trgp-10k_20181231.htm

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

The aggregate market value of the common stock held by non-affiliates of the registrant was approximately $10,966.3 million on June 29, 2018, based on $49.49 per share, the closing price of the common stock as reported on the New York Stock Exchange (NYSE) on such date.

As of February 21, 2019, there were 232,143,230 shares of the registrant’s common stock, $0.001 par value, outstanding.

Targa Resources Corp.’s (together with its subsidiaries, including Targa Resources Partners LP (“the Partnership” or “TRP”), “we,” “us,” “our,” “Targa,” “TRC,” or the “Company”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Annual Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Item 1A. Risk Factors” in this Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

As generally used in the energy industry and in this Annual Report, the identified terms have the following meanings:

Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementary midstream energy assets.

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.

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.

Since the founding of our predecessor company in 2003, and since 2010, the year of our initial public offering, 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 and North Dakota, as well as crude oil gathering and terminal assets in North Dakota and West Texas.

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 have invested approximately $8.3 billion in growth capital expenditures since 2010, including approximately $3.2 billion in 2018. These expansion investments are distributed across our businesses, with 53% to Gathering and Processing and 47% related to Logistics and Marketing. 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.

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:

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

In April 2018, the Partnership issued $1.0 billion aggregate principal amount of 5⅞% senior notes due 2026 (the “5⅞% Senior Notes due 2026”). The Partnership used the net proceeds of $991.9 million after costs from this offering to repay borrowings under its credit facilities and for general partnership purposes.

During the year ended December 31, 2018, we sold 6,315,711 shares of common stock under the equity distribution agreement under the universal shelf registration statement filed in May 2016 (the “December 2016 EDA”), resulting in net proceeds of $318.6 million, and 7,527,902 shares of common stock under the equity distribution agreement under the universal shelf registration statement filed in May 2016 (the “May 2017 EDA”), receiving net proceeds of $364.9 million. In September 2018, we terminated the December 2016 EDA.

On September 20, 2018, we entered into an equity distribution agreement under the universal shelf registration a statement filed in May 2016 (the “September 2018 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregate amount of $750.0 million of our common stock. For the year ended December 31, 2018, no shares of common stock were issued under the September 2018 EDA.

On October 29, 2018, Standard & Poor’s Corporation (“S&P”) raised Targa’s corporate credit rating and its 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 the Partnership’s 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.

may include repaying borrowings under its credit facilities or other indebtedness, funding growth investments and acquisitions, and working capital.

In June 2018, we entered into an agreement to amend the TRC Revolver to extend the maturity date from February 2020 to June 2023. The available commitments of $670.0 million and our ability to request additional commitments of $200.0 million remained unchanged. The TRC Revolver continues to bear interest costs that are dependent on the ratio of non-Partnership consolidated funded indebtedness to consolidated Adjusted EBITDA, as defined in the TRC Revolver, and the covenants remained substantially the same.

In June 2018, the Partnership 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. The Partnership’s ability to request additional commitments of $500.0 million remained unchanged.

The TRP Revolver bears interest, at the Partnership’s 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s 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 TRP achieve certain credit ratings.

The Partnership is 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s non-credit-enhanced senior unsecured long-term debt ratings. The TRP Revolver’s covenants remained substantially the same.

On February 17, 2016, TRC completed its acquisition of all of the outstanding common units of Targa Resources Partners LP (NYSE: NGLS), pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement,” and such transaction, the “TRC/TRP Merger”). We issued 104,525,775 shares of common stock in exchange for all of the outstanding common units of the Partnership that we previously did not own. As a result of the completion of the TRC/TRP Merger, the TRP common units are no longer publicly traded. The Partnership’s 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 preferred limited partner interests in TRP and continue to trade on the New York Stock Exchange (“NYSE”) under the symbol “NGLS PRA.” TRC also maintains a 2% general partner interest in the Partnership.

On October 19, 2016, TRP executed the Third Amended and Restated Agreement of Limited Partnership (the “Third A&R Partnership Agreement”), effective as of December 1, 2016. In connection with the Third A&R Partnership Agreement, TRP issued to Targa Resources GP LLC (the “General Partner”): (i) 20,380,286 common units and 424,590 General Partner units in exchange for the cancellation of the incentive distribution rights (“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.”

The diagram below shows our corporate structure as of February 21, 2019, which reflects the effect of the TRC/TRP Merger:

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.

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.

We have a demonstrated track record of completing organic growth and third-party acquisitions. Since our initial public offering in 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.

We believe that we are well positioned to execute our business strategies due to the following competitive strengths:

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.

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.

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.

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.

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.

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 company was formed in 2005, 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.

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.

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. Risk Factors.”

Our operations are reported in two segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

Our Gathering and Processing segment consists of gathering, compressing, dehydrating, treating, conditioning, processing, and marketing natural gas and gathering crude oil. The gathering of natural gas consists of aggregating natural gas produced from various wells through varying diameter gathering lines to processing plants. Natural gas has a widely varying composition depending on the field, the formation and the reservoir from which it is produced. The processing of natural gas consists of the extraction of imbedded NGLs and the removal of water vapor and other contaminants to form (i) a stream of marketable natural gas, commonly referred to as residue gas, and (ii) a stream of mixed NGLs. Once processed, the residue gas is transported to markets through pipelines that are owned by third parties. End-users of residue gas include large commercial and industrial customers, as well as natural gas and electric utilities serving individual consumers. We sell our residue gas either directly to such end-users or to marketers into intrastate or interstate pipelines, which are typically located in close proximity or with ready access to our facilities. The gathering of crude oil consists of aggregating crude oil production primarily through gathering pipeline systems, which deliver crude oil to a combination of other pipelines, rail and truck.

We continually seek new supplies of natural gas and crude oil, both to offset the natural decline in production from connected wells and to increase throughput volumes. We obtain additional natural gas and crude oil supply in our operating areas by contracting for production from new wells or by capturing existing production currently gathered by others. Competition for new natural gas and crude oil supplies is based primarily on location of assets, commercial terms including pre-existing contracts, service levels and access to markets. The commercial terms of natural gas gathering and processing arrangements and crude oil gathering are driven, in part, by capital costs, which are impacted by the proximity of systems to the supply source and by operating costs, which are impacted by operational efficiencies, facility design and economies of scale.

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) 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.

The natural gas processed in this segment is supplied through our gathering systems which, in aggregate, consist of approximately 28,500 miles of natural gas pipelines and include 42 owned and operated processing plants. During 2018, we processed an average of 3,937.4 MMcf/d of natural gas and produced an average of 415.7 MBbl/d of NGLs. In addition to our natural gas gathering and processing, our Badlands operations include a crude oil gathering system and four terminals with crude oil operational storage capacity of 125 MBbl, and our Permian operations include a crude oil gathering system and two terminals with crude oil operational storage capacity of 20 MBbl. During 2018, we gathered an average of 211.7 MBbl/d of crude oil.

The Gathering and Processing segment’s operations consist of Permian Midland, Permian Delaware, SouthTX, North Texas, SouthOK, WestOK, Coastal and Badlands each as described below:

The WestTX gathering system has approximately 4,700 miles of natural gas gathering pipelines located across nine counties within the Permian Basin in West Texas. We have an approximate 72.8% ownership in the WestTX system. Pioneer, the largest active driller in the Spraberry and Wolfberry Trends and a major producer in the Permian Basin, owns the remaining interest in the WestTX system.

The WestTX system includes eight separate plants: the Consolidator, Driver, Midkiff, Benedum, Edward, Buffalo, Joyce and Johnson processing facilities. The WestTX processing operations currently have an aggregate processing nameplate capacity of 1,275 MMcf/d. In addition, two previously announced 250 MMcf/d plants are expected to begin operations in the second quarter of 2019.

SAOU includes approximately 1,800 miles of pipelines in the Permian Basin that gather natural gas for delivery to the Mertzon, Sterling, Tarzan and High Plains processing plants. SAOU’s processing facilities are refrigerated cryogenic processing plants with an aggregate processing capacity of approximately 354 MMcf/d. SAOU has gathering lines that extend across nine counties.

The Permian Delaware system consists of two primary systems, Sand Hills and Versado.

Sand Hills includes approximately 2,200 miles of natural gas gathering pipelines within the Delaware Basin for delivery typically into the Sand Hills, Loving, Oahu and Wildcat processing plants. The processing facilities are refrigerated cryogenic processing plants with an aggregate capacity of 545 MMcf/d. Two additional plants in the Delaware Basin are currently being developed: 1) the 250 MMcf/d Falcon Plant, which is expected to be completed in the fourth quarter of 2019, and 2) the 250 MMcf/d Peregrine Plant, which is expected to be completed in the second quarter of 2020.

Versado consists of the Saunders, Eunice and Monument gas processing plants and related gathering systems in Southeastern New Mexico and in West Texas. Versado includes approximately 3,500 miles of natural gas gathering pipelines. The Saunders, Eunice and Monument refrigerated cryogenic processing plants have aggregate processing capacity of 255 MMcf/d. Gathered volumes from the Versado area may also be processed at the Wildcat or Oahu processing facilities.

The Permian Midland and Permian Delaware systems are interconnected and volumes may flow from one system to the other.

The South Texas system contains approximately 900 miles of high-pressure and low-pressure gathering and transmission pipelines and three natural gas processing plants in the Eagle Ford Shale. The South Texas system processes natural gas through the Silver Oak I, Silver Oak II and Raptor gas processing plants. The Silver Oak I and II Plants (the “Silver Oak Plants”) are each 200 MMcf/d cryogenic plants and located in Bee County, Texas. The Raptor Plant is a 260 MMcf/d cryogenic plant located in LaSalle County, Texas.

We participate in three joint ventures in South Texas. Our ownership interests in two of the joint ventures consist of our 75% share in T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and our 50% share in T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”). A subsidiary of Southcross Holdings, L.P. (“Southcross”) owns the remaining interests. T2 LaSalle owns approximately 60 miles of high-pressure gathering pipeline and T2 Eagle Ford owns approximately 120 miles of high-pressure gathering pipelines. Together, these two pipelines gather and transport gas to the Silver Oak Plants. The T2 Eagle Ford joint venture also owns the residue gas delivery pipelines downstream of the Silver Oak Plants. Effective December 31, 2018, we were named as operator for each of T2 LaSalle and T2 Eagle Ford.

Our third joint venture in South Texas is with Sanchez Midstream. We own a 50% interest in the Carnero Joint Venture and Sanchez Midstream owns the remaining 50% interest. Carnero owns the Silver Oak II Plant, the Raptor Plant and approximately 45 miles of high-pressure transmission pipeline located in La Salle, Dimmitt and Webb Counties, Texas which connects Sanchez Energy’s Catarina Ranch gathering system and Comanche Ranch acreage to the Raptor Plant. We operate the Carnero gas gathering and processing facilities.

North Texas includes two interconnected gathering systems in the Fort Worth Basin, Chico and Shackelford, and includes gas from the Barnett Shale and Marble Falls plays. The systems consist of approximately 4,700 miles of pipelines gathering wellhead natural gas.

The Chico gathering system gathers natural gas for the Chico and Longhorn plants. The Chico Plant has an aggregate processing capacity of 265 MMcf/d and an integrated fractionation capacity of 15 MBbl/d. The Longhorn Plant has processing capacity of 200 MMcf/d. The Shackelford gathering system gathers wellhead natural gas largely for the Shackelford Plant. Natural gas gathered from the northern and eastern portions of the Shackelford gathering system is typically transported to the Chico Plant for processing. The Shackelford Plant has processing capacity of 13 MMcf/d.

The SouthOK gathering system is located in the Ardmore and Anadarko Basins and includes the Golden Trend, SCOOP, and Woodford Shale areas of southern Oklahoma. The gathering system has approximately 2,200 miles of pipelines.

The SouthOK system includes six separate operational processing plants with a total nameplate capacity of 710 MMcf/d, including: the Coalgate, Stonewall, Hickory Hills and Tupelo facilities, which are owned by our Centrahoma Joint Venture, and our wholly-owned Velma and Velma V-60 plants. We have a 60% ownership interest in Centrahoma. The remaining 40% ownership interest in Centrahoma is held by MPLX.

The WestOK gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin and includes the Woodford shale and the STACK. The gathering system expands into 13 counties with approximately 6,600 miles of natural gas gathering pipelines.

The WestOK system has a total nameplate capacity of 458 MMcf/d with three separate cryogenic natural gas processing plants located at the Waynoka I and II and Chester facilities, and one refrigeration plant at the Chaney Dell facility.

Our Coastal assets, located in and offshore South Louisiana, gather and process natural gas produced from shallow-water central and western Gulf of Mexico natural gas wells and from deep shelf and deep-water Gulf of Mexico production via connections to third-party pipelines or through pipelines owned by us. Coastal consists of approximately 3,295 MMcf/d of natural gas processing capacity, 11 MBbl/d of integrated fractionation capacity, 980 miles of onshore gathering system pipelines, and 170 miles of offshore gathering system pipelines. The processing plants are comprised of five wholly-owned and operated plants (including one idled), one partially owned and operated plant, and two partially owned plants which are not operated by us. Toca, a partially owned, non-operated plant, was shut down in January 2019 and has been excluded from the preceding statistics. Our Coastal plants have access to markets across the U.S. through the interstate natural gas pipelines to which they are interconnected. The industry continues to rationalize gas processing capacity along the western Louisiana Gulf Coast with most of the producer volumes going to more efficient plants such as our Barracuda and Gillis plants.

The Badlands operations are located in the Bakken and Three Forks Shale plays of the Williston Basin in North Dakota and include approximately 480 miles of crude oil gathering pipelines, 40 MBbl of operational crude oil storage capacity at the Johnsons Corner Terminal, 30 MBbl of operational crude oil storage capacity at the Alexander Terminal, 30 MBbl of operational crude oil storage at New Town and 25 MBbl of operational crude oil storage at Stanley. The Badlands assets also include approximately 260 miles of natural gas gathering pipelines and the Little Missouri natural gas processing plant with a current gross processing capacity of approximately 90 MMcf/d. Additionally, the 200 MMcf/d LM4 Plant, in which we own a 50% interest and will operate, is anticipated to be completed in the second quarter of 2019. Hess Midstream Partners LP owns the remaining interest in the LM4 Plant.

In February 2019, we entered into definitive agreements to sell a 45% interest in Badlands to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities. Targa will continue to be the operator of Badlands and will hold majority governance rights.

The following table lists the Gathering and Processing segment’s processing plants and related volumes for the year ended December 31, 2018:

Gross Plant

Gross

Natural Gas

NGL

Processing

Inlet Throughput

Production

Facility

Process

Type (1)

Operated/

Non-Operated

% Owned

Location

Capacity (MMcf/d) (2)

Volume (MMcf/d) (3) (4) (5)

(MBbl/d) (3) (4) (5)

Permian Midland

Consolidator (6)

Cryo

Operated

72.8

Reagan County, TX

150.0

Midkiff (6)

Cryo

Operated

72.8

Reagan County, TX

80.0

Driver (6)

Cryo

Operated

72.8

Midland County, TX

200.0

Benedum (6)

Cryo

Operated

72.8

Upton County, TX

45.0

Edward (6)

Cryo

Operated

72.8

Upton County, TX

200.0

Buffalo (6)

Cryo

Operated

72.8

Martin County, TX

200.0

Joyce (6)

Cryo

Operated

72.8

Upton County, TX

200.0

Johnson (6)

Cryo

Operated

72.8

Midland County, TX

200.0

Mertzon

Cryo

Operated

100.0

Irion County, TX

52.0

Sterling

Cryo

Operated

100.0

Sterling County, TX

92.0

Tarzan

Cryo

Operated

100.0

Martin County, TX

10.0

High Plains

Cryo

Operated

100.0

Midland County, TX

200.0

Area Total

1,629.0

1,141.2

153.4

Permian Delaware

Sand Hills

Cryo

Operated

100.0

Crane County, TX

165.0

Loving

Cryo

Operated

100.0

Loving County, TX

70.0

Wildcat

Cryo

Operated

100.0

Winkler County, TX

250.0

Oahu

Cryo

Operated

100.0

Pecos County, TX

60.0

Saunders (7)

Cryo

Operated

100.0

Lea County, NM

60.0

Eunice (7)

Cryo

Operated

100.0

Lea County, NM

110.0

Monument (7) (16)

Cryo

Operated

100.0

Lea County, NM

85.0

Area Total

800.0

443.9

53.5

SouthTX

Silver Oak I

Cryo

Operated

100.0

Bee County, TX

200.0

Silver Oak II

Cryo

Operated

50.0

Bee County, TX

200.0

Raptor

Cryo

Operated

50.0

La Salle County, TX

260.0

Area Total

660.0

389.6

51.1

North Texas

Chico (8)

Cryo

Operated

100.0

Wise County, TX

265.0

Shackelford

Cryo

Operated

100.0

Shackelford County, TX

13.0

Longhorn

Cryo

Operated

100.0

Wise County, TX

200.0

Area Total

478.0

244.1

28.1

SouthOK (9)

Coalgate

Cryo

Operated

60.0

Coal County, OK

80.0

Stonewall

Cryo

Operated

60.0

Coal County, OK

200.0

Tupelo

Cryo

Operated

60.0

Coal County, OK

120.0

Hickory Hills

Cryo

Operated

60.0

Hughes County, OK

150.0

Velma

Cryo

Operated

100.0

Stephens County, OK

100.0

Velma V-60

Cryo

Operated

100.0

Stephens County, OK

60.0

Area Total

710.0

555.7

54.7

WestOK (9)

Waynoka I

Cryo

Operated

100.0

Woods County, OK

200.0

Waynoka II

Cryo

Operated

100.0

Woods County, OK

200.0

Chaney Dell (10)

Operated

100.0

Major County, OK

30.0

Chester (10)

Cryo

Operated

100.0

Woodward County, OK

28.0

Area Total

458.0

351.6

20.5

Coastal (11)

Gillis (12)

Cryo

Operated

100.0

Calcasieu Parish, LA

180.0

Acadia (10)

Cryo

Operated

100.0

Acadia Parish, LA

80.0

Big Lake (13)

Cryo

Operated

100.0

Calcasieu Parish, LA

180.0

VESCO

Cryo

Operated

76.8

Plaquemines Parish, LA

750.0

Barracuda

Cryo

Operated

100.0

Cameron Parish, LA

190.0

Lowry (13)

Cryo

Operated

100.0

Cameron Parish, LA

265.0

Terrebone

Non-operated

7.9

Terrebonne Parish, LA

950.0

Toca (14)

Cryo/RA

Non-operated

12.6

St. Bernard Parish, LA

1,150.0

Sea Robin

Cryo

Non-operated

0.9

Vermillion Parish, LA

700.0

Area Total

4,445.0

726.2

43.6

Badlands

Little Missouri (15)

Cryo/RA

Operated

100.0

McKenzie County, ND

90.0

85.1

10.8

Segment System Total

9,270.0

3,937.4

415.7

Our Logistics and Marketing segment is also referred to as our Downstream Business. Our Downstream Business includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services described below. The Logistics and Marketing segment includes Grand Prix, as well as our equity interest in GCX, which are both currently under construction. 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. Our fractionation, pipeline transportation, storage and terminaling businesses include approximately 1,100 miles of company-owned pipelines to transport mixed NGLs and specification products.

The Logistics and Marketing segment also transports, distributes and markets NGLs via terminals and transportation assets across the U.S. We own or commercially manage terminal facilities in a number of states, including Texas, Oklahoma, Louisiana, Arizona, Nevada, California, Florida, Alabama, Mississippi, Tennessee, Kentucky and New Jersey. The geographic diversity of our assets provides direct access to many NGL customers as well as markets via trucks, barges, ships, rail cars and open-access regulated NGL pipelines owned by third parties.

