRP Merger, indirectly acquiring all of the outstanding common units not already owned by TRC and its subsidiaries. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.
At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of TRC common stock. TRC issued 104,525,775 shares of its common stock to third-party unitholders of our common units in exchange for all of our 168,590,009 outstanding common units that TRC previously did not own. No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.
Pursuant to the TRC/TRP Merger Agreement, our common units were delisted from the NYSE and deregistered under the Exchange Act and our common units are no longer publicly traded. Our 5,000,000 Preferred Units remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE.
Distributions
As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement as to whether to distribute all available cash for any period. See Note 1 - Organization and Operations.
The following details the distributions declared or paid by the Partnership during 2018, 2017 and 2016:
The IDR Giveback Amendment in conjunction with the Atlas mergers, covered sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015. The IDR Giveback resulted in reallocation of IDR payments to common unitholders of $6.25 million for each of the first three quarters of 2016.
On October 19, 2016, we executed the Third A&R Partnership Agreement, which became effective on December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the IDRs held by our general partner, and related distribution and allocation provisions, (ii) eliminating the Special GP Interest (as defined in the Third A&R Partnership Agreement) held by our general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.
As a result of the Third A&R Partnership Agreement, the reallocations of IDRs under the IDR Giveback Amendment ceased in the fourth quarter of 2016.
On December 1, 2016, we issued to our general partner (i) 20,380,286 common units and 424,590 General Partner units in exchange for the elimination of the IDRs and (ii) 11,267,485 common units and 234,739 General Partner units in exchange for the elimination of the Special GP Interest in connection with the Third A&R Partnership Agreement.
Contributions
Subsequent to the TRC/TRP Merger, 58,621,036 common units and 1,196,346 general partner units were issued for Targa’s contributions of $1,191.0 million. Subsequent to the effective date of the Third A&R Partnership Agreement, no units will be issued for capital contributions but all capital contributions will continue to be allocated 98% to the limited partner and 2% to our general partner. In December 2016, Targa made a $190.0 million capital contribution to us which was allocated accordingly. For the years ended December 31, 2018, 2017 and 2016, Targa made total capital contributions to us of $600.0 million, $1,720.0 million and $1,381.0 million.
Preferred Units
In October 2015, under the April 2013 Shelf, we completed an offering of 4,400,000 Preferred Units at a price of $25.00 per unit. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 600,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. We used the net proceeds from this offering to reduce borrowings under our senior secured credit facility and for general partnership purposes. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”
Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.
The Preferred Units, with respect to anticipated monthly distributions, rank:
•
senior to our common units and to each other class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior to or pari passu with the Preferred Units as to the payment of distributions;
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pari passu with any class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior or subordinated to the Preferred Units as to the payment of distributions;
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junior to all of our existing and future indebtedness (including (i) indebtedness outstanding under the TRP Revolver, (ii) our senior notes and (iii) indebtedness outstanding under the Securitization Facility and other liabilities with respect to assets available to satisfy claims against us; and
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junior to each other class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is expressly made senior to the Preferred Units as to the payment of distributions.
At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. If we do not (or a third party with our prior written consent does not) exercise this option, then the holders of the Preferred Units (“Preferred Unitholders”) have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement. If we exercise (or a third party with our prior written consent exercises) our redemption rights relating to any Preferred Units, the Preferred Unitholders will not have the conversion right described above with respect to the Preferred Units called for redemption. The Preferred Unitholders have no voting rights except for certain exceptions set forth in our Partnership Agreement.
As of December 31, 2018, we have 5,000,000 Preferred Units outstanding. We paid $11.3 million of distributions each year to the Preferred Unitholders for 2018, 2017 and 2016.
In January and February 2019, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit, resulting in approximately $0.9 million in distributions each month. The distributions declared in January were paid on February 15, 2019 and the distributions declared in February will be paid on March 15, 2019.
Note 13 - Derivative Instruments and Hedging Activities
The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Marketing segment and (iii) natural gas transportation basis risk in our Logistics and Marketing segment. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes.
The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.
We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.
We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.
At December 31, 2018, the notional volumes of our commodity derivative contracts were:
Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:
The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:
Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Some of our hedges are futures contracts executed through a broker that clears the hedges through an exchange. We maintain a margin deposit with the broker in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within other current assets on our Consolidated Balance Sheets and is not offset against the fair values of our derivative instruments.