Additional description of the Logistics and Marketing segment assets and business activities associated with Fractionation, NGL Storage and Terminaling, Petroleum Logistics, NGL Distribution and Marketing, Wholesale Domestic Marketing, Refinery Services, Commercial Transportation and Natural Gas Marketing follows below.

After being extracted in the field, mixed NGLs are typically transported to a centralized facility for fractionation where the mixed NGLs are separated into discrete NGL products: ethane, ethane-propane mix, propane, normal butane, iso-butane and natural gasoline.

Our NGL fractionation business is under fee-based arrangements. These fees are subject to adjustment for changes in certain fractionation expenses, including energy costs. The operating results of our NGL fractionation business are dependent upon the volume of mixed NGLs fractionated, the level of fractionation fees charged and product gains/losses from fractionation.

We believe that sufficient volumes of mixed NGLs will be available for fractionation in commercially viable quantities for the foreseeable future due to historical increases in NGL production from shale plays and other shale-technology-driven resource plays in areas of the U.S. that include Texas, New Mexico, Oklahoma and the Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from conventional production of NGLs in areas such as the Permian Basin, Mid-Continent, East Texas, South Louisiana and shelf and deep-water Gulf of Mexico. Hydrocarbon dew point specifications implemented by individual natural gas pipelines and the Policy Statement on Provisions Governing Natural Gas Quality and Interchangeability in Interstate Natural Gas Pipeline Company Tariffs enacted in 2006 by the Federal Energy Regulatory Commission (“FERC”) should result in volumes of mixed NGLs being available for fractionation because natural gas requires processing or conditioning to meet pipeline quality specifications. These requirements establish a base volume of mixed NGLs during periods when it might be otherwise uneconomical to process certain sources of natural gas. Furthermore, significant volumes of mixed NGLs are contractually committed to our NGL fractionation facilities.

Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products is also an important competitive factor. This ability is a function of the existence of storage infrastructure and supply and market connectivity necessary to conduct such operations. We believe that the location, scope and capability of our logistics assets, including our transportation and distribution systems, give us access to both substantial sources of mixed NGLs and a large number of end-use markets.

Our fractionation assets include ownership interests in three stand-alone fractionation facilities that are located on the Gulf Coast, two of which we operate, one at Mont Belvieu, Texas and the other at Lake Charles, Louisiana. We have an equity investment in the third fractionation facility, Gulf Coast Fractionators LP (“GCF”), also located at Mont Belvieu. In addition to the three stand-alone facilities in the Logistics Assets segment, we own fractionation assets at Chico, Monument and Gillis in our Gathering and Processing segment.

The five existing fractionation trains at the Mont Belvieu facility with a gross capacity of 493.0 MBbl/d are part of our 88%-owned Cedar Bayou Fractionators. Three additional fractionation trains, which are currently under construction at the Mont Belvieu facility, are not part of CBF. The additional fractionation trains will be fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel. The additional fractionation trains are: (1) the 100 MBbl/d Train 6, which is expected to begin operations in the second quarter 2019, (2) the 110 MBbl/d Train 7, which is expected to begin operations in the first quarter 2020 and (3) the 110 MBbl/d Train 8, which is expected to begin operations in the second quarter 2020.

We also have a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural gasoline, allowing customers to meet stringent environmental standards. The facility has a capacity of 35 MBbl/d and is supported by long-term fee-based contracts that have certain guaranteed volume commitments or provisions for deficiency payments.

The following table details the Logistics and Marketing segment’s fractionation and treating facilities:

In general, our NGL storage assets provide warehousing of mixed NGLs, NGL products and petrochemical products in underground wells, which allows for the injection and withdrawal of such products at various times in order to meet supply and demand cycles. Similarly, our terminaling operations provide the inbound/outbound logistics and warehousing of mixed NGLs, NGL products and petrochemical products in above-ground storage tanks. Our NGL underground storage and terminaling facilities serve single markets, such as propane, as well as multiple products and markets. For example, the Mont Belvieu and Galena Park facilities have extensive pipeline connections for mixed NGL supply and delivery of component NGLs, including Grand Prix once it is operational. In addition, some of our facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to our customers. We provide long and short-term storage and terminaling services and throughput capability to third-party customers for a fee.

Across the Logistics and Marketing segment, we own 34 storage wells at our facilities with a gross storage capacity of approximately 71 MMBbl, and operate 6 non-owned wells, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage.

We operate our storage and terminaling facilities to support our key fractionation facilities at Mont Belvieu and Lake Charles for receipt of mixed NGLs and storage of fractionated NGLs to service the petrochemical, refinery, export and heating customers/markets as well as our wholesale domestic terminals that focus on logistics to service the heating market customer base. Our international export assets include our facilities at both Mont Belvieu and the Galena Park Marine Terminal near Houston, Texas. The facilities have export capacity of approximately 7 MMBbl per month of propane and/or butane with the capability to export international grade low ethane propane. We have the capability to load VLGC vessels, alongside small and medium sized export vessels. We continue to experience demand growth for U.S.-based NGLs (both propane and butane) for export into international markets and have the ability to further enhance our loading capabilities.

The following table details the Logistics and Marketing segment’s NGL storage and terminaling facilities:

Our Petroleum Logistics business owns and operates a storage and terminaling facility in Channelview, Texas. This facility serves the refined petroleum products, crude oil, LPG, and petrochemicals markets. The Channelview storage and terminaling facility’s throughput for the year ended December 31, 2018, was 171.6 MMgal and the gross storage capacity was 0.6 MMBbl. The Channelview Splitter, which is currently in the process of start-up and commissioning, will be part of our Petroleum Logistics business once in service.

We market our own NGL production and also purchase component NGL products from other NGL producers and marketers for resale. Additionally, we also purchase product for resale in our Logistics and Marketing segment, including exports. During the year ended December 31, 2018, our distribution and marketing services business sold an average of 537.9 MBbl/d of NGLs.

We generally purchase mixed NGLs at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these component products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which we earn margins from purchasing and selling NGL products from customers under contract. We also earn margins by purchasing and reselling NGL products in the spot and forward physical markets. To effectively serve our distribution and marketing customers, we contract for and use many of the assets included in our Logistics and Marketing segment.

Our wholesale domestic propane marketing operations primarily sell propane and related logistics services to major multi-state retailers, independent retailers and other end-users. Our propane supply primarily originates from both our refinery/gas supply contracts and our other owned or managed logistics and marketing assets. We sell propane at a fixed posted price or at a market index basis at the time of delivery and in some circumstances, we earn margin on a netback basis.

The wholesale domestic propane marketing business is significantly impacted by seasonal and weather-driven demand, particularly in the winter, which can impact the price and volume of propane sold in the markets we serve.

In our refinery services business, we typically provide NGL balancing services via contractual arrangements with refiners to purchase and/or market propane and to supply butanes. We use our commercial transportation assets (discussed below) and contract for and use the storage, transportation and distribution assets included in our Logistics and Marketing segment to assist refinery customers in managing their NGL product demand and production schedules. This includes both feedstocks consumed in refinery processes and the excess NGLs produced by other refining processes. Under typical netback purchase contracts, we generally retain a portion of the resale price of NGL sales or receive a fixed minimum fee per gallon on products sold. Under netback sales contracts, fees are earned for locating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a minimum fee per gallon.

Key factors impacting the results of our refinery services business include production volumes, prices of propane and butanes, as well as our ability to perform receipt, delivery and transportation services in order to meet refinery demand.

Our NGL transportation and distribution infrastructure includes a wide range of assets supporting both third-party customers and the delivery requirements of our marketing and asset management business. We provide fee-based transportation services to refineries and petrochemical companies throughout the Gulf Coast area. Our assets are also deployed to serve our wholesale domestic distribution terminals, fractionation facilities, underground storage facilities and pipeline injection terminals. These distribution assets provide a variety of ways to transport products to and from our customers.

Our transportation assets, as of December 31, 2018, include approximately 585 railcars that we lease and manage, approximately 136 leased and managed transport tractors and 2 company-owned pressurized NGL barges.

The following table details the Logistics and Marketing segment’s raw NGL, propane and butane terminaling facilities:

We also market natural gas available to us from the Gathering and Processing segment, purchase and resell natural gas in selected U.S. markets and manage the scheduling and logistics for these activities.

Overall, parts of our business are impacted by seasonality. Our downstream marketing business can be significantly impacted by seasonal and weather-driven demand, which can impact the price and volume of product sold in the markets we serve, as well as the level of inventory we hold in order to meet anticipated demand. See further discussion of the extent to which our business is affected by seasonality in “Item 1A. Risk Factors.”

We are subject to all risks inherent in the midstream natural gas, crude oil and petroleum logistics businesses. These risks include, but are not limited to, explosions, fires, mechanical failure, terrorist attacks, product spillage, weather, nature and inadequate maintenance of rights of way and could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or environmental pollution, as well as curtailment or suspension of operations at the affected facility. We maintain, on behalf of ourselves and our subsidiaries, including the Partnership, general public liability, property, boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive given the current insurance market environment.

The occurrence of a significant loss that is not insured, fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our inability to secure these levels and types of insurance in the future could negatively impact our business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates considered commercially reasonable, particularly named windstorm coverage and contingent business interruption coverage for our onshore operations.

We face strong competition in acquiring new natural gas or crude oil supplies. Competition for natural gas and crude oil supplies is primarily based on the location of gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, reliability and access to end-use markets or liquid marketing hubs. Competitors to our gathering and processing operations include other natural gas gatherers and processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and gas producers. Our major competitors for natural gas supplies in our current operating regions include Enterprise, Kinder Morgan, WTG Gas Processing, L.P. (“WTG”), DCP, Enbridge Inc., Enlink Midstream Partners LP, Energy Transfer, ONEOK, J-W Operating Company, Louisiana Intrastate Gas Company L.L.C., Enable and several other pipeline companies. Our competitors for crude oil gathering services in North Dakota include Crestwood Equity Partners LP, Kinder Morgan, Tesoro Corporation, Caliber Midstream Partners, L.P., Bridger Pipeline LLC, Paradigm Energy Partners, LLC and Summit Midstream Partners, LLC. Our competitors may have greater financial resources than we possess.

We also compete for NGL supplies for our NGL pipeline currently under construction. Competition for NGL supplies is primarily based on the location of gathering and processing facilities and their connectivity to NGL pipeline takeaway options, access to end-use markets or liquid marketing hubs, pricing and contractual arrangements, reputation, efficiency, flexibility, and reliability. Competitors to our NGL pipeline include other midstream providers with NGL transportation capabilities, such as major interstate and intrastate pipeline companies, master limited partnerships and midstream natural gas and NGL companies. Our major competitors for NGL supplies in our current operating regions include Energy Transfer, Enterprise, ONEOK, DCP and EPIC Midstream Holdings LP.

Additionally, we face competition for mixed NGLs supplies at our fractionation facilities. Our competitors include large oil, natural gas and petrochemical companies. The fractionators in which we own an interest in the Mont Belvieu region compete for volumes of mixed NGLs with other fractionators also located at Mont Belvieu, Texas. Among the primary competitors are Enterprise, ONEOK and LoneStar NGL LLC. In addition, certain producers fractionate mixed NGLs for their own account in captive facilities. The Mont Belvieu fractionators also compete on a more limited basis with fractionators in Conway, Kansas and a number of decentralized, smaller fractionation facilities in Texas, Louisiana and New Mexico. Our other fractionation facilities compete for mixed NGLs with the fractionators at Mont Belvieu as well as other fractionation facilities located in Louisiana. Our customers who are significant producers of mixed NGLs and NGL products or consumers of NGL products may develop their own fractionation facilities in lieu of using our services. Our primary competitors in providing export services to our customers are Enterprise, Phillips 66 and LoneStar NGL LLC.

We also compete for NGL products to market through our Logistics and Marketing segment. Our competitors include major oil and gas producers who market NGL products for their own account and for others. Additionally, we compete with several other NGL marketing companies, including Enterprise, Energy Transfer, DCP, ONEOK and BP p.l.c.

Regulation of pipeline gathering and transportation services, natural gas, NGL and crude oil sales, and transportation of natural gas, NGLs and crude oil may affect certain aspects of our business and the market for our products and services.

Our natural gas gathering operations are typically subject to ratable take and common purchaser statutes in the states in which we operate. The common purchaser statutes generally require gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates we charge for gathering are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems, including the gas gathering systems that are part of the Badlands and of the Pelican and Seahawk 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, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are now subject to Order No. 704. See “—Regulation of Operations—FERC Market Transparency Rules.”

Our natural gas gathering and processing operations are not presently subject to FERC regulation. However, since May 2009, we have been required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See “—Regulation of Operations—FERC Market Transparency Rules.” There can be no assurance that our processing operations will continue to be exempt from other FERC regulation in the future.

The price at which we buy and sell natural gas, NGLs and crude oil is currently not subject to federal rate regulation and, for the most part, is not subject to state rate regulation. However, with regard to our physical purchases and sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodities Futures Trading Commission (“CFTC”). See “—Regulation of Operations—EP Act of 2005.” Since May 2009, we have been required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See “—Regulation of Operations—FERC Market Transparency Rules.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

We own (in conjunction with Pioneer) and operate the Driver Residue Pipeline, a gas transmission pipeline extending from our Driver processing plant in West Texas just over ten miles to points of interconnection with intrastate and interstate natural gas transmission pipelines. We have obtained a waiver from FERC of the requirements pertaining to the filing of an initial rate for service, the filing of a tariff and compliance with specified accounting and reporting requirements for the Driver Residue Pipeline. As such, the Driver Residue Pipeline is not currently subject to conventional rate regulation; to requirements FERC imposes on “open access” interstate natural gas pipelines; to the obligation to file and maintain a tariff; or to the obligation to conform to certain business practices and to file certain reports. If, however, we receive a bona fide request for firm service on the Driver Residue Pipeline from a third party, FERC would reexamine the waivers it has granted us and would require us to file for authorization to offer “open access” transportation under its regulations, which would impose additional costs upon us.

Targa NGL Pipeline Company LLC (“Targa NGL”) has interstate NGL pipelines that are considered common carrier pipelines subject to regulation by FERC under the Interstate Commerce Act (the “ICA”). More specifically, Targa NGL owns an eight-inch diameter pipeline that runs between Mont Belvieu, Texas, and Galena Park, Texas. The eight-inch pipeline is regulated under the ICA and is part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic and foreign import and export customers.

Additionally, we began operating portions of Grand Prix in 2018, which transports mixed NGLs from the Permian Basin, including points in New Mexico, to intermediate points in Texas. Grand Prix is expected to be fully in service in the third quarter of 2019, with transportation to Mont Belvieu, Texas. On March 1, 2018, Grand Prix submitted its initial tariff establishing initial rates with FERC. On May 1, 2018, Grand Prix acquired an additional segment of pipeline from another party, which had previously obtained and operated such pipeline segment under a temporary waiver. On May 1, 2018, upon acquiring such segment of pipeline, Grand Prix filed to voluntarily terminate the temporary waiver.

Additionally, in 2018, Targa NGL began operating portions of a new pipeline that transports NGLs from Oklahoma to intermediate points in Oklahoma and, beginning in 2019, to Mont Belvieu, Texas. On July 27, 2018, Targa NGL submitted a petition for declaratory order to FERC on a proposed rate structure and terms of service for such new NGL pipeline system. This petition is pending at FERC.

The ICA requires that we maintain tariffs on file with FERC for each of these pipelines described above. 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. Several of these pipelines would qualify for a waiver of filing of FERC tariffs.

Targa NGL also owns a twenty-inch diameter pipeline and twelve-inch diameter pipeline that run between Mont Belvieu, Texas, and Galena Park, Texas and a twelve-inch diameter pipeline that runs between Mont Belvieu, Texas and Lake Charles, Louisiana, each of which transport NGLs and that have qualified for a waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. In 2019, Targa NGL will complete another pipeline for exports at Targa’s Galena Park dock, and this pipeline has also qualified for such a waiver. Additionally, the crude oil pipeline system that is part of the Badlands assets also qualifies for such a waiver. Further, while Targa intended to complete construction of a new pipeline connecting to a certain interstate crude pipeline, it did not occur. In anticipation of this new pipeline, however, Targa Crude Pipeline LLC sought, and on June 27, 2018, received a waiver of applicable FERC regulatory requirements under the ICA for those possible movements on the new pipeline. Targa Crude Pipeline LLC is expected to file a request to terminate the waiver in 2019.

All such waivers are subject to revocation, however, should a particular pipeline’s circumstances change. FERC could, either at the request of other entities or on its own initiative, assert that some or all of these pipelines no longer qualify for a waiver. In the event that FERC were to determine that one more of these pipelines no longer qualified for 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.

Many existing pipelines, including Grand Prix and some of Targa NGL’s pipelines, may utilize the FERC oil pipeline indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index. FERC’s indexing methodology is subject to review every five years. On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating, among other things, that with respect to oil and refined products pipelines subject to FERC jurisdiction, the impacts of the Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 on the costs of FERC-regulated oil and NGL pipelines will be reflected in FERC’s next five-year review of the oil pipeline index, which will generate the index level to be effective July 1, 2021. FERC’s establishment of a just and reasonable rate, including the determination of the appropriate oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of the appropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-year term of index rates, the Revised Policy Statement and tax effects related to the Tax Cuts and Jobs Act of 2017 may impact our revenues associated with any transportation services we may provide pursuant to cost-of-service based rates in the future, including indexed rates.

Our intrastate natural gas pipelines in North Dakota are subject to the various regulations of the State of North Dakota. In addition, various federal agencies within the U.S. Department of the Interior, particularly the federal Bureau of Land Management (“BLM”), Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, as well as the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. Please see “Other State and Local Regulation of Operations” below.

Though our natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, our intrastate pipelines may be subject to certain FERC-imposed reporting requirements depending on the volume of natural gas purchased or sold in a given year. See “—Regulation of Operations—FERC Market Transparency Rules.”

Our intrastate pipelines located in Texas are regulated by the Railroad Commission of Texas (the “RRC”). Our Texas intrastate pipeline, Targa Intrastate Pipeline LLC (“Targa Intrastate”), owns the intrastate pipeline that transports natural gas from its Shackelford processing plant to an interconnect with Atmos Pipeline-Texas that in turn delivers gas to the West Texas Utilities Company’s Paint Creek Power Station. Targa Intrastate also owns a 1.65-mile, ten-inch diameter intrastate pipeline that transports natural gas from a third-party gathering system into the Chico system in Denton County, Texas. Targa Intrastate is a gas utility subject to regulation by the RRC and has a tariff on file with such agency. Our other Texas intrastate pipeline, Targa Gas Pipeline LLC, owns a multi-county intrastate pipeline that transports gas in Crane, Ector, Midland, and Upton Counties, Texas, as well as some lines in North Texas. Targa Gas Pipeline LLC is a gas utility subject to regulation by the RRC and has a tariff on file with such agency.

Our Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC owns an approximately 60-mile intrastate pipeline system that receives all of the natural gas it transports within or at the boundary of the State of Louisiana. Because all such gas ultimately is consumed within Louisiana, and since the pipeline’s rates and terms of service are subject to regulation by the Office of Conservation of the Louisiana Department of Natural Resources (“DNR”), the pipeline qualifies as a Hinshaw pipeline under Section 1(c) of the NGA and thus is exempt from most FERC regulation.

We have an ownership interest of 50% of the capacity in a 50-mile long intrastate natural gas transmission pipeline, which extends from the tailgate of three natural gas processing plants located near Pettus, Texas to interconnections with existing intrastate and interstate natural gas pipelines near Refugio, Texas. The capacity is held by our subsidiary, TPL SouthTex Transmission Company LP (“TPL SouthTex Transmission”), which is entitled to transport natural gas through its capacity on behalf of third parties to both intrastate and interstate markets. Because the jointly owned pipeline system was initially interconnected only with intrastate markets, each of the capacity holders qualified as an “intrastate pipeline” within the meaning of the Natural Gas Policy Act of 1978 (“NGPA”) and therefore is able to provide transportation of natural gas to interstate markets under Section 311 of the NGPA. Under Sections 311 and 601 of the NGPA, an intrastate pipeline may transport natural gas in interstate commerce without becoming subject to FERC regulation as a “natural-gas company” under the NGA. Transportation of natural gas under authority of Section 311 must be filed with FERC and must be shown to be “fair and equitable.” TPL SouthTex Transmission has a Statement of Operating Conditions on file with FERC. TPL SouthTex Transmission has existing rates applicable to NGPA Section 311 service. We have a 10% ownership interest in an intrastate natural gas transmission pipeline crossing portions of Culberson, Loving, Pecos, Reeves and Ward counties in Texas and operated by Agua Blanca, LLC (“Agua Blanca”). Agua Blanca has filed rates for intrastate transportation service on the pipeline with the Railroad Commission of Texas and those rates remain pending. The intrastate rates were filed as the basis for the rates set forth in the Statement of Operating Conditions filed by Agua Blanca with FERC on July 31, 2018, pursuant to Section 311 of the NGPA. The Statement of Operating Conditions and Section 311 rates remain pending before FERC but are effective subject to refund based on any required change in transportation rates on the pipeline. We anticipate that the GCX Project, which is expected to be completed in 2019 and will transport natural gas from the Permian Basin to markets on the Texas Gulf Coast, will be subject to regulation by the RRC and under Section 311 of the NGPA.

We also operate natural gas pipelines that extend from the tailgate of our processing plants to interconnections with both intrastate and interstate natural gas pipelines. Although these “plant tailgate” pipelines may operate at transmission pressure levels and may transport “pipeline quality” natural gas, we believe they are generally exempt from FERC’s jurisdiction under the Natural Gas Act under FERC’s “stub” line exemption. However, Targa Midland Gas Pipeline LLC (“Targa Midland”) operates our Tarzan plant residue gas pipeline, which provides NGPA Section 311 service and falls outside of the “stub” line exemption. On September 13, 2018, FERC accepted Targa Midland’s petition for approval of its Statement of Operating Conditions and rates applicable to NGPA Section 311 service. On August 21, 2018, the Texas Railroad Commission accepted Targa Midland’s intrastate rates.

FERC issued Order No. 849 on July 18, 2018, which became effective September 13, 2018, establishing new regulations that, among other things, require pipelines providing NGPA Section 311 service to file a new rate election for its interstate rates if the intrastate pipeline’s rates on file with the state regulatory agency are reduced to reflect the reduced income tax rates adopted in the Tax Cuts and Jobs Act. If an NGPA Section 311 pipeline’s interstate service rates are established pursuant to a rate filing with FERC, the pipeline is exempt from filing a new rate election if FERC has approved the interstate rates after December 22, 2017, or the pipeline has a pending rate petition at FERC on the effective date of the reduced intrastate rates. Any such petitions may reduce the rates we are permitted to charge for NGPA Section 311 service.

Texas and Louisiana have adopted complaint-based regulation of intrastate natural gas transportation activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to pipeline access and rate discrimination. The rates we charge for intrastate transportation are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

Our intrastate NGL pipelines in Texas transport mixed and purity NGL streams between Targa’s Mont Belvieu and Galena Park, Texas facilities. Additionally, we began operating portions of Grand Prix in 2018, which transports mixed NGLs from the Permian Basin to intermediate points in Texas. We expect Grand Prix to be fully in service in the third quarter of 2019, with transportation to Mont Belvieu, Texas. Further, we operate crude gathering pipelines in the Permian Basin. With respect to intrastate movements, these pipelines are not subject to FERC regulation, but are subject to rate regulation by the RRC. They are also subject to United States Department of Transportation (“DOT”) safety regulations.

Our intrastate NGL pipelines in Louisiana gather mixed NGLs streams that we own from processing plants in Louisiana and deliver such streams to the Gillis and Lake Charles fractionators in Lake Charles, Louisiana, where the mixed NGLs streams are fractionated into various products. We deliver such fractionated petroleum products (ethane, propane, butanes and natural gasoline) out of our fractionator to and from Targa-owned storage, to other third-party facilities and to various third-party pipelines in Louisiana. Additionally, through our 50% ownership interest in Cayenne Pipeline, LLC, we operate the Cayenne pipeline, which transports mixed NGLs from the Venice gas plant in Venice, Louisiana, to an interconnection with a third-party NGL pipeline in Toca, Louisiana. These pipelines are not subject to FERC regulation or rate regulation by the DNR, but are subject to DOT safety regulations. Certain of our Louisiana intrastate NGL pipelines are subject to the Louisiana Public Service Commission 2015 General Order (the “LPSC Order”) Docket No. R-33390. We are currently in the process of registering such lines in accordance with Section 1 of the LPSC Order.

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to approximately $1.27 million per violation per day, adjusted annually for inflation, for violations of the NGA and approximately $1.27 million per violation per day, adjusted annually for inflation, for violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. In 2006, FERC issued Order No. 670 to implement the anti-market manipulation provision of the EP Act of 2005. Order No. 670 does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (Order No. 704), and the quarterly reporting requirement under Order No. 735. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

Beginning in 2007, FERC has issued a number of rules intended to provide for greater marketing transparency in the natural gas industry, including Order Nos. 704, 720, and 735. Under Order No. 704, wholesale buyers and sellers of more than 2.2 Bcf of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.

Under Order No. 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three calendar years, are required to post on a daily basis certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu/d and interstate pipelines are required to post information regarding the provision of no-notice service. In October 2011, Order No. 720 as clarified was vacated by the Court of Appeals for the Fifth Circuit. We take the position that, at this time, all of our entities are exempt from Order No. 720 as currently effective.

Under Order No. 735, intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA are required to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 also extends FERC’s periodic review of the rates charged by the subject pipelines from three years to five years. On rehearing, FERC reaffirmed Order No. 735 with some modifications. As currently written, this rule does not apply to our Hinshaw pipelines.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other midstream natural gas companies with whom we compete.

Our business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including operations, marketing, production, pricing, community right-to-know, protection of the environment, safety, marine traffic and other matters. In addition, 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. For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on our business, see “Risk Factors—Risks Related to Our Business.”

Our operations are subject to numerous federal, tribal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety, or otherwise relating to environmental protection. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our costs to construct, maintain, upgrade and decommission equipment and facilities. We have implemented programs and policies designed to monitor and pursue operation of our pipelines, plants and other facilities in a manner consistent with existing environmental laws and regulations. The trend in environmental and worker health and safety regulation is to typically place more restrictions and limitations on activities that may adversely affect the environment or expose workers to injury and thus, any changes in environmental or worker safety laws and regulations or reinterpretation of enforcement policies that may arise in the future and result in more stringent and costly waste management or disposal, pollution control, remediation or perceived worker health and safety-related requirements could have a material adverse effect on our operations and financial position. We may not have insurance or be fully covered by insurance against all environmental and occupational health and safety risks, and we may be unable to pass on such increased compliance costs to our customers. We review regulatory and environmental issues as they pertain to us and we consider regulatory and environmental issues as part of our general risk management approach. See Risk Factor “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” under Item 1A of this Form 10-K for further discussion on environmental compliance matters. See “Item 3. Legal Proceedings” for a discussion of certain recent or pending proceedings related to environmental matters.

Historically, our environmental and worker safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not become material in the future. The following is a summary of the more significant existing environmental and worker health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and comparable state laws impose joint and several, strict liability on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Liability of these “responsible persons” under CERCLA may include the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from these responsible persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims under CERCLA for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. We generate materials in the course of our operations that are regulated as “hazardous substances” under CERCLA or similar state statutes and, as a result, may be jointly and severally liable under CERCLA or similar state statutes for all or part of the costs required to clean up releases of hazardous substance into the environment.

We also generate solid wastes, including hazardous wastes that are subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes additional stringent requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations, we generate petroleum product wastes and ordinary industrial wastes that are regulated as hazardous wastes. Although certain materials generated in the exploration, development or production of crude oil and natural gas are excluded from RCRA’s hazardous waste regulations, there have been efforts from time to time to remove this exclusion. For example, in late 2016, a consent decree was issued by a federal court resolving the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes. Under the consent decree, the EPA is required to propose a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes by March 15, 2019 or sign a determination that revision of the regulations is unnecessary. Any rulemaking proposed by the agency must be finalized by July 15, 2021. Any future changes in law or regulation that result in these wastes, including wastes currently generated during our or our customers’ operations, being designated as “hazardous wastes” and therefore subject to more rigorous and costly disposal requirements, could have a material adverse effect on our capital expenditures and operating expenses and, with respect to such adverse effects on our customers, could reduce the demand for our services.

We currently own or lease, and have in the past owned or leased, properties that for many years have been used for midstream natural gas, NGL and crude oil activities and refined petroleum product and crude oil storage and terminaling activities. Hydrocarbons or other substances and wastes may have been released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons or other substances and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and release of hydrocarbons or other substances and wastes was not under our control. These properties and any hydrocarbons, substances and wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination, the costs of which activities could have a material adverse effect on our business and results of operations.

The federal Clean Air Act (“CAA”) and comparable state laws and regulations restrict the emission of air pollutants from many sources, including processing plants and compressor stations, and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay, restrict or cancel the development of oil and natural gas related projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of the public health and welfare. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” “unclassifiable” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 National Ambient Air Quality Standards (“NAAQS”) for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs. Compliance with these or other air emissions-related regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines that could delay or halt the development of projects, and significantly increase our capital expenditures and operating costs, any of which could have a material adverse effect on our business.

The EPA has determined that greenhouse gas (“GHG”) emissions endanger public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under the CAA related to GHG emissions. See Risk Factor “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” under Item 1A of this Form 10-K for further discussion on climate change and regulation of GHG emissions.

The Federal Water Pollution Control Act (“Clean Water Act” or “CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities and such permits may require us to monitor and sample the storm water runoff. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The CWA and analogous state laws also may impose civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits, including as a result of spills and other non-authorized discharges.

In 2015, the EPA and the U.S. Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States, including wetlands. Beginning in the first quarter of 2017, the EPA and the Corps agreed to reconsider the 2015 rule and, thereafter, the agencies have (i) published a proposed rule in July 2017 to rescind the 2015 rule and recodify the regulatory text that governed waters of the United States prior to promulgation of the 2015 rule, (ii) published a proposed rule in November 2017 and a final rule in February 2018 adding a February 6, 2020 applicability date to the 2015 rule, and (iii) announced a proposed rule on December 11, 2018 re-defining the Clean Water Act’s jurisdiction over waters of the United States for which the agencies will seek public comment. The 2015 and February 2018 final rules are being challenged by various parties in federal district court and implementation of the 2015 rule has been enjoined in twenty-eight states pending resolution of the various federal district court challenges. As a result of these legal developments, future implementation of the 2015 rule or a revised rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities.

The Federal Oil Pollution Act of 1990 (“OPA”) which amends the CWA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of onshore facilities, such as our plants and our pipelines. Under the OPA, owners and operators of facilities that handle, store, or transport oil are required to develop and implement oil spill response plans, and establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible.

Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The process is typically regulated by state oil and gas commissions, but several federal agencies, including the EPA and the BLM have asserted regulatory authority over aspects of the process. Also, Congress has considered, and some states and local governments have adopted legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. While we do not conduct hydraulic fracturing, if new or more stringent federal, state, or local legal restrictions or prohibitions relating to the hydraulic fracturing process are adopted in areas where our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could reduce demand for our gathering, processing and fractionation services. See Risk Factor “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” under Item 1A of this Form 10-K for further discussion on hydraulic fracturing.

The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of our facilities or projects under development may be located in areas that are designated as habitat for endangered or threatened species. If endangered species are located in areas of the underlying properties where we plan to conduct development activities, such work could be restricted, delayed or prohibited or expensive mitigation may be required. Similar protections are offered to migrating birds under the federal Migratory Bird Treaty Act. Moreover, as a result of one or more settlements approved by the federal government, the U.S. Fish and Wildlife Service (“FWS”) must make determinations within specified timeframes on the listing of numerous species as endangered or threatened under the ESA. The designation of previously unprotected species as threatened or endangered in areas where we or our customers operate or plan to develop a project could cause us or our customers to incur increased costs arising from species protection measures and could result in restrictions, delays or prohibitions in our customers’ performance of operations, which could reduce demand for our services. Certain of our operations occur within areas of American Burying Beetle habitat.

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the federal Occupational Safety and Health Administration’s (“OSHA”) hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The regulations apply to any process that (1) involves a listed chemical in a quantity at or above the threshold quantity specified in the regulation for that chemical, or (2) involves certain flammable gases or flammable liquids present on site in one location in a quantity of 10,000 pounds or more. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have implemented an internal program of inspection designed to monitor and pursue operations in a manner consistent with worker safety requirements.

Many of our natural gas, NGL and crude pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency under the DOT (or state analogs), under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas, crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing, among other things, pipeline design, maximum operating pressures, pipeline patrols and leak surveys, public awareness, operation and maintenance procedures, operator qualification, minimum depth requirements and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulations 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. In the past, we have not incurred material costs in connection with complying with these NGPSA and HLPSA requirements; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our results of operations or financial position.

Legislation in recent years has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which became law in January 2012, amended the NGPSA and HLPSA by increasing the penalties for safety violations, establishing additional safety requirements for newly constructed pipelines and requiring studies of safety issues that could result in the adoption of new regulatory requirements for existing pipelines. In June 2016, President Obama signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”), further amending the NGPSA and HLPSA, extending PHMSA’s statutory mandate through 2019 and, among other things, required PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities. The 2016 Pipeline Safety Act also empowers 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 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property or the environment.

We, or the entities in which we own an interest, inspect our pipelines regularly in a manner consistent with state and federal maintenance requirements. Nonetheless, the adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on us. 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 operations or financial position.

In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. Texas, Louisiana, Oklahoma, and New Mexico, for example, have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting natural gas, NGLs and crude oil. North Dakota has similarly implemented regulatory programs applicable to intrastate natural gas pipelines. We currently estimate an annual average cost of $2.6 million for the years 2019 through 2021 to perform necessary integrity management program testing on our pipelines required by existing PHMSA and state regulations. This estimate does not include the costs, if any, of any repair, remediation, or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our financial condition or results of operations.

See Risk Factors “We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs” and “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” under Item 1A of this Form 10-K for further discussion on pipeline safety standards, including integrity management requirements.

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights of way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors. We and our predecessors have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, rights of way, permit, lease or license, and we believe that we have satisfactory title to all of our material leases, easements, rights of way, permits, leases and licenses.

Through a wholly-owned subsidiary of ours, we employ approximately 2,460 people who primarily support our operations. None of those employees are covered by collective bargaining agreements. We consider our employee relations to be good.

See “Segment Information” included under Note 27 of the “Consolidated Financial Statements” for a presentation of financial results by reportable segment and see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations– By Reportable Segment” for a discussion of our financial results by segment.

We make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website, http://www.targaresources.com, as soon as reasonably practicable after they are filed with the SEC. Our press releases and recent analyst presentations are also available on our website. The SEC also maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC.

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 the Partnership’s 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 the Partnership’s Securitization Facility. In addition, we had (i) $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, and (ii) $435.0 million of borrowings outstanding and $235.0 million of additional borrowing capacity available under the TRC Revolver. For the years ended December 31, 2018, 2017 and 2016, our consolidated interest expense, net was $185.8 million, $233.7 million and $254.2 million.

In January 2019, the Partnership 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 the Partnership’s 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.

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:

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 dividends. 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 and TRC Revolver allow us to request increases in commitments up to an additional $500 million and $200 million, respectively. 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 and may cause the market price of our common stock to decline.

We have significant exposure to increases in interest rates. As of December 31, 2018, our total indebtedness was $6,692.6 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 $1,415.0 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 $14.2 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.

Additionally, like all equity investments, an investment in our equity securities is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments. Reduced demand for our common stock resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common stock to decline.

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, including to pay dividends to our stockholders.

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:

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 the Partnership’s 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:

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.”

Factors such as reserves established by our board of directors for our estimated general and administrative expenses as well as other operating expenses, reserves to satisfy our debt service requirements, if any, and reserves for future dividends by us may affect the dividends we make to our stockholders. The actual amount of cash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control.

Because we may distribute a substantial amount of our cash flow, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. If we issue additional shares of common or preferred stock or we incur debt, the payment of dividends on those additional shares or interest on that debt could increase the risk that we will be unable to maintain or increase our cash dividend levels.

If dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.

Dividends to our common stockholders are not cumulative. Consequently, if dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.

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 pay cash dividends to our stockholders.

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 pay dividends to stockholders. 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 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 dividends will be limited.

Any acquisition or growth project involves potential risks, including, among other things:

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 to pay cash dividends to our stockholders.

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 we lose any of our named executive officers, our business may be adversely affected.

Our success is dependent upon the efforts of the named executive officers. Our named executive officers are responsible for executing our business strategies. There is substantial competition for qualified personnel in the midstream natural gas industry. We may not be able to retain our existing named executive officers or fill new positions or vacancies created by expansion or turnover. We have not entered into employment agreements with any of our named executive officers. In addition, we do not maintain “key man” life insurance on the lives of any of our named executive officers. A loss of one or more of our named executive officers 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.

The duties of our officers and directors may conflict with those owed to the Partnership.

Substantially all of our officers and all the members of our board of directors are officers and/or directors of the general partner of the Partnership and, as a result, have separate duties that govern their management of the Partnership’s business. These officers and directors may encounter situations in which their obligations to us, on the one hand, and the Partnership, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our stockholders. For a discussion of our officers and directors that will serve in the same capacity for the general partner and the amount of time we expect them to devote to our business, please read “Management.”

The Preferred Shares give the holders thereof liquidation and distribution preferences, certain rights relating to our business and management, and the ability to convert such shares into our common stock, potentially causing dilution to our common stockholders.

In March 2016, we issued 965,100 Preferred Shares, which rank senior to the common stock with respect to distribution rights and rights upon liquidation. Subject to certain exceptions, so long as any Preferred Shares remain outstanding, we may not declare any dividend or distribution on our common stock unless all accumulated and unpaid dividends have been declared and paid on the Preferred Shares. In the event of our liquidation, winding-up or dissolution, the holders of the Preferred Shares would have the right to receive proceeds from any such transaction before the holders of the common stock. The payment of the liquidation preference could result in common stockholders not receiving any consideration if we were to liquidate, dissolve or wind up, either voluntarily or involuntarily. Additionally, the existence of the liquidation preference may reduce the value of the common stock, make it harder for us to sell shares of common stock in offerings in the future, or prevent or delay a change of control.