The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net asset of $112.7 million as of December 31, 2018. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.
The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue and expense for the periods indicated:
Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.
Based on valuations as of December 31, 2018, we expect to reclassify commodity hedge related deferred gains of $123.8 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2021, with $92.5 million of gains to be reclassified over the next twelve months.
See Note 14 - Fair Value Measurements and Note 24 - Segment Information for additional disclosures related to derivative instruments and hedging activities.
Note 14 - Fair Value Measurements
Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.
Fair Value of Derivative Financial Instruments
Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.
The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at December 31, 2018, a net asset position of $112.7 million, reflects the present value, adjusted for
counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net asset of $37.3 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $188.7 million, ignoring an adjustment for counterparty credit risk.
Fair Value of Other Financial Instruments
Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:
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The TRP Revolver and the Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and
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Senior unsecured notes are based on quoted market prices derived from trades of the debt.
Contingent consideration liabilities related to business acquisitions are carried at fair value.
Fair Value Hierarchy
We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:
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Level 1 - observable inputs such as quoted prices in active markets;
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Level 2 - inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and
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Level 3 - unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.
The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:
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(1)
The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 - Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.
(2)
We have a contingent consideration liability related to the Permian Acquisition, which is carried at fair value. See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures.
(3)
We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value.
Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets
We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable implied volatilities or market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.
The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.
As of December 31, 2018, we had 13 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.
The fair value of the Permian Acquisition contingent consideration was determined using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate. The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) in our Consolidated Statements of Operations.
The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
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(1)
Represents the change in fair value between December 31, 2017 and December 31, 2018 of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the initial fair value.
Note 15 - Related Party Transactions
Transactions with Unconsolidated Affiliates
The following table summarizes transactions with unconsolidated affiliates:
Relationship with Targa
We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.
Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) until March 2018, costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.
The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.
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(1)
Prior to the execution of the Third A&R Partnership Agreement, 2016 cash distributions to Targa also included IDRs.
(2)
The 2016 cash contributions from Targa related to limited partner ownership was contributed for the issuance of common units. The 2018 and 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to the general partner. See Note 12 - Partnership Units and Related Matters.
Relationship with Sajet Resources LLC
In December 2010, immediately prior to Targa’s initial public offering, Sajet Resources LLC (“Sajet”) was spun-off from Targa. Rene Joyce, James Whalen and Joe Bob Perkins, directors of Targa, are also directors of Sajet. Joe Bob Perkins, James Whalen, Michael Heim, Jeffrey McParland, Paul Chung, and Matthew Meloy, executive officers of Targa, are also executive officers of Sajet. The primary assets of Sajet are real property. Sajet also holds (i) an ownership interest in Floridian Natural Gas Storage Company, LLC through a December 2016 merger with Tesla Resources LLC, (ii) an ownership interest in Allied CNG Ventures LLC and (iii) certain technology rights. Former holders of our pre-IPO common equity, including certain of our current and former executives, managers and directors collectively own an 18% interest in Sajet. We provide general and administrative services to Sajet and were reimbursed for these amounts at our actual cost. Fees for services provided to Sajet totaled less than $0.1 million in January and February of 2018, $0.3 million in the year ended December 31, 2017, and $0.5 million in the year ended December 31, 2016.
In March 2018, we acquired the 82% interest in Sajet that was held by Warburg Pincus sponsored funds for $5.0 million in cash (the “Warburg Funds Transaction”) and extinguished Sajet’s third-party debt in exchange for a promissory note from Sajet of $9.9 million. Minority shareholders had the right to join the transaction and sell up to 100% of their membership interests in Sajet to us at substantially the same terms and price as the Warburg Funds Transaction (the “Tag-Along Rights”). Minority shareholders who currently hold, or formerly held, executive positions at Targa, and minority shareholders who are board members of Targa, agreed not to exercise their Tag-Along Rights resulting from the Warburg Funds Transaction. Certain minority shareholders chose to sell interests totaling 1.6% for approximately $0.1 million in April 2018.
Since March 2018, Sajet has been accounted for on a consolidated basis in our consolidated financial statements.