The Certificate of Designations governing the Preferred Shares provides the holders of the Preferred Shares with the right to vote, under certain conditions, on an as-converted basis with our common stockholders on matters submitted to a stockholder vote. The holders of the Preferred Shares do not currently have such right to vote. Also, so long as any Preferred Shares are outstanding, subject to certain exceptions, the affirmative vote or consent of the holders of at least a majority of the outstanding Preferred Shares, voting together as a separate class, will be necessary for effecting or validating, among other things: (i) any issuance of stock senior to the Preferred Shares, (ii) any issuance or increase by any of our consolidated subsidiaries of any issued or authorized amount of, any specific class or series of securities, (iii) any issuance by us of parity stock, subject to certain exceptions and (iv) any incurrence of indebtedness by us and our consolidated subsidiaries for borrowed monies, other than under our existing credit agreement and the Partnership’s existing credit agreement (or replacement commercial bank credit facilities) in an aggregate amount up to $2.75 billion, or indebtedness that complies with a specified fixed charge coverage ratio. These restrictions may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Furthermore, the conversion of the Preferred Shares into common stock twelve years after the issuance of the Preferred Shares, pursuant to the terms of the Certificate of Designations, may cause substantial dilution to holders of the common stock. Because our Board of Directors is entitled to designate the powers and preferences of preferred stock without a vote of our shareholders, subject to NYSE rules and regulations, our shareholders will have no control over what designations and preferences our future preferred stock, if any, will have.

The tax treatment of the Partnership depends on its status as a partnership for U.S. federal income tax purposes as well as it not being subject to a material amount of entity-level taxation by individual states. If, upon an audit of the Partnership, the Internal Revenue Service (“IRS”) were to treat the Partnership as a corporation for U.S. federal income tax purposes now or with respect to a prior tax period, or the Partnership becomes subject to a material amount of entity-level taxation for state tax purposes, then its cash available for distribution to us would be substantially reduced.

A publicly traded partnership such as the Partnership may be treated as a corporation for U.S. federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on the Partnership’s current operations and current Treasury Regulations, we believe that the Partnership satisfies 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 the Partnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Partnership to taxation as an entity. The Partnership has not requested, and does not plan to request, a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes.

If the Partnership were treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on its taxable income at the corporate tax rate, which is 21% for tax years beginning after December 31, 2017, and would likely pay state income tax at varying rates. Distributions from the Partnership would generally be taxed again as corporate distributions and no income, gains, losses or deductions would flow through to us. If such tax were imposed upon the Partnership as a corporation now or with respect to a prior tax period, its cash available for distribution would be substantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to us and could cause a substantial reduction in the value of our shares.

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, the Partnership is subject to the Texas franchise tax at a maximum effective rate of 0.75% of its gross income apportioned to Texas in the prior year. Imposition of any similar tax on the Partnership by additional states would reduce the cash available for distribution to us.

The tax treatment of publicly traded partnerships or our investment in the Partnership 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 the Partnership, or an investment in the Partnership, 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 the Partnership relies for its 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 the Partnership’s 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 the Partnership 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 our shares.

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:

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:

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 decadesprior 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.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We or our stockholders may sell shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. As of December 31, 2018, we had 231,790,530 outstanding shares of common stock. We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including provisions which require:

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

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.

The information required for this item is provided in Note 20 – 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 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our common stock is listed on the NYSE under the symbol “TRGP.” As of December 31, 2018, there were approximately 228 stockholders of record of our common stock. This number does not include stockholders whose shares are held in trust by other entities. The actual number of stockholders is greater than the number of holders of record. As of February 21, 2019, there were 232,143,230 shares of common stock outstanding.

The graph below compares the cumulative return to holders of Targa Resources Corp.'s common stock, the NYSE Composite Index (the “NYSE Index”) and the Alerian MLP Index (the “MLP Index”). The performance graph was prepared based on the following assumptions: (i) $100 was invested in our common stock at $24.70 per share (the closing market price at the end of our first trading day), in the NYSE Index, and the MLP Index on December 7, 2010 (our first day of trading) and (ii) dividends were reinvested on the relevant payment dates. The stock price performance included in this graph is historical and not necessarily indicative of future stock price performance.

Pursuant to Instruction 7 to Item 201(e) of Regulation S-K, the above stock performance graph and related information is being furnished and is not being filed with the SEC, and as such shall not be deemed to be incorporated by reference into any filing that incorporates this Annual Report by reference.

We intend to pay to our stockholders, on a quarterly basis, dividends funded primarily by the cash that we receive from our operations, less reserves for expenses, future dividends and other uses of cash, including:

The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors, in consultation with management, deems relevant. Further, the Partnership’s debt agreements and obligations to its holders of Preferred Units (“Preferred Unitholders”) may restrict or prohibit the payment of distributions to us if the Partnership is in default, threat of default, or arrears. If the Partnership cannot make distributions to us, we may be unable to pay dividends on our common stock. In addition, so long as any Preferred Shares are outstanding, certain limitations on our ability to declare dividends on our common stock exist.

Our dividend policy takes into account the possibility of establishing cash reserves in some quarterly periods that we may use to pay cash dividends in other quarterly periods, thereby enabling us to maintain more consistent cash dividend levels even if our business experiences fluctuations in cash from operations due to seasonal and cyclical factors. Our dividend policy also allows us to maintain reserves to provide funding for growth opportunities.

Dividends on our Preferred Shares are cumulative from the last day of the most recent fiscal quarter, and are payable quarterly in arrears on the 45th day after the end of each fiscal quarter when, as and if declared by our board of directors. Dividends on the Preferred Shares are paid out of funds legally available for payment, in an amount equal to an annual rate of 9.5% ($95.00 per share annualized) of $1,000 per Preferred Share, subject to certain adjustments (the “Liquidation Preference”). If we fail to pay in full to the holders of the Preferred Shares (the “Holders”) the required cash dividend for a fiscal quarter, then (i) the amount of such shortfall will continue to be owed by us to the Holders and will accumulate until paid in full in cash, (ii) the Liquidation Preference will be deemed increased by such amount until paid in full in cash and (iii) contemporaneous with increasing the Liquidation Preference by such shortfall, we will grant and deliver to the Holders a corresponding number of additional warrants having the same terms (including exercise price) as the warrants issued on the date of the closing of the transactions pursuant to which the Preferred Shares were issued.

Subject to certain exceptions, so long as any Preferred Shares remain outstanding, no dividend or distribution will be declared or paid on, and no redemption or repurchase will be agreed to or consummated of, stock on a parity with the Preferred Shares or our common stock, unless all accumulated and unpaid dividends for all preceding full fiscal quarters (including the fiscal quarter in which such accumulated and unpaid dividends first arose) have been declared and paid.

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 the 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 a discussion of restrictions on our and our subsidiaries’ ability to pay dividends or make distributions, please see Note 10 – Debt Obligations in our Consolidated Financial Statements beginning on page F-1 in this Form 10-K for more information.

There were no sales of unregistered equity securities for the year ended December 31, 2018.

The following table presents selected historical consolidated financial and operating data of Targa Resources Corp. 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.

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.” Also, the Partnership files a separate Annual Report on Form 10-K with the SEC.

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.

Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. We own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets.

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.

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:

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

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.

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.

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. Quantitative and Qualitative Disclosures About Market Risk–Commodity Price Risk.”

Variable costs such as fuel, utilities, power, service and repairs can impact our results. The fuel and power costs are pass-through elements in many of our logistics contracts, which mitigates their impact on our results. Continued expansion of existing assets will also give rise to additional operating expenses, which will affect our results. The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company, and an indirect wholly-owned subsidiary of ours.

We perform centralized corporate functions such as legal, accounting, treasury, insurance, risk management, health, safety, environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Other than our direct costs of being a separate public reporting company, these costs are reimbursed by the Partnership. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

We expect the midstream energy business environment to continue to be affected by the following key trends: demand for our products and services, commodity prices, volatile capital markets, competition and increased regulation. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related activity levels from our customers. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Producers generally focus their drilling activity on certain basins depending on commodity price fundamentals. As a result, our asset systems are predominately located in some of the most economic basins in the United States. Accordingly, increased producer activity will drive demand for our midstream services and may result in incremental infrastructure growth capital expenditures. Demand in our Downstream Business for fractionation and other fee-based services is largely correlated with producer activity levels. Demand for our international export, storage and terminaling services has remained relatively constant during recent commodity price volatility, as demand for these services is based on a number of domestic and international factors.

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. In addition, the volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems. Global oil and natural gas commodity prices, particularly crude oil, have declined substantially as compared to mid-2014 and remain volatile. See “Item 1A. Risk Factors – Our cash flow is affected by supply and demand for natural gas and NGL products 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 operating income generally improves in an environment of higher natural gas, NGL and condensate prices, and where the spread between NGL prices and natural gas prices widens primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing and the supply of and market demand for natural gas, NGLs and condensate. Pricing and supply are beyond our control and have been volatile. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. Due to the volatility in commodity prices, we are uncertain of what pricing and market demand for oil, condensate, NGLs and natural gas will be throughout 2019, and, as a result, demand for the services that we provide may decrease. Across our operations and particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. The significant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

We continuously consider and enter into discussions regarding potential acquisitions and growth projects and identify appropriate private and public capital sources for funding potential acquisitions and growth projects. Any limitations on our access to capital may 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 may be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. 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.

Additional regulation in various areas has the potential to materially impact our operations and financial condition. For example, increased regulation of hydraulic fracturing used by producers and increased GHG emission regulations may cause reductions in supplies of natural gas, NGLs and crude oil from producers. Please read “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” and “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” under Item 1A of this Annual Report. Similarly, the forthcoming rules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less predictability in our results of operations.

The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based contracts. Our growing fee-related capital expenditures for pipelines, expansion of our downstream facilities, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for services such as fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in unit fees due to market dynamics such as available commodity throughput does affect profitability.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: gross margin, operating margin, Adjusted EBITDA and distributable cash flow.

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and in the future through Grand Prix, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period.

Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.

We define gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas, condensate, crude oil and NGLs and fees related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases.

The gross margin impacts of our equity volumes hedge settlements are reported in Other.

We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of our financial statements, including investors and commercial banks, to assess:

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income (loss) attributable to TRC. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

We define Adjusted EBITDA as net income (loss) attributable to TRC before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the Adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable to TRC. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

We define distributable cash flow as Adjusted EBITDA less distributions to TRP preferred limited partners, the Splitter Agreement adjustment, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). This measure includes the impact of noncontrolling interests on the prior adjustment items.

Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by our board of directors) to the cash dividends we expect to pay our shareholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to cash dividends. Distributable cash flow is also an important financial measure for our shareholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly dividend rates.

Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income (loss) attributable to TRC. Distributable cash flow should not be considered as an alternative to GAAP net income (loss) available to common and preferred shareholders. It has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into our decision-making processes.

The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated.


		2018			2017			2016
	(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA and Distributable Cash Flow
Net income (loss) attributable to TRC		$	1.6		$	54.0		$	(187.3	)
Impact of TRC/TRP Merger on NCI			—			—			(3.8	)
Income attributable to TRP preferred limited partners			11.3			11.3			11.3
Interest expense, net (1)			185.8			233.7			254.2
Income tax expense (benefit)			5.5			(397.1	)		(100.6	)
Depreciation and amortization expense			815.9			809.5			757.7
Impairment of property, plant and equipment			—			378.0			—
Impairment of goodwill			210.0			—			207.0
(Gain) loss on sale or disposition of business and assets			(0.1	)		15.9			6.1
(Gain) loss from financing activities (2)			2.0			16.8			48.2
Equity (earnings) loss			(7.3	)		17.0			14.3
Distributions from unconsolidated affiliates and preferred partner interests, net			31.5			18.0			17.5
Change in contingent considerations			(8.8	)		(99.6	)		(0.4	)
Compensation on equity grants			56.3			42.3			29.7
Transaction costs related to business acquisitions			—			5.6			—
Splitter Agreement (3)			75.2			43.0			10.8
Risk management activities (4)			8.5			10.0			25.2
Noncontrolling interests adjustments (5)			(21.1	)		(18.6	)		(25.0	)
TRC Adjusted EBITDA		$	1,366.3		$	1,139.8		$	1,064.9
Distributions to TRP preferred limited partners			(11.3	)		(11.3	)		(11.3	)
Cash received from payments under Splitter Agreement (3)			43.0			43.0			43.0
Splitter Agreement (3)			(75.2	)		(43.0	)		(10.8	)
Interest expense on debt obligations (6)			(252.5	)		(224.3	)		(263.8	)
Cash tax benefit (7)			—			46.7			20.9
Maintenance capital expenditures			(135.0	)		(100.7	)		(85.7	)
Noncontrolling interests adjustments of maintenance capital expenditures			7.1			1.6			5.2
Distributable Cash Flow		$	942.4		$	851.8		$	762.4

The following table and discussion is a summary of our consolidated results of operations:

	Year Ended December 31,
	2018			2017			2016			2018 vs. 2017					2017 vs. 2016
	(In millions, except operating statistics and price amounts)
Revenues
Sales of commodities	$	9,278.7		$	7,751.1		$	5,626.8		$	1,527.6		20	%	$	2,124.3			38	%
Fees from midstream services		1,205.3			1,063.8			1,064.1			141.5		13	%		(0.3	)		—
Total revenues		10,484.0			8,814.9			6,690.9			1,669.1		19	%		2,124.0			32	%
Product purchases		8,238.2			6,906.1			4,922.9			1,332.1		19	%		1,983.2			40	%
Gross margin (1)		2,245.8			1,908.8			1,768.0			337.0		18	%		140.8			8	%
Operating expenses		722.0			622.9			553.7			99.1		16	%		69.2			12	%
Operating margin (1)		1,523.8			1,285.9			1,214.3			237.9		19	%		71.6			6	%
Depreciation and amortization expense		815.9			809.5			757.7			6.4		1	%		51.8			7	%
General and administrative expense		256.9			203.4			187.2			53.5		26	%		16.2			9	%
Impairment of property, plant and equipment		—			378.0			—			(378.0	)	(100	%)		378.0			—
Impairment of goodwill		210.0			—			207.0			210.0		—			(207.0	)		(100	%)
Other operating (income) expense		3.5			17.4			6.6			(13.9	)	(80	%)		10.8			164	%
Income (loss) from operations		237.5			(122.4	)		55.8			359.9		294	%		(178.2	)	NM
Interest expense, net		(185.8	)		(233.7	)		(254.2	)		47.9		20	%		20.5			8	%
Equity earnings (loss)		7.3			(17.0	)		(14.3	)		24.3		143	%		(2.7	)		(19	%)
Gain (loss) from financing activities		(2.0	)		(16.8	)		(48.2	)		14.8		88	%		31.4			65	%
Change in contingent considerations		8.8			99.6			0.4			(90.8	)	(91	%)		99.2		NM
Other income (expense), net		0.1			(2.6	)		0.8			2.7		104	%		(3.4	)	NM
Income tax (expense) benefit		(5.5	)		397.1			100.6			(402.6	)	(101	%)		296.5			295	%
Net income (loss)		60.4			104.2			(159.1	)		(43.8	)	(42	%)		263.3			165	%
Less: Net income (loss) attributable to noncontrolling interests		58.8			50.2			28.2			8.6		17	%		22.0			78	%
Net income (loss) attributable to Targa Resources Corp.		1.6			54.0			(187.3	)		(52.4	)	(97	%)		241.3			129	%
Dividends on Series A Preferred Stock		91.7			91.7			72.6			—		—			19.1			26	%
Deemed dividends on Series A Preferred Stock		29.2			25.7			18.2			3.5		14	%		7.5			41	%
Net income (loss) attributable to common shareholders	$	(119.3	)	$	(63.4	)	$	(278.1	)	$	(55.9	)	(88	%)	$	214.7			77	%
Financial data:
Adjusted EBITDA (1)	$	1,366.3		$	1,139.8		$	1,064.9		$	226.5		20	%	$	74.9			7	%
Distributable cash flow (1)		942.4			851.8			762.4			90.6		11	%		89.4			12	%
Capital expenditures (2)		3,327.7			1,506.5			592.1			1,821.2		121	%		914.4			154	%
Business acquisition (3)		—			987.1			—			(987.1	)	(100	%)		987.1			—

The increase in commodity sales reflects increased NGL, natural gas, petroleum and condensate volumes ($1,606.0 million) and higher NGL and condensate prices ($742.2 million), partially offset by lower natural gas prices ($465.7 million) and the impact of hedges ($22.4 million). Fee-based and other revenues increased primarily due to higher gas processing and crude gathering fees.

The increase in product purchases reflects increased volumes and higher NGL and condensate prices.

The prospective adoption of the revenue recognition accounting standard as set forth in Topic 606 in 2018 resulted in lower commodity sales ($333.2 million) and lower fee revenue ($39.6 million) with a corresponding net reduction in product purchases, resulting in no impact on operating margin or gross margin.

The higher operating margin and gross margin in 2018 reflect increased segment results for both Gathering and Processing and Logistics and Marketing. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense increased due to higher depreciation related to our growth investments, partially offset by lower depreciation for our North Texas system, which incurred an impairment write-down in 2017, lower scheduled amortization of Badlands intangibles and lower depreciation on our inland marine barge business sold in the second quarter of 2018.

General and administrative expense increased primarily due to higher compensation and benefits, including increased staffing levels, legal costs, outside professional services and contract labor costs.

In conjunction with our required annual goodwill assessments, we recognized impairments of goodwill totaling $210.0 million during 2018 related to the remaining goodwill from the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers”). There was no impairment of goodwill in 2017 as the fair values of affected reporting units exceeded their accounting carrying values.

Other operating (income) expense in 2018 was comprised primarily of the loss on sale of our refined products and crude oil storage and terminaling facilities in Tacoma, Washington, and Baltimore, Maryland, the loss on disposal of the benzene saturation component of our LSNG hydrotreater and the loss for abandoned project development costs, partially offset by the gain on sale of our inland marine barge business and the gain on an exchange of a portion of our Versado gathering system. In 2017, other operating (income) expense included the loss on sale of our 100% ownership interest in the Venice gathering system.

Lower interest expense, net, in 2018 was primarily due to higher non-cash interest income related to a lower valuation of the mandatorily redeemable preferred interests liability and higher capitalized interest related to our major growth investments. These factors more than offset the impact of higher average outstanding borrowings during 2018.

Equity earnings increased in 2018 primarily due to decreased losses of the T2 Joint Ventures, increased earnings resulting from the commencement of operations at Cayenne and increased earnings at Gulf Coast Fractionators. Equity losses of the T2 Joint Ventures in 2017 included a $12.0 million impairment of our investment in the T2 EF Cogen joint venture.

In 2018, we recorded a loss from financing activities of $2.0 million associated with amendments of our revolving credit facilities, which resulted in a write-off of debt issuance costs. In 2017, we recorded a loss from financing activities of $16.8 million upon the redemption of the Partnership’s outstanding 6⅜% Senior Notes and the repayment of the outstanding balance on our senior secured term loan.

During 2018, other income included $8.8 million of fair value adjustments of the Permian Acquisition contingent consideration, as compared to $99.6 million of other income in 2017. The decrease in fair value of the contingent consideration in 2018 was primarily attributable to lower forecasted volumes for the remainder of the earn-out period, partially offset by a shorter discount period. The decrease in fair value of the contingent consideration in 2017 was primarily related to reductions in forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region.

During 2018, we recorded income tax expense, whereas in 2017 we recorded an income tax benefit. The change is primarily attributable to the difference in income (loss) before taxes between the periods and the reduced federal statutory rate from 2017 to 2018. In 2017, the income tax benefit was primarily due to the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and the resulting reduction of the federal corporate tax rate from 35% to 21%, which under GAAP results in a recalculation of our ending balance sheet deferred tax balances.

Net income attributable to noncontrolling interests was higher in 2018 due to increased earnings at the Carnero Joint Venture, Centrahoma, Cedar Bayou Fractionators and Venice Energy Services Company, L.L.C.