Note 16 - Commitments
Future non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter:
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(1)
Includes minimum payments on lease obligations for office space, railcars and tractors.
(2)
Land site lease and rights of way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual.
Total expenses incurred under the above non-cancelable commitments were:
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(1)
Includes short-term leases for items such as compressors and equipment.
Note 17 - Contingencies
Legal Proceedings
We are a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We are also a party to various proceedings with governmental environmental agencies in 2018, including but not limited to the Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Health, Environmental Health Section, which assert penalties for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business.
On December 28, 2018, Targa Midstream Services LLC and the New Mexico Environment Department entered into a Settlement Agreement and Stipulated Final Compliance Order resolving alleged air emissions violations relating to flaring of acid gas at Targa Midstream Services LLC’s Monument gas processing plant in Lea County, New Mexico. This order imposes a $150,000 penalty and a Supplemental Environmental Project involving the provision of additional compression facilities. Additionally, on February 26, 2019, the U.S. Environmental Protection Agency Region 8 and Targa Badlands LLC entered into a Final Order and Consent Agreement in connection with Targa Badland LLC’s alleged violation of Subpart ZZZZ of the National Emission Standards for Hazardous Air Pollutants at its Junction Compressor Station in McKenzie County, North Dakota. The Consent Agreement imposes a $220,000 civil penalty and certain compliance improvements.
Note 18 - Significant Risks and Uncertainties
Nature of Our Operations in Midstream Energy Industry
We operate in the midstream energy industry. Our business activities include gathering, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products and changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.
Our profitability could be impacted by a decline in the volume of crude oil, natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities, or otherwise, could result in a decline in the volume of crude oil, natural gas, NGLs and condensate handled by our facilities.
A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.
Our principal market risks are exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, and changes in interest rates.
Commodity Price Risk
A significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. In response to these price risks, we monitor NGL inventory levels in order to mitigate losses related to downward price exposure.
In an effort to reduce the variability of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk. Historically, these transactions have included both swaps and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We hedge a higher percentage of our expected equity volumes in the earlier future periods. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity and pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than actual equity volumes, we limit our use of swaps to hedge the prices of less than our expected equity volumes. Our commodity hedges may expose us to the risk of financial loss in certain circumstances.
We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas and NGL prices.
Counterparty Risk - Credit and Concentration
Derivative Counterparty Risk
Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.
We have master netting provisions in the International Swap Dealers Association agreements with our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties, which reduced our maximum loss due to counterparty credit risk by $36.7 million as of December 31, 2018. The range of losses attributable to our individual counterparties would be between $0.3 million and $28.0 million, depending on the counterparty in default.
The credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value, representing expected future receipts, at the reporting date. At such times, these outstanding instruments expose us to losses in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of the counterparties decline, the ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
Customer Credit Risk
We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met. Our allowance for doubtful accounts was $0.1 million as of December 31, 2018 and $0.1 million as of December 31, 2017.
Significant Commercial Relationship
During the year ended December 31, 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 15% of our consolidated revenues. No customer comprised greater than 10% of our consolidated revenues in the years ended December 31, 2017 and 2016.
Interest Rate Risk
We are exposed to changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and Securitization Facility.
Casualty or Other Risks
Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverage which is customary for the nature and scope of our operations. The majority of the insurance costs described above is allocated to us by Targa through the Partnership Agreement described in Note 15 - Related Party Transactions.
Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles may change overtime, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.
If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations. Furthermore, even when a business interruption event is covered, it could affect interperiod results as we would not recognize the contingent gain until realized in a period following the incident.
Note 19 - Revenue
Fixed consideration allocated to remaining performance obligations
The following table includes the estimated minimum revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments and for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements.
In accordance with the optional exemptions that we elected to apply, the amounts presented in the table exclude variable consideration for which the allocation exception is met and consideration associated with performance obligations of short-term contracts. In addition, consideration from contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed is also excluded from the table above, with the exception of any fixed consideration attributable to such contracts. The nature of the performance obligations for which the consideration has been excluded is consistent with the performance obligations described within our revenue recognition accounting policy and the estimated remaining duration of such contracts primarily ranges from 1 to 15 years. In addition, variability exists in the consideration excluded due to the unknown quantity and composition of volumes to be serviced or sold as well as fluctuations in the market price of commodities to be received as consideration or sold over the applicable remaining contract terms. Such variability is resolved at the end of each future month or quarter.