The increase in commodity sales was primarily due to higher commodity prices ($2,124.2 million) and increased petroleum products, natural gas and condensate sales volumes ($100.1 million), partially offset by decreased NGL sales volumes ($13.8 million) and the impact of hedge settlements ($86.2 million). Fee-based and other revenues were flat as a result of lower export fees offset by increases in gas processing and crude gathering fees, which included the impact of our March 2017 Permian Acquisition.

The increase in product purchases was primarily due to the impact of higher commodity prices and increased volumes.

In the third quarter of 2017, we experienced limited impacts to our operations from Hurricane Harvey and our operating margin for the full year 2017 was not significantly impacted. No property insurance or business interruption insurance claims were made as a result of the storm.

The higher operating margin and gross margin in 2017 reflect increased segment results for Gathering and Processing, partially offset by decreased Logistics and Marketing segment results. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense increased primarily due to the impact of the March 2017 Permian Acquisition and the impact of other growth investments, including CBF Train 5 that went into service in the second quarter of 2016 and the Raptor Plant at SouthTX that went into service in the second quarter of 2017. These factors were partially offset by lower planned amortization of the Badlands intangible assets.

General and administrative expense increased primarily due to higher compensation and benefits, including increased staffing levels, partially offset by lower professional services and insurance premiums.

The impairment of property, plant and equipment in 2017 reflects the impairment of gas processing facilities and gathering systems associated with our North Texas operations in the Gathering and Processing segment. The impairment was the result of our assessment that forecasted undiscounted future net cash flows from operations, while positive, would not be sufficient to recover the total net book value of the underlying assets.

In conjunction with our required annual goodwill assessments, we recognized impairments of goodwill totaling $207.0 million during 2016 related to goodwill acquired in the Atlas mergers. There was no impairment of goodwill in 2017 as the fair values of affected reporting units exceeded their accounting carrying values.

Other operating expense in 2017 included a loss on the sale of our ownership interest in the Venice gathering system. Other operating expense in 2016 was primarily due to the loss on decommissioning two storage wells at our Hattiesburg facility and an acid gas injection well at our Versado facility.

Net interest expense in 2017 decreased as compared with 2016 primarily due to lower average outstanding borrowings and higher capitalized interest during 2017, partially offset by higher non-cash interest expense related to the increase in the estimated redemption value of mandatorily redeemable preferred interests.

Higher equity losses in 2017 reflect a $12.0 million loss provision due to the impairment of our investment in the T2 EF Cogen joint venture, partially offset by increased equity earnings at Gulf Coast Fractionators.

During 2017, we recorded a loss from financing activities of $16.8 million on the redemption of the outstanding 6⅜% Senior Notes and the repayment of the outstanding balance on our senior secured term loan. In 2016, we recorded a $48.2 million loss from financing activities that included the tender, open market repurchase and redemption of various series of Partnership senior notes.

During 2017, we recorded other income for changes in contingent considerations of $99.6 million resulting primarily from a reduction in the estimated fair value of the Permian Acquisition contingent consideration, which is based on a multiple of gross margin realized during the first two annual periods after the acquisition date.

The increase in income tax benefit was primarily due to the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and the resulting reduction of the federal corporate tax rate from 35% to 21%, which under GAAP results in a recalculation of our ending balance sheet deferred tax balances. The resulting $269.5 million reduction of our net deferred tax liability is included in current period earnings. Further, in 2017, which is subject to pre-Tax Act rates, a higher pre-tax loss resulted in higher income tax benefits.

Net income attributable to noncontrolling interests was higher in 2017 primarily due to the February 2016 TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for a portion of the first quarter of 2016, and our October 2016 acquisition of the 37% interest of Versado that we did not already own. Further, earnings at our joint ventures increased as compared with 2016.

Preferred dividends represent both cash dividends related to the March 2016 Series A Preferred Stock offering and non-cash deemed dividends for the accretion of the preferred discount related to a beneficial conversion feature. Preferred dividends increased as the Series A Preferred Stock was outstanding for a full year in 2017.

	Year Ended December 31,
	2018		2017		2016			2018 vs. 2017					2017 vs. 2016
Gross margin	$	1,406.7	$	1,145.5	$	903.6	$		261.2		23	%	$	241.9		27	%
Operating expenses		438.3		361.7		326.5			76.6		21	%		35.2		11	%
Operating margin	$	968.4	$	783.8	$	577.1	$		184.6		24	%	$	206.7		36	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)		1,141.2		893.5		747.4			247.7		28	%		146.1		20	%
Permian Delaware (4)		443.9		381.8		321.0			62.1		16	%		60.8		19	%
Total Permian		1,585.1		1,275.3		1,068.4			309.8					206.9

SouthTX		389.6		273.2		216.4			116.4		43	%		56.8		26	%
North Texas		244.1		268.1		317.3			(24.0	)	(9	%)		(49.2	)	(16	%)
SouthOK		555.7		494.0		462.1			61.7		12	%		31.9		7	%
WestOK		351.6		377.7		444.9			(26.1	)	(7	%)		(67.2	)	(15	%)
Total Central		1,541.0		1,413.0		1,440.7			128.0					(27.7	)

Badlands (5)		85.1		56.5		52.1			28.6		51	%		4.4		8	%
Total Field		3,211.2		2,744.8		2,561.2			466.4					183.6

Coastal		726.2		728.8		838.4			(2.6	)	—			(109.6	)	(13	%)

Total		3,937.4		3,473.6		3,399.6			463.8		13	%		74.0		2	%
NGL production, MBbl/d (3)
Permian Midland (4)		153.4		118.3		94.5			35.1		30	%		23.8		25	%
Permian Delaware (4)		53.5		43.1		36.4			10.4		24	%		6.7		18	%
Total Permian		206.9		161.4		130.9			45.5					30.5

SouthTX		51.1		30.4		23.8			20.7		68	%		6.6		28	%
North Texas		28.1		30.2		35.8			(2.1	)	(7	%)		(5.6	)	(16	%)
SouthOK		54.7		42.8		39.4			11.9		28	%		3.4		9	%
WestOK		20.5		21.9		27.1			(1.4	)	(6	%)		(5.2	)	(19	%)
Total Central		154.4		125.3		126.1			29.1					(0.8	)

Badlands		10.8		7.9		7.3			2.9		37	%		0.6		8	%
Total Field		372.1		294.6		264.3			77.5					30.3

Coastal		43.6		38.6		41.2			5.0		13	%		(2.6	)	(6	%)

Total		415.7		333.2		305.5			82.5		25	%		27.7		9	%
Crude oil gathered, Badlands, MBbl/d		146.8		113.6		105.2			33.2		29	%		8.4		8	%
Crude oil gathered, Permian, MBbl/d (4)		64.9		29.8		—			35.1		118	%		29.8		—
Natural gas sales, BBtu/d (3)		1,867.9		1,665.4		1,623.6			202.5		12	%		41.8		3	%
NGL sales, MBbl/d		317.6		254.8		241.3			62.8		25	%		13.5		6	%
Condensate sales, MBbl/d		12.6		11.8		9.9			0.8		7	%		1.9		19	%
Average realized prices (6):
Natural gas, $/MMBtu		1.98		2.65		2.14			(0.67	)	(25	%)		0.51		24	%
NGL, $/gal		0.63		0.55		0.36			0.08		15	%		0.19		53	%
Condensate, $/Bbl		55.99		45.52		36.20			10.47		23	%		9.32		26	%

The increase in gross margin was primarily due to higher Permian, Badlands and Central volumes and higher NGL and condensate prices, partially offset by the impact of lower natural gas prices. NGL production, NGL sales and natural gas sales increased due to higher Field Gathering and Processing inlet volumes and increased NGL recoveries including reduced ethane rejection. Coastal Gathering and Processing had a positive margin impact due to richer gas, increased recoveries and higher NGL prices, partially offset by slightly lower inlet volumes. Total crude oil gathered volumes increased in the Permian region due to production from new wells, system expansions and the inclusion of the March 2017 Permian Acquisition for the full year in 2018. In the Badlands, total crude oil gathered volumes and natural gas gathered volumes increased primarily due to production from new wells and system expansions.

Operating expenses increased as a result of higher compensation, contract labor and other costs primarily associated with new plants in the Permian and Central regions and system expansions in the Badlands.

The increase in gross margin was primarily due to higher commodity prices and higher Permian volumes including those associated with the Permian Acquisition. The overall increase in Gathering and Processing inlet volumes included all areas in the Permian region, at SouthTX and SouthOK, partially offset by decreases at WestOK, North Texas and Coastal. The Coastal Gathering and Processing assets generate significantly lower unit margins than the Field Gathering and Processing assets. NGL production, NGL sales and natural gas sales increased primarily due to higher Field Gathering and Processing inlet volumes and increased plant recoveries including additional ethane recovery. Total crude oil gathered volumes increased in the Permian region due to the Permian Acquisition. In the Badlands, total crude oil gathered volumes and natural gas volumes increased primarily due to higher production from new wells and system expansions.

The increase in operating expenses was primarily driven by the inclusion of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement in operations of the Raptor Plant at SouthTX.

The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field portion of the Gathering and Processing segment:

	Year Ended December 31, 2018
Operating statistics:
Plant natural gas inlet, MMcf/d (1), (2)	Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported
Permian Midland		1,438.5	Varies (4)				1,141.2		1,141.2
Permian Delaware		443.9		100	%		443.9		443.9
Total Permian		1,882.4					1,585.1		1,585.1

SouthTX		389.6	Varies (5)				283.9		389.6
North Texas		244.1		100	%		244.1		244.1
SouthOK		555.7	Varies (6)				432.8		555.7
WestOK		351.6		100	%		351.6		351.6
Total Central		1,541.0					1,312.4		1,541.0

Badlands (7)		85.1		100	%		85.1		85.1
Total Field		3,508.5					2,982.6		3,211.2

NGL production, MBbl/d (2)
Permian Midland		194.1	Varies (4)				153.4		153.4
Permian Delaware		53.5		100	%		53.5		53.5
Total Permian		247.6					206.9		206.9

SouthTX		51.1	Varies (5)				35.9		51.1
North Texas		28.1		100	%		28.1		28.1
SouthOK		54.7	Varies (6)				42.8		54.7
WestOK		20.5		100	%		20.5		20.5
Total Central		154.4					127.3		154.4

Badlands		10.8		100	%		10.8		10.8
Total Field		412.8					345.0		372.1

	Year Ended December 31, 2017
Operating statistics:
Plant natural gas inlet, MMcf/d (1), (2)	Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported
Permian Midland (4)		1,110.8	Varies (5)				893.5		893.5
Permian Delaware (4)		381.8		100	%		381.8		381.8
Total Permian		1,492.6					1,275.3		1,275.3

SouthTX		273.2	Varies (6)				213.5		273.2
North Texas		268.1		100	%		268.1		268.1
SouthOK		494.0	Varies (7)				397.9		494.0
WestOK		377.7		100	%		377.7		377.7
Total Central		1,413.0					1,257.2		1,413.0

Badlands (8)		56.5		100	%		56.5		56.5
Total Field		2,962.1					2,589.0		2,744.8

NGL production, MBbl/d (2)
Permian Midland (4)		148.2	Varies (5)				118.3		118.3
Permian Delaware (4)		43.1		100	%		43.1		43.1
Total Permian		191.3					161.4		161.4

SouthTX		30.4	Varies (6)				23.4		30.4
North Texas		30.2		100	%		30.2		30.2
SouthOK		42.8	Varies (7)				34.9		42.8
WestOK		21.9		100	%		21.9		21.9
Total Central		125.3					110.4		125.3

Badlands		7.9		100	%		7.9		7.9
Total Field		324.5					279.7		294.6

	Year Ended December 31, 2016
Operating statistics:
Plant natural gas inlet, MMcf/d (1), (2)	Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported
Permian Midland (4)		929.8	Varies (5)				747.4		747.4
Permian Delaware		321.0	Varies (6)				253.8		321.0
Total Permian		1,250.8					1,001.2		1,068.4

SouthTX		216.4	Varies (7)				205.6		216.4
North Texas		317.3		100	%		317.3		317.3
SouthOK		462.1	Varies (8)				382.0		462.1
WestOK		444.9		100	%		444.9		444.9
Total Central		1,440.7					1,349.8		1,440.7

Badlands (9)		52.1		100	%		52.1		52.1
Total Field		2,743.6					2,403.1		2,561.2

Gross NGL production, MBbl/d (2)
Permian Midland (4)		117.9	Varies (5)				94.5		94.5
Permian Delaware		36.4	Varies (6)				36.4		36.4
Total Permian		154.3					130.9		130.9

SouthTX		23.8	Varies (7)				22.8		23.8
North Texas		35.8		100	%		35.8		35.8
SouthOK		39.4	Varies (8)				32.6		39.4
WestOK		27.1		100	%		27.1		27.1
Total Central		126.1					118.3		126.1

Badlands		7.3		100	%		7.3		7.3
Total Field		287.7					256.5		264.3

		Year Ended December 31,
		2018		2017		2016			2018 vs. 2017					2017 vs. 2016
	(In millions)
Gross margin		$	876.8	$	773.4	$		801.8	$	103.4		13	%	$	(28.4	)	(4	%)
Operating expenses			284.3		261.6			227.4		22.7		9	%		34.2		15	%
Operating margin		$	592.5	$	511.8	$		574.4	$	80.7		16	%	$	(62.6	)	(11	%)
Operating statistics MBbl/d (1):
Fractionation volumes (2)(3)			426.7		354.2			309.3		72.5		20	%		44.9		15	%
LSNG treating volumes (2)			32.1		32.2			24.9		(0.1	)	—			7.3		29	%
Benzene treating volumes (2)(4)			3.3		21.6			22.1		(18.3	)	(85	%)		(0.5	)	(2	%)
Export volumes (5)			203.4		184.1			181.4		19.3		10	%		2.7		1	%
NGL sales			537.9		490.0			477.5		47.9		10	%		12.5		3	%
Average realized prices:
NGL realized price, $/gal		$	0.77	$	0.69	$	0.49		$	0.08		12	%	$	0.20		41	%

Logistics and Marketing gross margin increased due to higher fractionation margin, higher domestic marketing margin, higher LPG export margin, and higher terminaling and storage throughput, partially offset by lower commercial transportation margin and lower marketing gains. Fractionation margin increased due to higher supply volume and higher fees, partially offset by lower system product gains. Fractionation margin was partially impacted by the variable effects of fuel and power which are largely reflected in operating expenses (see footnote (2) above). Domestic marketing margin increased due to higher terminal volumes and higher unit margins. LPG export margin increased primarily due to higher volumes. Commercial transportation margin decreased primarily due to the sale of the Company’s inland marine barge business in the second quarter of 2018.

Operating expenses increased due to higher fuel and power costs that are largely passed through and higher compensation and benefits, partially offset by lower maintenance expenses and lower taxes.

Logistics and Marketing gross margin decreased due to lower LPG export margin and lower domestic marketing margin, partially offset by higher fractionation margin, higher terminaling and storage throughput and higher marketing gains. LPG export margin decreased due to lower fees partially offset by higher volumes. Domestic marketing margin decreased due to lower terminal margins. Fractionation margin increased due to higher supply volume and higher system product gains. Fractionation margin was partially impacted by the variable effects of fuel and power costs that are largely reflected in operating expenses (see footnote (2) above).

Operating expenses increased due to higher fuel and power costs that are largely passed through, higher compensation and benefits related to the operations of CBF Train 5, 2017 repairs and maintenance activities that were not required in 2016 and higher taxes.

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. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow.

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 in our Gathering and Processing operations that result from percent of proceeds/liquids processing arrangements. Because we are essentially forward-selling a portion of our future plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. Additionally, we hedge the commodity price associated with a portion of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Marketing segment. See further details of our risk management program in “Item 7A. – Quantitative and Qualitative Disclosures About Market Risk.”

The following table provides a breakdown of the change in Other operating margin:

As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $7.6 million and $26.6 million for the years ended December 31, 2017 and 2016, related to these novated contracts. The final settlement was received in December 2017. These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.

As of December 31, 2018, we had $232.1 million of “Cash and cash equivalents” on our Consolidated Balance Sheet. We believe our cash position, remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”), and our cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership’s liquidity, subject to the limitations set forth in the Partnership Agreement and any restrictions contained in the covenants of the Partnership’s debt agreements, as well as the ability to contribute capital to the Partnership, subject to any restrictions contained in the covenants of our debt agreements.

On a consolidated basis, our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing our indebtedness and meeting our collateral requirements, and to pay dividends declared by our board of directors will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices, weather and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

We are entitled to the entirety of distributions made by the Partnership on its equity interests, other than those made to the TRP Preferred Unitholders. The actual amount we declare as dividends depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.

The Partnership’s debt agreements and obligations to its Preferred Unitholders may restrict or prohibit the payment of distributions if the Partnership is in default, threat of default, or arrears. If the Partnership cannot make distributions to us, we may be limited in our ability, or unable, to pay dividends on our common stock. In addition, so long as any shares of our Preferred Shares are outstanding, certain common stock distribution limitations exist.

On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRC Revolver, the TRP Revolver, and the Securitization Facility, and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

Other potential capital resources associated with our existing arrangements include:

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P. They also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from NGL customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels and valuation, which we closely manage; (iii) changes in payables and accruals related to major growth projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth projects.

Working capital as of December 31, 2018 decreased $1,033.2 million compared to December 31, 2017. Our working capital, exclusive of current debt obligations and reclassifications from other long-term liabilities, decreased $53.9 million from December 31, 2017 to December 31, 2018. The major items contributing to the decrease in 2018 were increases in accounts payable and accruals, especially those related to Grand Prix, Train 6 and other growth projects and a reduction in inventories primarily attributable to a decrease in volumes in storage. The working capital decrease was partially offset by an increase in our net risk management position due to changes in forward prices of commodities, higher cash balances and increased commodity activities. Working capital as of December 31, 2018 was also impacted by a $301.4 million decrease primarily due to the May 2019 estimated contingent consideration payment, a $749.4 million decrease due to the reclassification of the 4⅛% Senior Notes due 2019 from long-term to short-term and a $70.0 million increase due to lower borrowings under our Securitization Facility.

Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings available under the TRC Revolver, the TRP Revolver and the Securitization Facility and proceeds from debt and equity offerings, as well as joint ventures and/or potential asset sales, should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and quarterly cash dividends for at least the next twelve months.

In February 2018, Stonepeak Infrastructure Partners (“Stonepeak”) committed a maximum of approximately $960 million of capital to the three newly-formed DevCo JVs. 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 has dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin.

For the year ended December 31, 2018, total contributions from Stonepeak to the DevCo JVs were $557.1 million. For the year ended December 31, 2018, total contributions from Blackstone to the Grand Prix Joint Venture were $212.5 million. These contributions from Stonepeak and Blackstone are included in noncontrolling interests.

For the year ended December 31, 2018, we issued 6,315,711 shares of common stock under the December 2016 EDA, receiving net proceeds of $318.6 million. In September 2018, we terminated the December 2016 EDA.

We also sold 7,527,902 shares of common stock under our May 2017 EDA, receiving net proceeds of $364.9 million. As of December 31, 2018, we have $382.1 million remaining under the May 2017 EDA. On September 20, 2018, we entered into the September 2018 EDA, pursuant to which we may sell through our sales agents, at our option, up to an aggregate amount of $750.0 million of our common stock. For the year ended December 31, 2018, no shares of common stock were issued under the September 2018 EDA.

From time to time, we issue long-term debt securities, which we refer to as senior notes. Our senior notes issued to date, generally have similar terms other than interest rates, maturity dates and redemption premiums. As of December 31, 2018 and December 31, 2017, the aggregate principal amount outstanding of our senior notes and other various long-term debt obligations (excluding current maturities) was $5,663.2 million and $4,732.6 million, respectively.

We consolidate the debt of the Partnership with that of our own; however, we do not have the contractual obligation to make interest or principal payments with respect to the debt of the Partnership. Our debt obligations do not restrict the ability of the Partnership to make distributions to us. Our Credit Agreement has restrictions and covenants that may limit our ability to pay dividends to our stockholders. See Note 10 – Debt Obligations for more information regarding our debt obligations.

The majority of our consolidated debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRC Revolver, the TRP Revolver and the Securitization Facility. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of December 31, 2018, we did not have any interest rate hedges.

In April 2018, the Partnership issued $1.0 billion aggregate principal amount of the 5⅞% Senior Notes due April 2026. The Partnership used the net proceeds of $991.9 million after costs from this offering to repay borrowings under its credit facilities and for general partnership purposes.

In June 2018, we entered into an agreement to amend the TRC Revolver which extended the maturity date from February 2020 to June 2023. The available commitments of $670.0 million and our ability to request additional commitments of $200.0 million remained unchanged. The TRC Revolver continues to bear interest costs that are dependent on our ratio of non-Partnership consolidated funded indebtedness to consolidated Adjusted EBITDA and the covenants remained substantially the same.

In June 2018, the Partnership entered into an agreement to amend and restate the TRP Revolver which extended the maturity date from October 2020 to June 2023 and increased available commitments from $1.6 billion to $2.2 billion. The Partnership’s ability to request additional commitments of $500.0 million remained unchanged. The TRP Revolver continues to bear interest costs that are dependent on the ratio of the Partnership’s consolidated funded indebtedness to consolidated Adjusted EBITDA and the covenants remained substantially the same.

To date, our and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 10 - Debt Obligations to our consolidated financial statements. For information about our interest rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

As of December 31, 2018, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs, natural gas and other petroleum commodities, as well as fees for gas processing, crude gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs and natural gas, (iii) changes in payables and accruals related to major growth projects; and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.

Net cash provided by operations increased from 2017 to 2018 primarily due to the impact of higher NGL and condensate prices and volumes, and decreased margin calls from futures contracts, partially offset by increases in payments for operating expenses and general and administration expenses. The increase was further offset by cash tax transactions. In 2017, we received net tax refunds mainly from a net operating loss carryback, which did not occur in 2018. The rising commodity prices and volumes resulted in higher cash collections from customers, partially offset by higher product purchases. Increases in payments for operating expenses and general and administrative expenses were mainly due to system expansions, and higher compensation and benefits.

Net cash provided by operating activities increased in 2017 compared to 2016, primarily driven by higher commodity prices and a lower average debt balance, offset by the impact of expanded operations in 2017. Higher commodity prices resulted in higher net cash collections from the sale of commodities partially offset by an increase in NGL product inventory, and higher margin calls and payments related to our derivative contracts. The lower average debt balance in 2017 resulting from the debt repayments in the fourth quarter of 2016 contributed to lower interest charges. In addition, we received net tax refunds mainly from net operating loss carryback. Expanded operations in 2017 contributed to increases in payments for compensation and benefits, as well as utilities.

Cash used in investing activities increased in 2018 compared to 2017, primarily due to increased outlays for property, plant and equipment and contributions to unconsolidated affiliates, partially offset by lower outlays for business acquisitions and higher proceeds from the sale of assets. Our capital expenditures for property, plant and equipment increased $1,817.3 million in 2018 primarily related to a large number of capital projects, and our contributions to unconsolidated affiliates increased $272.5 million primarily due to the construction activities of GCX and the LM4 Plant. We have made no cash payment for business acquisitions in 2018, whereas in 2017 we paid $570.8 million for the initial cash portion of the Permian Acquisition. In 2018, we received proceeds of $256.9 million from the sale of our facilities in Tacoma, Washington, and Baltimore, Maryland, the sale of our inland marine barge business and the exchange of a portion of our Versado gathering system.

Cash used in investing activities increased in 2017 compared to 2016, primarily due to a $735.4 million increase in capital expenditures, reflecting the spending for major growth projects during 2017 and the acquisition of the Flag City Plant. In addition, outlays for business acquisitions increased by $570.8 million for the cash portion of the Permian Acquisition consideration.

In 2018, we realized a net source of cash from financing activities primarily due to a net increase of debt outstanding, contributions from noncontrolling interests and equity offerings under our December 2016 EDA and May 2017 EDA, partially offset by payments of dividends and distributions. The issuance of 5⅞% Senior Notes due 2026 and increases in net borrowings under our credit facilities contributed to higher net debt outstanding. The contributions from noncontrolling interests were primarily from Stonepeak and Blackstone to fund growth projects.

In 2017, we realized a net source of cash from financing activities primarily due to equity offerings and a net increase of debt borrowing, partially offset by payments of dividends and distributions. We issued 9,200,000 shares of common stock in January 2017 and 17,000,000 shares of common stock in June 2017 through public offerings in addition to common stock offerings through our December 2016 equity distribution agreement. A portion of the proceeds from the equity issuances was used to repay outstanding borrowings under the TRP Revolver and to redeem TRP’s 6⅜% Senior Notes due 2022. In October 2017, we issued 5% Senior Notes due 2028 and used a portion of the proceeds to redeem our 5% Senior Notes due 2018. During 2017, we sold a 25% interest in the Grand Prix Joint Venture to Blackstone, which contributed a total of $96.3 million to the joint venture in 2017. The contributions from Blackstone are included in financing activities as contributions from noncontrolling interests.

We incurred a net use of cash from financing activities in 2016, primarily due to a net reduction of outstanding debt and payment of dividends and distributions, partially offset by proceeds from our issuance of 965,100 shares of Series A Preferred Stock (“Series A Preferred”) and common stock issued under our May 2015 and December 2016 EDAs. With the proceeds from equity issuances we repurchased a portion of the Partnership’s senior notes through open market repurchases generally at a discount to par values and repaid a portion of our senior secured credit facilities. With the proceeds from new senior note borrowings and additional borrowings under the TRP Revolver, we tendered for, and then redeemed, certain of the Partnership’s senior notes to refinance to longer maturities.

The following table details the dividends on common stock declared and/or paid by us for 2018:

Our Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter.

Cash dividends of $91.7 million were paid to holders of the Series A Preferred during the year ended December 31, 2018. As of December 31, 2018, cash dividends accrued for our Series A Preferred were $22.9 million, which were paid on February 14, 2019.

Our capital requirements relate to capital expenditures, which are classified as growth capital expenditures, business acquisitions, and maintenance expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

We currently estimate that we will invest at least $2,300 million in net growth capital expenditures (exclusive of outlays for business acquisitions) and contributions to investments in unconsolidated affiliates for announced projects in 2019. Given our objective of growth through expansions of existing assets, other internal growth projects, and acquisitions, we anticipate that, over time, we will invest significant amounts of capital to grow and acquire assets. Future growth capital expenditures may vary significantly based on investment opportunities. We expect that 2019 net maintenance capital expenditures will be approximately $130 million.

Our growth capital expenditures increased for the year ended December 31, 2018 as compared to the year ended December 31, 2017, primarily due to spending related to Grand Prix, additional processing plants and associated infrastructure in the Permian Basin, SouthOK and Badlands, and construction of Train 6. Our maintenance capital expenditures increased for 2018 as compared to 2017, primarily due to our increased asset base and additional infrastructure.

Our growth capital expenditures increased for the year ended December 31, 2017 as compared to the year ended December 31, 2016, primarily due to spending related to additional processing plants and associated infrastructure in the Permian Basin, Grand Prix and the Channelview Splitter, as well as the acquisition of the Flag City Plant. The increase was partially offset by the impact of the substantial completion of the CBF Train 5 project in the second quarter of 2016. Our maintenance capital expenditures increased for 2017 as compared to 2016, primarily due to increases in overhauls driven by higher volumes on our systems and additional infrastructure upgrades of the existing capital assets.

As of December 31, 2018, there were $55.3 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 8 – Investments in Unconsolidated Affiliates and Note 10 – Debt Obligations.

In addition to disclosures related to debt and lease obligations, contained in our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report, the following is a summary of certain contractual obligations over the next several years:

	Payments Due By Period
			Less Than						More Than
Contractual Obligations	Total		1 Year		1-3 Years		3-5 Years		5 Years
	(in millions)
Long-term debt obligations (1)	$	5,663.2	$	—	$	6.5	$	2,326.6	$	3,330.1
Interest on debt obligations (2)		1,737.5		299.9		529.7		499.0		408.9
Operating leases (3)		110.8		20.9		38.7		26.3		24.9
Land site lease and rights of way (4)		122.3		4.0		7.3		8.2		102.8

Purchase Obligations (5):
Pipeline capacity and throughput agreements (6)		785.0		167.2		197.7		198.5		221.6
Commodities (7)		240.8		151.3		89.5		—		—
Purchase commitments and service contracts (8)		1,390.4		1,372.9		7.1		2.2		8.2

Other long-term liabilities (9)		53.3		—		14.5		8.7		30.1
	$	10,103.3	$	2,016.2	$	891.0	$	3,069.5	$	4,126.6
Commodity Volumetric Commitments
Natural gas (MMBtu)		19.9		19.9		—		—		—
NGLs (MMgal)		499.4		213.8		285.6		—		—

The accounting policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

For business acquisitions, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the acquisition date. Goodwill results when the cost of a business acquisition exceeds the fair value of the net identifiable assets of the acquired business. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with respect to projections of future production volumes, pricing and cash flows, benchmark analysis of comparable public companies, discount rates, expectations regarding customer contracts and relationships, and other management estimates. The judgments made in the determination of the estimated fair value assigned to the assets acquired, liabilities assumed and any noncontrolling interest in the investee, the duration of each liability, and any resulting goodwill can materially impact the financial statements in periods after acquisition. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures to our consolidated financial statements.

Depreciation of Property, Plant and Equipment and Amortization of Intangible Assets

In general, depreciation and amortization is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. Amortization expense attributable to intangible 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. At the time assets are placed in service or acquired, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation/amortization amounts prospectively. Examples of such circumstances include:

We evaluate long-lived assets, including related intangibles, for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. 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.

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. We early adopted ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, for our annual goodwill impairment test as of November 30, 2017, which requires an impairment up to the amount of goodwill to the extent that the carrying value of the affected reporting unit exceeds its fair value.

Our 2016 evaluation was performed under the previous guidance, which required a second step if the carrying value of the reporting unit exceeded its fair value. The second step involved determining the fair value of the assets and liabilities of the affected reporting unit to derive the implied fair value of goodwill. Any excess carrying value over the implied fair value was recognized as a goodwill impairment loss.

Our goodwill impairment assessments utilized the income approach (a discounted cash flow analysis (“DCF”)) to estimate the fair values of our reporting units. Future cash flows for our reporting units were based on our estimates, at that time, of future volumes and operating margin and other factors, such as timing of capital expenditures and terminal values. We took into account current and expected industry and market conditions, including commodity pricing, volumetric forecasts and observable exit multiples in the basins in which the reporting units operate. The discount rates used in our DCF analysis were based on a weighted average cost of capital determined from relevant market comparisons. Changes in the forecasts and assumptions used in our DCF analysis could have a material effect on the results of our goodwill assessment.

Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. In an effort to reduce the volatility of our cash flows, we have entered into derivative financial 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.

One of the primary factors that can affect our operating results each period is the price assumptions used to value our derivative financial instruments, which are reflected at their fair values on the balance sheet. We determine the fair value of our derivative instruments using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. Changes in the methods or assumptions we use to calculate the fair value of our derivative instruments could have a material effect on our consolidated financial statements.

For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.

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.

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.

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 the Partnership’s senior secured indebtedness that ranks equal in right of payment with liens granted in favor of the Partnership’s 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.

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRC Revolver, 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 TRC Revolver, the TRP Revolver and the Securitization Facility will also increase. As of December 31, 2018, the Partnership had $980.0 million in outstanding variable rate borrowings under the TRP Revolver and Securitization Facility, and we had outstanding variable rate borrowings of $435.0 million under the TRC Revolver. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact the Partnership’s annual interest expense by $9.8 million and our consolidated annual interest expense by $14.2 million based on our December 31, 2018 debt balances.

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.

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 $8.7 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.

Our “Consolidated Financial Statements,” together with the report of our independent registered public accounting firm, begin on page F-1 in this Annual Report.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

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.

Our Management’s Report on Internal Control Over Financial Reporting is included on page F-2 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.

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.

Our executive officers listed below serve in the same capacity for the General Partner and devote their time as needed to conduct the business and affairs of both the Company and the Partnership. Because the Company’s only cash-generating assets are direct and indirect partnership interests in the Partnership, we expect that our executive officers will devote a substantial majority of their time to the Partnership’s business and affairs. We expect the amount of time that our executive officers devote to the Company’s business and affairs as opposed to the Partnership’s business and affairs in future periods will not be substantial unless significant changes are made to the nature of the Company’s business.

Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers. The following table sets forth certain information with respect to our directors, executive officers and other officers as of February 17, 2019:

Joe Bob Perkins has served as Chief Executive Officer and director of the Company and the 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 the 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 the 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 the 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 the 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 the 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 the 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 the General Partner since November 12, 2015. Mr. Heim previously served as President and Chief Operating Officer of the Company and the 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 the 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 the General Partner since March 1, 2018. Mr. Meloy previously served as Executive Vice President and Chief Financial Officer of the Company and the General Partner between May 20, 2015 and February 28, 2018. He also served as Treasurer of the Company and the 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 the 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 the General Partner between March 2006 and March 2008. He has served as Vice President – Finance and Treasurer of the 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 the 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 the General Partner between October 2006 and December 15, 2010 and served as a director of the 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 the 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 the General Partner since March 1, 2018. Mr. McDonie previously served as Executive Vice President – Southern Field Gathering and Processing of the Company and the 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 the General Partner, since March 1, 2018. Mr. Pryor previously served as Executive Vice President – Logistics and Marketing of the Company and the 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 the General Partner since March 1, 2018. Mr. Muraro previously served as Executive Vice President – Commercial of the Company and the 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 the General Partner since March 1, 2018. Ms. Kneale previously served as Vice President – Finance of the Company and the General Partner between December 16, 2015 and February 28, 2018. She also served as Senior Director, Finance of the Company and the General Partner between March 2015 and December 2015. She also served as Director, Finance of the Company and the 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 the 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 the 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 the General Partner since February 22, 2017. Mr. Klein previously served as Senior Vice President – Controller of the Company and the 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 the 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 the General Partner since October 2006. Mr. Joyce previously served as Executive Chairman of the Board of the 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 the 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 the 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 the 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 the 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 the 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 the 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 the 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 the 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.

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.

Our board of directors has four standing committees – an Audit Committee, a Compensation Committee, a Nominating and Governance Committee and a Risk Management Committee – and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors has the composition and responsibilities described below.

The current members of our Audit Committee are Messrs. Tong and Redd and Ms. Fulton. Mr. Tong serves as the Chairman of the Audit Committee, a position he has held for the last 13 years. 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 and Ms. Fulton are “audit committee financial experts” 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 and our cybersecurity efforts and measures. 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 members of our Compensation Committee are Messrs. Crisp, Davis and Evans. Mr. Davis is the Chairman of this committee. This committee establishes salaries, incentives and other forms of compensation for officers and other employees. Our Compensation Committee also administers our incentive compensation and benefit plans. We have adopted a Compensation Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

In August 2018, the Compensation Committee considered the independence of BDO USA, LLP (“BDO”), our compensation consultant, in light of new SEC rules and the NYSE listing standards. The Compensation Committee requested and received a letter from BDO addressing the consulting firm’s independence, including the following factors:

The Compensation Committee concluded that the work of BDO did not raise any conflict of interest.

The members of our Nominating and Governance Committee are Messrs. Crisp, Tong and Davis. Mr. Crisp is the Chairman of this committee. This committee identifies, evaluates and recommends qualified nominees to serve on our board of directors, develops and oversees our internal corporate governance processes and maintains a management succession plan. We have adopted a Nominating and Governance Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.

In evaluating director candidates, the Nominating and Governance Committee assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the Company, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

The members of our Risk Management Committee are Messrs. Evans, Joyce and Whalen and Ms. Bowman. Mr. Evans is the Chairman of this committee. This committee oversees our commodity price and commodity basis risk management and hedging activity.

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.

Our board of directors has adopted a Code of Ethics For Chief Executive Officer and Senior Financial Officers (the “Code of Ethics”), which applies to our 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 our and our subsidiaries’ officers, directors and employees. 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.

We make available, free of charge within the “Corporate Governance” section of our website at http://www.targaresources.com and in print to any stockholder who so requests, our Corporate Governance Guidelines, Code of Ethics, Code of Conduct, Audit Committee Charter, Compensation Committee charter and Nominating and Governance Committee charter. Requests for print copies may be directed to: Investor Relations, Targa Resources Corp., 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.

Our board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

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 Corp., 811 Louisiana, Suite 2100, Houston, Texas 77002.

Section 16(a) of the Securities Exchange Act of 1934 requires our directors, executive officers and 10% stockholders to file with the SEC reports of ownership and changes in ownership of our equity securities. 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 common shares complied with Section 16(a) filing requirements applicable to them, except for a Form 4 disclosing one transaction by Mr. Klein on August 14, 2018, which was filed one day late on August 17, 2018 due to administrative issues.

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.

Compensatory arrangements with our executive officers identified in the Summary Compensation Table (“named executive officers”) are approved by the Compensation Committee of our Board of Directors (the “Compensation Committee”). For 2018, our named executive officers were:

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.

Our operating assets are held by subsidiaries of the Partnership, and our named executive officers also served as executive officers of its General Partner during 2018. The named executive officers devote their time as needed to the conduct of our 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 our named executive officers for the services they provide to us and for the services they provide to the General Partner and the Partnership for the years indicated. For 2018, the Compensation Committee was generally responsible for determining and setting compensation practices for our named executive officers. During 2018, the Partnership reimbursed us and our affiliates for the compensation of our named executive officers pursuant to the Partnership’s partnership agreement. See “—Transactions with Related Persons—Reimbursement of Operating and General and Administrative Expense” for additional information regarding the Partnership’s 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 that the Company’s performance over its trading history demonstrates that our compensation programs are structured to pay reasonable amounts for performance based on our understanding of the markets in which we compete for executive talent and the returns our shareholders have realized.

We held our most recent advisory say-on-pay vote regarding executive compensation at our 2018 Annual Meeting. At that meeting, more than 93% of the votes cast by our shareholders approved, on an advisory basis, of the compensation paid to our named executive officers as described in the CD&A and the other related compensation tables and disclosures contained in our Proxy Statement filed with the SEC on March 29, 2018. The Board of Directors and the Compensation Committee reviewed the results of this vote and concluded that, with this level of support, no changes to our compensation design and philosophy needed to be considered as a result of the say-on-pay vote. In accordance with the preference expressed by our shareholders to conduct an advisory vote on executive compensation every year, the next advisory vote will occur this year at the 2019 Annual Meeting. See “Item 3 —Advisory Vote on Executive Compensation”

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:

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.

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:

The following compensation objectives guide the Compensation Committee in its deliberations about executive compensation matters:

Consistent with this philosophy and the compensation objectives, our 2018 executive compensation program consisted of the following elements:

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).

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.

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).

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.

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.

Based upon the recommendation of our Compensation Consultant, we made the following changes to our Peer Group during the 2018 year:

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:

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.

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:

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.

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:

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:

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.

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.

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.

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.

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:

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.

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.

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:

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.

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).

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.