For additional information on our revenue recognition policy and the adoption of ASU No. 2014-09, see Note 3 - Significant Accounting Policies. For disclosures related to disaggregated revenue, see Note 24 - Segment Information.
Note 20 - Other Operating (Income) Expense
Other Operating (Income) Expense is comprised of the following:
The (Gain) loss on sale or disposal of assets is comprised of the following:
Note 21 - Income Tax
Our income tax expense (benefit) is summarized below:
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act makes broad and complex changes to the Internal Revenue Code of 1986, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) eliminating the corporate alternative minimum tax (AMT) and changing how existing AMT credits are realized; (3) creating a new limitation on deductible interest expense; and (4) changing rules related to uses and limitation of net operating loss carryforwards created in tax years beginning after December 31, 2017.
The SEC staff issued Staff Accounting Bulletin No. 118 (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Act for which the accounting under ASC 740 is complete. To the extent that a company's accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act.
In connection with our initial analysis of the impact of the Tax Act, we recorded a discrete net deferred tax benefit of $1.0 million in the year ended December 31, 2017, for TPL Arkoma, Inc. This net deferred tax benefit consisted of the corporate tax rate reduction. As of December 31, 2017, we were able to make reasonable estimates of certain elements of the Tax Act, which we recorded as provisional adjustments.
Our accounting for all applicable elements of the Tax Act is complete:
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We reclassified $0.3 million of AMT credits from deferred tax assets to long term assets. We expect to receive this amount as a refund in 2019, 2020 and 2021.
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Reduction of U.S. federal corporate tax rate: The Tax Act reduces the corporate tax rate to 21%, effective January 1, 2018. We recorded a provisional deferred tax benefit of $1.0 million for the year ended December 31, 2017.
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Cost recovery: In the year ended December 31, 2017, we recorded a provisional tax depreciation expense of $0.7 million, which did not include full expensing of all qualifying capital expenditures. In the year ended December 31, 2018, we completed our analysis of capital expenditures and recorded no additional expenditures.
Prior to the TRC/TRP Merger, the Partnership was subject to the Texas margin tax, consisting generally of a 0.75% tax on the amounts by which total revenues exceed cost of goods sold, as apportioned to Texas. After the TRC/TRP Merger, TRC is the reporting company for the combined group. The Partnership still has audit responsibility for the pre-Merger years.
Our deferred income tax assets and liabilities at December 31, 2018 and 2017, consisted of differences related to the timing of recognition of certain types of costs as follows:
As of December 31, 2018, TPL Arkoma, Inc. had net operating loss carry forwards for federal income tax purposes of approximately $50.3 million, which expire at various dates from 2029 to 2038. Management believes it more likely than not that the deferred tax asset will be fully utilized.
Note 22 - Supplemental Cash Flow Information
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(1)
Interest capitalized on major projects was $46.3 million, $14.3 million and $8.3 million for the years ended December 31, 2018, 2017 and 2016.
Note 23 - Compensation Plans
TRC Equity Compensation Plan
In 2007, both we and Targa adopted Long-Term Incentive Plans (each, an “LTIP”) for employees, consultants, directors and non-employee directors of us and our affiliates who perform services for Targa or its affiliates. The awards under this plan included performance units, phantom units and director grants. Our LTIP (“TRP LTIP”) provided for, among other things, the grant of both cash-settled and equity-settled performance units. In connection with the TRC/TRP Merger, as of February 17, 2016, Targa assumed, adopted, and amended the TRP LTIP, and changed the name of the plan to the Targa Resources Corp. Equity Compensation Plan (as assumed, adopted and amended, the “TRC Equity Compensation Plan” or the “Plan”), and Targa assumed all our obligations associated with the Plan existing prior to the assumption and adoption by us. The TRC Equity Compensation Plan allows for the grant of options, performance shares, restricted stocks, replacement stocks and other stock-based awards. The termination date for this plan was February 7, 2017.
Awards Under TRP LTIP
Performance Units
The performance units granted under the TRP LTIP were linked to the performance of our common units. Performance unit awards granted under either LTIP may also include distribution equivalent rights. The TRP LTIP was administered by the board of directors of our general partner of TRP. Total units authorized under the TRP LTIP were 1,680,000.