Messrs. Davis, Crisp and Evans are the current members of our Compensation Committee. In fulfilling its oversight responsibilities, the Compensation Committee 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 and in our proxy statement. Based on these reviews and discussions, the Compensation Committee recommended to our Board of Directors that the Compensation Discussion and Analysis be included in our Annual Report on Form 10-K for the year ended December 31, 2018 and in our proxy statement 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.

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.

Name and Principal Position	Year	Salary		Bonus (1)		Stock Awards ($) (2) (3)		All Other Compensation (4)		Total
Joe Bob Perkins	2018	$	833,333	$	—	$	12,624,959	$	23,310	$	13,481,602
Chief Executive Officer	2017		745,833		—		4,552,878		23,184		5,321,895
	2016		—		453,125		3,534,138		1,616		3,988,879

Matthew J. Meloy	2018		516,667		1,115,625		3,914,716		23,037		5,570,045
President	2017		472,500		418,800		4,901,220		22,814		5,815,334
	2016		450,000		258,750		909,856		22,270		1,640,876

Jennifer R. Kneale	2018		332,500		446,250		1,166,427		22,535		1,967,712
Chief Financial Officer


Patrick J. McDonie	2018		466,667		807,500		1,803,674		22,928		3,100,769
President – Gathering and Processing	2017		422,633		221,000		3,977,300		22,685		4,643,618


D. Scott Pryor	2018		466,667		807,500		1,803,674		22,928		3,100,769
President - Logistics and Marketing	2017		419,167		221,000		3,969,916		22,630		4,632,713


Paul W. Chung	2018		520,833		892,500		2,153,478		23,092		3,589,903
Executive Vice President, General	2017		498,333		400,000		1,807,450		22,894		2,728,677
Counsel and Secretary	2016		490,000		275,625		1,104,764		22,494		1,892,883

The following table and the footnotes thereto provide information regarding grants of plan-based equity awards made to the named executive officers during 2018:

		Estimated Future Payouts Under Performance Share Unit Awards						Equity Awards: Number of Units		Grant Date Fair Value of Equity Awards (4)
Name	Grant Date	Threshold (#)		Target (#)		Maximum (#)		Equity Awards: Number of Units		Grant Date Fair Value of Equity Awards (4)
Mr. Perkins	01/12/18 (1)								80,000	$	4,076,000
	01/17/18 (2)		23,494		46,987		117,468		46,987		6,207,453
	01/17/18 (3)								45,831		2,341,506

Mr. Meloy	01/17/18 (2)		13,192		26,383		65,958		26,383		3,485,458
	01/17/18 (3)								8,402		429,258

Ms. Kneale	01/17/18 (2)		3,958		7,915		19,788		7,915		1,045,651
	01/17/18 (3)								2,364		120,777

Mr. McDonie	01/17/18 (2)		5,968		11,935		29,838		11,935		1,576,733
	01/17/18 (3)								4,442		226,942

Mr. Pryor	01/17/18 (2)		5,968		11,935		29,838		11,935		1,576,733
	01/17/18 (3)								4,442		226,942

Mr. Chung	01/17/18 (2)		6,596		13,191		32,978		13,191		1,742,663
	01/17/18 (3)								8,041		410,815

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”).

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.

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.”

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.”

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.

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.

We do not have any plan that provides for the deferral of compensation on a basis that is not tax qualified.

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.”

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.

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.

(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.

(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.

(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.

(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.

(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;

(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;

(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.

(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.

The following table sets forth the compensation earned by our non-employee directors for 2018:

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.

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.

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”).

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:

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth information regarding the beneficial ownership of our common stock as of February 1, 2019 (unless otherwise indicated) held by:

TRC owns all of the outstanding Partnership common units of the Partnership. As of February 1, 2019, none of our directors or executive officers owned any Preferred Shares of the Company or Preferred Units of the Partnership.

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 our common stock outstanding on February 1, 2019.

The following table sets forth certain information as of December 31, 2018 regarding our long-term incentive plans, under which our common stock is authorized for issuance to employees, consultants and directors of us, the general partner and their affiliates. Our sole equity compensation plan, under which we will make equity grants, is our Amended and Restated 2010 Stock Incentive Plan, which was approved by our stockholders on May 22, 2017.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Our only cash generating assets consist of our interests in the Partnership, which consist of (i) a 2.0% general partner interest in the Partnership and (ii) all of the outstanding common units of the Partnership.

Under the terms of the Partnership Agreement, the Partnership reimburses us for all direct and indirect expenses, as well as expenses otherwise allocable to the Partnership in connection with the operation of the Partnership’s business, incurred on the Partnership’s behalf, which includes 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 the Partnership’s benefit. We perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. The general partner determines the amount of general and administrative expenses to be allocated to the Partnership in accordance with the Partnership Agreement. Other than our direct costs of being a reporting company, so long as our only cash-generating asset consists of our interests in the Partnership, substantially all of our general and administrative costs have been and will continue to be allocated to the Partnership.

We are not restricted, under the Partnership’s partnership agreement, from competing with the Partnership. We may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer the Partnership the opportunity to purchase or construct those assets.

The Partnership and the general partner have entered into indemnification agreements with each individual who was an independent director of the general partner prior to the TRC/TRP Merger. Each indemnification agreement provides that each of the Partnership and the general partner 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 the Partnership or the general partner is jointly liable in the proceeding with the indemnitee, the Partnership and the general partner 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 the Partnership or the general partner on the one hand and indemnitee on the other in the transaction giving rise to the proceeding.

Each indemnification agreement also provides that the Partnership and the general partner will indemnify and hold harmless the indemnitee against Expenses incurred for actions taken as a director or officer of the Partnership or the general partner or for serving at the request of the Partnership or the general partner 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. The indemnification agreement also provides that the Partnership and the general partner 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.

We have entered into parent indemnification agreements with each of our directors and officers, including directors and officers who serve or served as directors and/or officers of the general partner. Each parent indemnification agreement provides that we will indemnify and hold harmless each indemnitee for Expenses (as defined in the parent indemnification agreement) 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 indemnitee. If such indemnification is unavailable as a result of a court decision and if we and the indemnitee are jointly liable in the proceeding, we will contribute funds to the indemnitee for his or her Expenses in proportion to relative benefit and fault of us and indemnitee in the transaction giving rise to the proceeding.

Each parent indemnification agreement also provides that we will indemnify the indemnitee for monetary damages for actions taken as our director or officer or for serving at our request as a director or officer or another position at another corporation or enterprise, as the case may be but only if (i) the 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 our best interests and, in all other cases, not opposed to our best interests and (ii) in the case of a criminal proceeding, the indemnitee must have had no reasonable cause to believe that his or her conduct was unlawful. The parent indemnification agreement also provides that we 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.

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.

Rene R. Joyce, a director of Targa and of the Partnership’s 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.

Robert B. Evans, a director of Targa and of the Partnership’s 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 the Partnership’s 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.

Ershel C. Redd Jr., a director of Targa and of the Partnership’s 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.

Jennifer R. Kneale, Chief Financial Officer of Targa and of the Partnership’s 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 exist and may arise in the future as a result of the relationships between the general partner and its affiliates (including us), on the one hand, and the Partnership and its other limited partners, on the other hand. The directors and officers of the general partner have fiduciary duties to manage the general partner and us, if applicable, in a manner beneficial to our owners. At the same time, the general partner has a fiduciary duty to manage the Partnership in a manner beneficial to it and its unitholders. Please see “—Review, Approval or Ratification of Transactions with Related Persons” below for additional detail of how these conflicts of interest will be resolved.

Our policies and procedures for approval or ratification of transactions with “related persons” are not contained in a single policy or procedure. Instead, they are reflected in the general operation of our board of directors, consistent with past practice. We distribute and review a questionnaire to our executive officers and directors requesting information regarding, among other things, certain transactions with us in which they or their family members have an interest. Pursuant to our 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 us or any of our subsidiaries, unless the conflict is pre-approved by our board of directors.

Whenever a conflict arises between the general partner or its affiliates, on the one hand, and the Partnership or any other partner, on the other hand, the general partner will resolve that conflict. The Partnership’s partnership agreement contains provisions that modify and limit the general partner’s fiduciary duties to the Partnership’s unitholders. The partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

The general partner will not be in breach of its obligations under the partnership agreement or its duties to the Partnership or its unitholders if the resolution of the conflict is:

The general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. If the 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 the partnership agreement, the general partner or its conflicts committee may consider any factors they determine in good faith to consider when resolving a conflict. When the 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.

Messrs. Crisp, Redd, Tong, Evans, Joyce and Davis and Mses. Fulton and Bowman are our independent directors under the NYSE’s listing standards. Please see “Item 10. Directors, Executive Officers and Corporate Governance.” Our board of directors examined the commercial relationships between us and companies for whom our independent directors serve as directors or with whom family members of our independent directors have an employment relationship. The commercial relationships reviewed consisted of product and services purchases and product sales at market prices consistent with similar arrangements with unrelated entities.

We have engaged PricewaterhouseCoopers LLP as our independent principal accountant. The following table summarizes fees we were billed by PricewaterhouseCoopers LLP for independent auditing, tax and related services for each of the last two fiscal years:

The Audit Committee has approved the use of PricewaterhouseCoopers LLP as our independent principal accountant. All services provided by our independent principal accountant are subject to pre-approval by the Audit Committee. The Audit Committee is informed of each engagement of the independent principal accountant to provide services to us. All of the services of PricewaterhouseCoopers LLP for 2018 and 2017 described above were pre-approved by the Audit Committee.

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 F-1 in this Annual Report.

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.

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.

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 F-3.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Targa Resources Corp. 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 Series A Preferred Stock, 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 Company'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 Company 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 Company 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.

The Company'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 Company’s consolidated financial statements and on the Company'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 Company 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.

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.

	December 31, 2018			December 31, 2017
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	232.1		$	137.2
Trade receivables, net of allowances of $0.1 and $0.1 million at December 31, 2018 and December 31, 2017		865.5			827.6
Inventories		164.7			204.5
Assets from risk management activities		115.3			37.9
Other current assets		41.3			62.7
Total current assets		1,418.9			1,269.9
Property, plant and equipment		17,220.7			14,205.4
Accumulated depreciation		(4,292.3	)		(3,775.4	)
Property, plant and equipment, net		12,928.4			10,430.0
Intangible assets, net		1,983.2			2,165.8
Goodwill, net		46.6			256.6
Long-term assets from risk management activities		34.1			23.2
Investments in unconsolidated affiliates		490.5			221.6
Other long-term assets		36.5			21.5
Total assets	$	16,938.2		$	14,388.6

LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	1,737.3		$	1,186.9
Liabilities from risk management activities		33.6			79.7
Current debt obligations		1,027.9			350.0
Total current liabilities		2,798.8			1,616.6
Long-term debt		5,632.4			4,703.0
Long-term liabilities from risk management activities		3.1			19.6
Deferred income taxes, net		525.2			479.0
Other long-term liabilities		262.2			597.9
Contingencies (see Note 20)
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference, (1,200,000 shares authorized, 965,100 shares issued and outstanding), net of discount (see Note 12)		245.7			216.5
Owners' equity:
Targa Resources Corp. stockholders' equity:
Common stock ($0.001 par value, 300,000,000 shares authorized)		0.2			0.2
Issued Outstanding
December 31, 2018 232,456,283 231,790,530
December 31, 2017 218,152,620 217,566,980
Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, no shares issued and outstanding)		—			—
Additional paid-in capital		6,154.9			6,302.8
Retained earnings (deficit)		(130.4	)		(77.2	)
Accumulated other comprehensive income (loss)		94.3			(29.9	)
Treasury stock, at cost (665,753 shares as of December 31, 2018 and 585,640 shares as of December 31, 2017)		(39.6	)		(35.6	)
Total Targa Resources Corp. stockholders' equity		6,079.4			6,160.3
Noncontrolling interests in subsidiaries		1,391.4			595.7
Total owners' equity		7,470.8			6,756.0
Total liabilities, Series A Preferred Stock and owners' equity	$	16,938.2		$	14,388.6

	Year Ended December 31,
	2018			2017			2016
	(In millions, except per share amounts)
Revenues:
Sales of commodities (see Note 3)	$	9,278.7		$	7,751.1		$	5,626.8
Fees from midstream services (see Note 3)		1,205.3			1,063.8			1,064.1
Total revenues		10,484.0			8,814.9			6,690.9
Costs and expenses:
Product purchases (see Note 3)		8,238.2			6,906.1			4,922.9
Operating expenses		722.0			622.9			553.7
Depreciation and amortization expense		815.9			809.5			757.7
General and administrative expense		256.9			203.4			187.2
Impairment of property, plant and equipment		—			378.0			—
Impairment of goodwill		210.0			—			207.0
Other operating (income) expense		3.5			17.4			6.6
Income (loss) from operations		237.5			(122.4	)		55.8
Other income (expense):
Interest expense, net		(185.8	)		(233.7	)		(254.2	)
Equity earnings (loss)		7.3			(17.0	)		(14.3	)
Gain (loss) from financing activities		(2.0	)		(16.8	)		(48.2	)
Change in contingent considerations		8.8			99.6			0.4
Other, net		0.1			(2.6	)		0.8
Income (loss) before income taxes		65.9			(292.9	)		(259.7	)
Income tax (expense) benefit		(5.5	)		397.1			100.6
Net income (loss)		60.4			104.2			(159.1	)
Less: Net income (loss) attributable to noncontrolling interests		58.8			50.2			28.2
Net income (loss) attributable to Targa Resources Corp.		1.6			54.0			(187.3	)
Dividends on Series A Preferred Stock		91.7			91.7			72.6
Deemed dividends on Series A Preferred Stock		29.2			25.7			18.2
Net income (loss) attributable to common shareholders	$	(119.3	)	$	(63.4	)	$	(278.1	)

Net income (loss) per common share - basic	$	(0.53	)	$	(0.31	)	$	(1.80	)
Net income (loss) per common share - diluted	$	(0.53	)	$	(0.31	)	$	(1.80	)
Weighted average shares outstanding - basic		224.2			206.9			154.4
Weighted average shares outstanding - diluted		224.2			206.9			154.4

		Year Ended December 31,
		2018										2017												2016
		Pre-Tax			Related Income Tax				After Tax			Pre-Tax				Related Income Tax				After Tax				Pre-Tax				Related Income Tax			After Tax
		(In millions)
Net income (loss) attributable to Targa Resources Corp.								$		1.6									$		54.0									$		(187.3	)
Other comprehensive income (loss) attributable to Targa Resources Corp.
Commodity hedging contracts:
Change in fair value	$		132.5	$		(32.2	)			100.3	$		(28.8	)	$		13.5				(15.3	)	$		(127.3	)	$		48.5			(78.8	)
Settlements reclassified to revenues			38.4			(9.3	)			29.1			44.6				(20.9	)			23.7				(33.8	)			12.8			(21.0	)
Other comprehensive income (loss) attributable to Targa Resources Corp.			170.9			(41.5	)			129.4			15.8				(7.4	)			8.4				(161.1	)			61.3			(99.8	)
Comprehensive income (loss) attributable to Targa Resources Corp.										131.0											62.4											(287.1	)

Net income (loss) attributable to noncontrolling interests								$		58.8									$		50.2									$		28.2
Other comprehensive income (loss) attributable to noncontrolling interests
Commodity hedging contracts:
Change in fair value	$		—	$		—				—	$		—		$		—				—		$		23.7		$		—			23.7
Settlements reclassified to revenues			—			—				—			—				—				—				(11.2	)			—			(11.2	)
Other comprehensive income (loss) attributable to noncontrolling interests			—			—				—			—				—				—				12.5				—			12.5
Comprehensive income (loss) attributable to noncontrolling interests										58.8											50.2											40.7

Total
Net income (loss)								$		60.4									$		104.2									$		(159.1	)
Other comprehensive income (loss)
Commodity hedging contracts:
Change in fair value	$		132.5	$		(32.2	)			100.3	$		(28.8	)	$		13.5				(15.3	)	$		(103.6	)	$		48.5			(55.1	)
Settlements reclassified to revenues			38.4			(9.3	)			29.1			44.6				(20.9	)			23.7				(45.0	)			12.8			(32.2	)
Other comprehensive income (loss)			170.9			(41.5	)			129.4			15.8				(7.4	)			8.4				(148.6	)			61.3			(87.3	)

Total comprehensive income (loss)								$		189.8									$		112.6									$		(246.4	)

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK

									Retained			Accumulated
						Additional			Earnings			Other			Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(In millions, except shares in thousands)
Balance, December 31, 2015		56,020		$	0.1	$	1,457.4		$	26.9		$	5.7			426	$	(28.7	)	$	4,788.8		$	6,250.2		$	—
Compensation on equity grants, net of excess tax benefits		—			—		27.5			—			—			—		—			2.2			29.7			—
Distribution equivalent rights		—			—		(8.7	)		—			—			—		—			(0.2	)		(8.9	)		—
Shares issued under compensation program		364			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(88	)		—		—			—			—			88		(3.5	)		(0.1	)		(3.6	)		—
Issuance of common stock		12,562			—		572.7			—			—			—		—			—			572.7			—
Issuance of Series A preferred and detachable warrants		—			—		796.6			—			—			—		—			—			796.6			172.6
Exercise of warrants - shares settled		11,337			—		—			—			—			—		—			—			—			—
Series A Preferred Stock dividends
Dividends – $23.75 per share		—			—		—			(72.6	)		—			—		—			—			(72.6	)		—
Dividends in excess of retained earnings		—			—		(68.8	)		68.8			—			—		—			—			—			—
Deemed dividends - accretion of beneficial conversion feature		—			—		(18.2	)		—			—			—		—			—			(18.2	)		18.2
Common stock dividends
Dividends – $3.64 per share		—			—		—			(513.7	)		—			—		—			—			(513.7	)		—
Dividends in excess of retained earnings		—			—		(490.6	)		490.6			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(177.0	)		(177.0	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			43.3			43.3			—
Acquisition of TRP noncontrolling common interests, net of acquisition costs and deferred income taxes		104,526			0.1		3,183.7			—			55.8			—		—			(4,119.7	)		(880.1	)		—
Purchase of noncontrolling interests in subsidiary, net of tax impact		—			—		54.6			—			—			—		—			(102.2	)		(47.6	)		—
Other comprehensive income (loss)		—			—		—			—			(99.8	)		—		—			12.5			(87.3	)		—
Net income (loss)		—			—		—			(187.3	)		—			—		—			28.2			(159.1	)		—
Balance, December 31, 2016		184,721		$	0.2	$	5,506.2		$	(187.3	)	$	(38.3	)		514	$	(32.2	)	$	475.8		$	5,724.4		$	190.8
Impact of accounting standard adoption (see Note 3)		—			—		—			56.1			—			—		—			—			56.1			—
Compensation on equity grants		—			—		42.3			—			—			—		—			—			42.3			—
Distribution equivalent rights		—			—		(9.7	)		—			—			—		—			—			(9.7	)		—
Shares issued under compensation program		285			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(72	)		—		—			—			—			72		(3.4	)		—			(3.4	)		—
Issuance of common stock		32,633			—		1,644.4			—			—			—		—			—			1,644.4			—
Series A Preferred Stock dividends
Dividends – $23.75 per share		—			—		—			(91.7	)		—			—		—			—			(91.7	)		—
Dividends in excess of retained earnings		—			—		(91.7	)		91.7			—			—		—			—			—			—
Deemed dividends - accretion of beneficial conversion feature		—			—		(25.7	)		—			—			—		—			—			(25.7	)		25.7
Common stock dividends
Dividends – $3.64 per share		—			—		—			(749.4	)		—			—		—			—			(749.4	)		—
Dividends in excess of retained earnings		—			—		(749.4	)		749.4			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(59.4	)		(59.4	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			141.6			141.6			—
Purchase of noncontrolling interests in subsidiary, net of tax impact		—			—		(13.6	)		—			—			—		—			(12.5	)		(26.1	)		—
Other comprehensive income (loss)		—			—		—			—			8.4			—		—			—			8.4			—
Net income (loss)		—			—		—			54.0			—			—		—			50.2			104.2			—
Balance, December 31, 2017		217,567		$	0.2	$	6,302.8		$	(77.2	)	$	(29.9	)		586	$	(35.6	)	$	595.7		$	6,756.0		$	216.5