Each performance unit entitled the grantee to the value of our common unit on the vesting date multiplied by a stipulated vesting percentage determined from our ranking in a defined peer group. The performance period for most awards was three-years, except for certain awards granted in December 2013, which provided for two, three or four-year vesting periods. The grantee received the vested unit value in cash or common units depending on the terms of the grant. The grantee may also be entitled to the value of any distribution equivalent rights based on the notional distributions accumulated during the vesting period times the vesting percentage. Distribution equivalent rights were paid for both cash-settled and equity-settled performance units.
Compensation cost for equity-settled performance units was recognized as an expense over the performance period based on fair value at the grant date. Fair value was calculated using a simulated unit price that incorporates peer ranking. Distribution equivalent rights associated with equity-settled performance units were accrued over the performance period as a reduction of owners’ equity. We evaluated the grant date fair value using a Monte Carlo simulation model and historical volatility assumption to estimate accruals throughout the vesting period.
Phantom Units
In 2015, we granted phantom units under the LTIP to various employees of Targa. These phantom units were denominated with respect to our common units, but not otherwise linked to the performance of our common units. Their vesting periods vary from one year to five years. The distribution equivalent rights of the phantom units were accumulated to be paid in cash at the vesting dates.
Replacement Phantom Units
In connection with the APL merger in 2015, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees upon close of the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and will vest either 25% per year over the original four-year term or 33% per year over the original three-year term. The distribution equivalent rights of the replacement phantom units are paid in cash within 60 days of the payment of distributions.
Partnership Director Grants
Starting in 2012, the common units granted to our non-management directors vested immediately at the grant date. The weighted average grant date fair value of the director grants granted in 2016 was $10.11. The fair value related to the units vested was $0.3 million.
Impact of TRC/TRP Merger
The TRC/TRP Merger did not trigger the acceleration of any time-based vesting of any of our outstanding long-term equity incentive compensation awards under the TRP LTIP. All outstanding performance unit awards previously granted under the TRP LTIP were converted and restated into comparable awards based on Targa’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the TRC/TRP Merger, into an award to acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Targa common shares determined by multiplying the number of performance units subject to each award by the exchange ratio in the TRC/TRP Merger (0.62), rounded down to the nearest whole share, and the performance factor was eliminated.
At the time of the TRC/TRP Merger and immediately prior to the assumption and adoption of the Plan, the only outstanding awards under the TRP LTIP were-equity settled performance units and certain phantom units of us. All such outstanding awards were converted into comparable time-based RSUs based on Targa’s common stock. All amounts previously credited as distribution equivalent rights under any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forth in the applicable award agreement, subject to the same time-based vesting schedule previously included in the performance unit award, but without application of any performance factor. The total employees affected by the amendment of the TRP LTIP were 363.
The February 17, 2016 conversion of 675,745 equity-settled performance units and 349,541 replacement phantom units outstanding to 418,906 equity-settled performance shares and 216,561 replacement phantom shares was considered modification of awards under ASC 718, Accounting for Stock-Based Compensation (“ASC 718”). The incremental change of $3.9 million in fair value between the original grant date fair value and the fair value as of February 17, 2016 is being recognized prospectively in general and administrative expense over the remaining service period of each award.
In addition to the conversion of TRP awards, we issued 331,282 restricted stock units under the Plan in 2016 which will cliff vest three years from the grant date. Of these 2016 grants, 310,809 RSUs were made in lieu of cash bonus for our nonexecutives. The grant-date fair value for the issuances was $74.01. In 2018 and 2017, no restricted stock units were issued under the Plan.
The following table summarizes the restricted stock units for the year ended December 31, 2018, under the Plan:
TRC Long Term Incentive Plan
The TRC LTIP is administered by the Compensation Committee of the Targa board of directors. Prior to the TRC/TRP Merger, the TRC LTIP provided for the grant of cash-settled performance units only. In connection with the TRC/TRP Merger, performance unit grant agreements were amended to convert TRP’s outstanding cash-settled performance unit obligation to cash-settled restricted stock units.
On February 17, 2016, as a result of the TRC/TRP Merger, 451,990 of TRP’s outstanding cash-settled performance units were converted to 279,964 cash-settled restricted stock units under the TRC LTIP with performance factors eliminated. All amounts previously credited as distribution equivalent rights under any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forth in the applicable award agreement, subject to the same time-based vesting schedule previously included in the performance unit award, but without application of any performance factor.
The February 17, 2016 conversion of outstanding cash-settled performance units to cash-settled restricted stock units was considered modification of awards under ASC 718. The incremental change in fair value between the original grant date fair value and the fair value as of February 17, 2016 resulted in recognition of additional compensation costs during the first quarter of 2016 of $4.8 million. Compensation expense for cash-settled performance units and any related distribution equivalent rights will ultimately be equal to the cash paid to the grantee upon vesting. However, throughout the vesting period Targa must record an accrued expense based on fair value of the stock on the last business day of the quarter. During 2018, the remaining 112,550 shares of cash-settled awards vested and paid for $6.9 million.
The cash settled for the awards under TRC LTIP were $6.9 million, $4.1 million and $4.8 million for 2018, 2017 and 2016.
2010 TRC Stock Incentive Plan
In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan for employees, consultants and non-employee directors of the Company. In May 2017, the 2010 TRC Plan was amended and restated (the “2010 TRC Plan”). Total authorized shares of common stock under the plan is 15,000,000, comprised of 5,000,000 shares originally available and an additional 10,000,000 shares that became available in May. The 2010 TRC Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as incentive options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom Stock Awards”), (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards (collectively referred to as “Awards”).
Unless otherwise specified, the compensation costs for the awards listed below were recognized as expenses over related vesting periods based on the grant-date fair values, reduced by forfeitures incurred.
Restricted Stock Awards - Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends, and paid in cash when the award vests. The restricted stock awards will be included in the outstanding shares of our common stock upon issuance.
Restricted Stock in Lieu of Salary - During 2016, Targa issued on a quarterly basis, a total of 32,267 shares of restricted stock to two of our executives in lieu of all of their 2016 base salary. These awards vested one year from the date of each grant. The weighted average grant-date fair value of these shares of restricted stock was $41.43. The number of shares of restricted stock awarded was determined by dividing one-fourth of the officer’s annual base salary by the average closing price of the shares of common stock for five trading days before the end of each quarter. There was no issuance of this type of awards in 2017 and 2018.
Director Grants - The committee awarded Targa’s common stock to its outside directors. In 2018, 2017 and 2016, Targa issued 16,955, 13,818 and 24,234 shares of director grants with the weighted average grant-date fair value of $51.21, $60.48 and $16.45. Starting from January 1, 2018, director grants are restricted stock awards that vest in one year. In prior years, directors were granted shares of common stock with no vesting requirement.
Restricted Stock Units Awards - Restricted Stock Units (“RSUs”) are similar to restricted stock, except that shares of common stock are not issued until the RSUs vest. The vesting periods vary from one year to five years. In 2018, 2017 and 2016, Targa issued 1,393,812, 1,193,942 and 1,129,705 shares of RSUs with the weighted average grant-date fair value of $51.71, $54.18 and $27.87. The 2018 issuances include 275,076 shares of RSUs for our new retention program. These shares will vest in four years.
Restricted Stock in Lieu of Bonus - During 2018, 2017 and 2016, Targa issued 112,438, 84,221 and 153,252 shares of restricted stock awards in lieu of cash bonuses in the form of RSUs for its executives at the weighted average grant-date fair value of $51.09, $55.94 and $26.34. These awards will cliff vest over three years. Dividends on these awards are paid quarterly.
The following table summarizes the restricted stock and RSUs under the 2010 TRC Plan in shares and in dollars for the year indicated.
Performance Share Units
During 2018 and 2017, we issued 182,849 and 113,901 shares of performance share units (“PSUs”) to executive management and employees for the 2018 and 2017 compensation cycle that will vest on December 31, 2020 and December 31, 2019. The PSUs granted under the 2010 TRC Plan are three-year equity-settled awards linked to the performance of shares of our common stock. The awards also include dividend equivalent rights (“DERs”) that are based on the notional dividends accumulated during the vesting period.
The vesting of the PSUs is dependent on the satisfaction of a combination of certain service-related conditions and the Company’s total shareholder return (“TSR”) relative to the TSR of the members of a specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periods. The TSR performance factor is determined by the Committee at the end of the overall performance period based on relative performance over the designated weighting periods as follows: (i) 25% based on annual relative TSR for the first year; (ii) 25% based on annual relative TSR for the second year; (iii) 25% based on annual relative TSR for the third year; and (iv) the remaining 25% based on cumulative three-year relative TSR over the entirety of the performance period. With respect to each weighting period, the Committee determines the “guideline performance percentage,” which could range from 0% to 250%, based upon the Company’s relative TSR performance for the applicable period. The TSR performance factor will be calculated by averaging the guideline performance percentage for each weighting period, and the average percentage may then be decreased or increased by the Committee at its discretion. The grantee will become vested in a number of PSUs equal to the target number awarded multiplied by the TSR performance factor, and vested PSUs will be settled by the issuance of Company common stock. The value of dividend equivalent rights will be paid in cash.
Compensation cost for equity-settled PSUs was recognized as an expense over the performance period based on fair value at the grant date. The compensation cost will be reduced if forfeitures occur. Fair value was calculated using a simulated share price that incorporates peer ranking. DERs associated with equity-settled PSUs were accrued over the performance period as a reduction of owners’ equity. We evaluated the grant date fair value using a Monte Carlo simulation model and historical volatility assumption with an expected term of three years. The expected volatilities were 55% - 61% for PSUs granted in 2017 and 29% - 53% for PSUs granted in 2018.
The following table summarizes the PSUs under the 2010 TRC Plan in shares and in dollars for the years indicated.
Cash-settled Awards
In October, we issued 69,042 shares of cash-settled awards for our new retention program. These awards vest each quarter for one year. The fair value of the awards is evaluated based on the average of TRC stock prices for the last ten trading days at the end of each quarter. The following table summarizes the cash-settled restricted stock units for the year ended 2018. The vested awards will be settled in cash for $0.6 million in 2019. The weighted average remaining year for the unvested shares is less than a year.
Stock compensation expense under our plans totaled $59.0 million, $44.2 million, and $41.2 million for the years ended December 31, 2018, 2017, and 2016.
As of December 31, 2018, we have $109.4 million of unrecognized compensation expense associated with share-based awards and an approximate remaining weighted average vesting periods of 2.6 years related to our various compensation plans.
The fair values of share-based awards vested in 2018, 2017 and 2016 were $18.8 million, $14.4 million and $17.1 million. Cash dividends paid for the vested awards were $3.5 million, $2.5 million and $2.7 million for 2018, 2017 and 2016.
Subsequent Events
In January 2019, the Compensation Committee of the Targa board of directors made the following awards under the 2010 TRC Plan.
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25,344 shares of restricted stock to our outside directors that will vest in January 2020.
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20,316 shares of RSUs under retention program that will vest on October 1, 2022, together with 3,842 cash-settled RSUs that vest 33% on March 31, 2019, 33% on Jun 30, 2019 and 34% on September 30, 2019.
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269,530 shares of RSUs to executive management for the 2019 compensation cycle that will vest in January 2022
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261,245 shares of PSUs to executive management for the 2019 compensation cycle that will vest in December 2021.
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95,687 shares of RSUs in lieu of cash bonus to executive management for the 2019 compensation cycle that will vest in January 2022.
Note 24 - Segment Information
We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.
Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK plays) and South Central Kansas; the Williston Basin in North Dakota; and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and Marketing segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Marketing segment includes Grand Prix, which is currently under construction. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.
Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.
Reportable segment information is shown in the following tables:
(1)
Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver.
(1)
Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver.
(1)
Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver.
The following table shows our consolidated revenues by product and service for the periods presented:
(1)
Represents derivative activities that are not designated as hedging instruments under ASC 815.
The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:
Note 25 - Selected Quarterly Financial Data (Unaudited)
Our results of operations by quarter for the years ended December 31, 2018 and 2017 were as follows:
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(1)
Includes a non-cash pre-tax impairment charge of $210.0 million in the fourth quarter of 2018. See Note 7 - Goodwill.
(2)
Includes a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017. See Note 6 - Property, Plant and Equipment and Intangible Assets.