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK

									Retained			Accumulated
						Additional			Earnings			Other			Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(In millions, except shares in thousands)

Balance, December 31, 2017		217,567		$	0.2	$	6,302.8		$	(77.2	)	$	(29.9	)		586	$	(35.6	)	$	595.7		$	6,756.0		$	216.5
Impact of accounting standard adoption (see Note 3)		—			—		—			5.2			(5.2	)		—		—			—			—			—
Compensation on equity grants		—			—		56.3			—			—			—		—			—			56.3			—
Distribution equivalent rights		—			—		(13.7	)		—			—			—		—			—			(13.7	)		—
Shares issued under compensation program		401			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(80	)		—		—			—			—			80		(4.0	)		—			(4.0	)		—
Issuance of common stock		13,844			—		683.5			—			—			—		—			—			683.5			—
Exercise of warrants - share settled		59			—		—			—			—			—		—			—			—			—
Series A Preferred Stock dividends
Dividends – $23.75 per share		—			—		—			(91.7	)		—			—		—			—			(91.7	)		—
Dividends in excess of retained earnings		—			—		(31.7	)		31.7			—			—		—			—			—			—
Deemed dividends - accretion of beneficial conversion feature		—			—		(29.2	)		—			—			—		—			—			(29.2	)		29.2
Common stock dividends
Dividends – $3.64 per share		—			—		—			(813.1	)		—			—		—			—			(813.1	)		—
Dividends in excess of retained earnings		—			—		(813.1	)		813.1			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(82.0	)		(82.0	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			817.9			817.9			—
Acquisition of related party (see Note 18)		—			—		—			—			—			—		—			1.1			1.1			—
Purchase of noncontrolling interests in subsidiary		—			—		—			—			—			—		—			(0.1	)		(0.1	)		—
Other comprehensive income (loss)		—			—		—			—			129.4			—		—			—			129.4			—
Net income (loss)		—			—		—			1.6			—			—		—			58.8			60.4			—
Balance, December 31, 2018		231,791		$	0.2	$	6,154.9		$	(130.4	)	$	94.3			666	$	(39.6	)	$	1,391.4		$	7,470.8		$	245.7

	Year Ended December 31,
	2018			2017			2016
	(In millions)
Cash flows from operating activities
Net income (loss)	$	60.4		$	104.2		$	(159.1	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		10.8			11.5			14.9
Compensation on equity grants		56.3			42.3			29.7
Depreciation and amortization expense		815.9			809.5			757.7
Impairment of property, plant and equipment		—			378.0			—
Impairment of goodwill		210.0			—			207.0
Accretion of asset retirement obligations		3.7			3.9			4.6
Increase (decrease) in redemption value of mandatorily redeemable preferred interests		(72.1	)		3.3			(15.2	)
Deferred income tax expense (benefit)		5.5			(392.7	)		(37.8	)
Equity (earnings) loss of unconsolidated affiliates		(7.3	)		17.0			14.3
Distributions of earnings received from unconsolidated affiliates		20.8			12.5			4.1
Risk management activities		9.8			10.0			26.0
(Gain) loss on sale or disposition of business and assets		(0.1	)		15.9			6.1
(Gain) loss from financing activities		2.0			16.8			48.2
Change in contingent considerations included in Other expense (income)		(8.8	)		(99.6	)		(0.4	)
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets		(6.2	)		(20.1	)		(222.9	)
Inventories		(13.9	)		(73.2	)		(15.9	)
Accounts payable and other liabilities		57.2			100.2			176.1
Net cash provided by operating activities		1,144.0			939.5			837.4
Cash flows from investing activities
Outlays for property, plant and equipment		(3,114.8	)		(1,297.5	)		(562.1	)
Outlays for business acquisition, net of cash acquired		—			(570.8	)		—
Proceeds from sale of business and assets		256.9			2.7			4.8
Investments in unconsolidated affiliates		(282.0	)		(9.5	)		(4.4	)
Return of capital from unconsolidated affiliates		5.5			0.2			4.1
Other, net		(12.5	)		(17.8	)		(1.0	)
Net cash used in investing activities		(3,146.9	)		(1,892.7	)		(558.6	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facilities		2,235.0			2,701.0			2,322.0
Repayments of credit facilities		(1,555.0	)		(2,671.0	)		(2,617.0	)
Proceeds from borrowings under accounts receivable securitization facility		546.6			666.6			171.4
Repayments of accounts receivable securitization facility		(616.6	)		(591.6	)		(115.7	)
Proceeds from issuance of senior notes and term loan		1,000.0			750.0			1,000.0
Redemption of senior notes and term loan		—			(698.1	)		(1,852.2	)
Redemption of TPL senior notes		—			—			(13.3	)
Proceeds from issuance of common stock		689.0			1,660.4			577.3
Proceeds from issuance of preferred stock and warrants		—			—			994.1
Costs incurred in connection with financing arrangements		(24.7	)		(23.5	)		(71.4	)
Repurchase of shares and units under compensation plans		(4.0	)		(3.4	)		(3.6	)
Purchase of noncontrolling interests in subsidiary		(0.1	)		(12.5	)		(37.2	)
Contributions from noncontrolling interests		817.9			141.6			43.3
Distributions to noncontrolling interests		(70.7	)		(48.1	)		(26.7	)
Distributions to Partnership unitholders		(11.3	)		(11.3	)		(150.3	)
Dividends paid to common and Series A preferred shareholders		(908.3	)		(843.2	)		(565.9	)
Other, net		—			—			(0.3	)
Net cash provided by (used in) financing activities		2,097.8			1,016.9			(345.5	)
Net change in cash and cash equivalents		94.9			63.7			(66.7	)
Cash and cash equivalents, beginning of period		137.2			73.5			140.2
Cash and cash equivalents, end of period	$	232.1		$	137.2		$	73.5

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.

Targa Resources Corp. (“TRC”) is a publicly traded Delaware corporation formed in October 2005. Our common stock is listed on the New York Stock Exchange under the symbol “TRGP.” In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean our consolidated business and operations.

See Note 27 – Segment Information for certain financial information regarding our business segments.

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.

On February 17, 2016, we completed the transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement,” and such transactions, the “TRC/TRP Merger”), dated November 2, 2015, by and among us, the general partner of Targa Resources Partners LP (“the Partnership” or “TRP”), an indirect subsidiary of us, TRC and Spartan Merger Sub LLC, a subsidiary of us (“Merger Sub”) and we acquired indirectly all of the outstanding TRP common units that we and our 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.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by us or our subsidiaries was converted into the right to receive 0.62 shares of our common stock. We issued 104,525,775 shares of our common stock to third-party unitholders of the common units of the Partnership in exchange for all of the 168,590,009 outstanding common units of the Partnership that we previously did not own. No fractional shares were issued in the TRC/TRP Merger, and TRP common unitholders instead received cash in lieu of fractional shares. There were no changes to our other interests in the Partnership.

TRP’s 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding after the TRC/TRP Merger. The Preferred Units are listed on the NYSE under “NGLS PRA” and are publicly traded. The Preferred Units are reported as noncontrolling interests in our financial statements.

As we continued to control the Partnership after the TRC/TRP Merger, the resulting change in our ownership interest was accounted for as an equity transaction, which was reflected in our Consolidated Balance Sheets as a reduction of noncontrolling interests and a corresponding increase in common stock and additional paid in capital. The TRC/TRP Merger was a taxable exchange that resulted in a book/tax difference in the basis of the underlying assets acquired (our investment in TRP). The tax impact is presented as a reduction of additional paid-in capital consistent with the accounting for tax effects of transactions with noncontrolling interests. The financial effects of the TRC/TRP Merger is reflected as Acquisition of TRP noncontrolling common interests, net of acquisition costs and deferred income taxes in our Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for 2016.

The equity interests in TRP (which are consolidated in our financial statements) that were owned by the public prior to February 17, 2016 were reflected within “Noncontrolling interests” in our Consolidated Balance Sheets prior to the merger date. The earnings recorded by TRP that were attributed to its common units held by the public prior to February 17, 2016 are reflected within Net income attributable to noncontrolling interests in our Consolidated Statements of Operations for periods prior to the merger date.

On October 19, 2016, TRP executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), effective as of December 1, 2016. The Third A&R Partnership Agreement (i) eliminated the Incentive Distribution Rights (“IDRs”) held by the General Partner, and related distribution and allocation provisions, (ii) eliminated the Special GP Interest held by the General Partner, (iii) provided the ability to declare monthly distributions in addition to quarterly distributions, (iv) modified certain provisions relating to distributions from available cash, (v) eliminated the Class B Unit provisions and (vi) made changes to reflect the passage of time and removed provisions that were no longer applicable. In connection with the Third A&R Partnership Agreement, on December 1, 2016, TRP issued to the 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.

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.

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 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).

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.

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.

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.

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.

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 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 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 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.

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.

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.

Proceeds from the sale or contribution of certain receivables under the Partnership’s 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.

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.

We account for income taxes using the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences based on legislated tax rates during the periods that the timing differences are scheduled to reverse.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. 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 reported on a net basis 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.

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 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 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.

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.

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.

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.

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.

We award share-based compensation to employees, directors and non-management directors in the form of restricted stock, restricted stock units, and performance share units. Compensation expense on restricted stock, restricted stock units, and performance share unit 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 performance share unit 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 recognized in general and administrative expense over the requisite service period of each award. In addition, we account for forfeitures when they occur. We may withhold shares to satisfy employees’ tax withholding obligations on vested awards. The withheld shares are recorded by us in treasury stock at cost. Cash paid by us when directly withholding shares for tax-withholding purposes is classified as a financing activity on the statement of cash flows. All excess tax benefits and tax deficiencies related to share-based compensation are recognized as income tax benefit or expense in the income statement with the tax effects of exercised or vested awards treated as discrete items in the reporting period which they occur. Excess tax benefits are classified as an operating activity.

We account for earnings per share (“EPS”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock so long as it does not have an anti-dilutive effect on EPS. The dilutive effect is determined through the application of the treasury stock method. The assumed proceeds under the treasury stock method exclude windfall tax benefits. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic EPS.

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.

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.

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:

The following tables summarize the effects of adoption on our consolidated financial statements:

See Note 22 – Revenue for information regarding our performance obligations and Note 27 – Segment Information for further disaggregation of our revenues.

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.

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.

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.

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 16 – Derivative Instruments and Hedging Activities and Note 27 – Segment Information.

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220). The amendments in this update allow a reclassification of stranded tax effects in accumulated other comprehensive income as a result of the Tax Cuts and Jobs Act to retained earnings. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We early adopted the amendments on January 1, 2018, resulting in a reclassification of stranded tax effects, which were associated with our commodity hedges, of $5.2 million from accumulated other comprehensive income to retained earnings.

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.

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.

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.

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.

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.

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.

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 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.

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.

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.

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.

On March 1, 2017, we 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, we completed a public offering of 9,200,000 shares of our 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. We 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 $19.8 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:

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 17 – 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.

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).

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.

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.

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.

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.

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.

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.

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.

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 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.

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 17 – Fair Value Measurements.

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.

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 17 – 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.

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 27 – 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:

	Balance at December 31, 2015		Equity Earnings (Loss)			Cash Distributions (1)			Acquisition (Disposition)			Contributions		Balance at December 31, 2016
GCF	$	49.5	$	4.1		$	(7.5	)	$	—		$	—	$	46.1
T2 LaSalle		63.6		(5.2	)		—			—			0.2		58.6
T2 Eagle Ford		123.8		(9.4	)		—			—			4.2		118.6
T2 EF Cogen		22.0		(3.8	)		(0.7	)		—			—		17.5
Cayenne		—		—			—			—			—		—
GCX		—		—			—			—			—		—
Little Missouri 4		—		—			—			—			—		—
Agua Blanca		—		—			—			—			—		—
Total	$	258.9	$	(14.3	)	$	(8.2	)	$	—		$	4.4	$	240.8

	Balance at December 31, 2016		Equity Earnings (Loss)			Cash Distributions (1)			Acquisition (Disposition)			Contributions		Balance at December 31, 2017
GCF	$	46.1	$	12.4		$	(12.7	)	$	—		$	—	$	45.8
T2 LaSalle		58.6		(4.9	)		—			—			0.4		54.1
T2 Eagle Ford		118.6		(10.6	)		—			—			1.2		109.2
T2 EF Cogen		17.5		(13.9	)		—			—			0.3		3.9
Cayenne		—		—			—			5.0			3.6		8.6
GCX		—		—			—			—			—		—
Little Missouri 4		—		—			—			—			—		—
Agua Blanca		—		—			—			—			—		—
Total	$	240.8	$	(17.0	)	$	(12.7	)	$	5.0		$	5.5	$	221.6

	Balance at December 31, 2017		Equity Earnings (Loss)			Cash Distributions (1)(2)			Acquisition (Disposition)			Contributions (3)		Balance at December 31, 2018
GCF	$	45.8	$	16.8		$	(22.3	)	$	—		$	—	$	40.3
T2 LaSalle		54.1		(4.9	)		—			—			0.1		49.3
T2 Eagle Ford		109.2		(10.2	)		—			—			—		99.0
T2 EF Cogen		3.9		(1.8	)		—			(2.1	)		—		—
Cayenne		8.6		6.4			(4.0	)		—			5.6		16.6
GCX (4)		—		0.8			—			—			210.8		211.6
Little Missouri 4		—		—			(8.0	)		—			75.3		67.3
Agua Blanca		—		0.2			—			3.5			2.7		6.4
Total	$	221.6	$	7.3		$	(34.3	)	$	1.4		$	294.5	$	490.5

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):

Accounts payable and accrued liabilities includes $52.6 million and $50.4 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.

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:

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The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the year ended December 31, 2018:

As of December 31, 2018, we were in compliance with the covenants contained in our various debt agreements.

In June 2018, we entered into an agreement to amend the TRC Revolver to (a) remove certain lenders from the TRC Revolver and include other new lenders, (b) extend the maturity date of the TRC Revolver from February 2020 to June 2023 and (c) memorialize the prior prepayment in full of term loans. The available commitments of $670.0 million and our ability to request additional commitments of $200.0 million remained unchanged. The TRC Revolver continues to bear interest costs that are dependent on the consolidated leverage ratio of non-Partnership consolidated funded indebtedness to consolidated Adjusted EBITDA, as defined in the TRC Revolver, and the covenants remained substantially the same.

We are required to pay a commitment fee ranging from 0.375% to 0.5% (dependent upon the Company’s consolidated leverage ratio) on the daily average unused portion of the TRC Revolver. Loans under the TRC Revolver bear interest at either a base rate or LIBOR (at our option) plus (i) for revolving loans, a margin of 0.75% to 1.75% (in the case of base rate loans) or 1.75% to 2.75% (in the case of LIBOR loans), in each case based on our consolidated leverage ratio and (ii) for term loans, 3.75% (in the case of base rate loans) or 4.75% (in the case of LIBOR loans).

The TRC Revolver is secured by a pledge of the Company’s equity interests in the Partnership and requires us to maintain a consolidated leverage ratio (the ratio of consolidated funded non-partnership indebtedness to consolidated Adjusted EBITDA) of no more than 4.00 to 1.00 for each fiscal quarter. The TRC Revolver restricts our ability to pay dividends to shareholders if, on a pro forma basis after giving effect to such dividend, (a) any default or event of default has occurred and is continuing or (b) we are not in compliance with our consolidated leverage ratio as of the last day of the most recent test period. In addition, it includes 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.

We incurred a loss of $0.7 million to partially write off debt issuance costs associated with the TRC Revolver as a result of a change in syndicate members, pursuant to the TRC Revolver amendment. The remaining debt issuance costs, along with debt issuance costs incurred with this amendment, will be amortized on a straight-line basis over the TRC Revolver’s new term.

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 Partnership is 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 the Partnership’s 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 the Partnership’s non-credit-enhanced senior unsecured long-term debt ratings), in each case, 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s restricted subsidiaries.

The TRP Revolver requires the Partnership to maintain a total leverage ratio (the ratio of consolidated indebtedness to the Partnership’s 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 the Partnership 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 the Partnership may not incur second lien indebtedness or consummate an acquisition of, or investment in, any included unrestricted subsidiary that would cause the Partnership’s senior leverage ratio to exceed 4.00 to 1.00 and the Partnership may not redeem its preferred units if doing so would cause its senior leverage ratio to exceed 3.50 to 1.00.

The TRP Revolver also requires the Partnership 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 the Partnership’s 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, the Partnership’s 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 the Partnership’s 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, the Partnership 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.

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.

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 the Partnership and the Partnership’s restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver and the Partnership’s 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.

The Partnership’s senior unsecured notes and associated indenture agreements restrict the Partnership’s ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict the Partnership’s ability and the ability of certain of its 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.

The Partnership 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.

The Partnership 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.

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, the Partnership issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 (the “5% Senior Notes due 2028”). The Partnership used the net proceeds of $744.1 million after costs from this offering to redeem its 5% Senior Notes, reduce borrowings under its credit facilities, and for general partnership purposes.

In April 2018, the Partnership issued $1.0 billion aggregate principal amount of 5⅞% senior notes due April 2026 (the “5⅞% Senior Notes due 2026”). The Partnership used net proceeds of $991.9 million after costs from this offering to repay borrowings under its credit facilities and for general partnership purposes.

In January 2019, the Partnership 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 the Partnership’s 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.

In May 2016, we filed with the SEC a universal shelf registration statement that allows us to issue debt or equity securities (the “May 2016 Shelf”). The May 2016 Shelf will expire in May 2019. See Note 13 – Common Stock and Related Matters.

In March 2017, we repaid the entirety of the TRC Senior secured term loan in the amount of $160.0 million. The repayment resulted in write offs of $2.2 million of discount and $3.7 million of debt issuance costs, which are reflected as Loss from financing activities in our Consolidated Statements of Operations for the year ended December 31, 2017.

In June 2017, the Partnership redeemed its 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, the Partnership redeemed its 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, the Partnership repurchased on the open market a portion of its outstanding senior notes as follows:

During the years ended December 31, 2018 and 2017, the Partnership did not repurchase any of its outstanding senior notes on the open market.

We or the Partnership may retire or purchase various series of the Partnership’s 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.

Concurrently with the October 2016 Offering, the Partnership 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 the Partnership accepted for purchase all Tender Notes that were validly tendered as of the early tender date.

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.

Subsequent to the closing of the Tender Offers in October 2016, the Partnership 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, the Partnership 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.

The following table summarizes the debt repurchases and extinguishments that are included in our Consolidated Statements of Operations:

	2018		2017		2016
Premium over face value paid upon redemption:
Partnership 5% Senior Notes	$	—	$	—	$	16.9
Partnership 6⅝% Senior Notes		—		—		11.5
Partnership 6⅞% Senior Notes		—		—		18.0
Partnership 6⅝% TPL Notes		—		—		0.4
Partnership 6⅜% Senior Notes		—		8.9		—
Recognition of unamortized discount:
TRC Senior secured term loan		—		2.2		—
Partnership 6⅞% Senior Notes		—		—		19.5
Recognition of unamortized premium:
Partnership 6⅝% Senior Notes		—		—		(4.3	)
Partnership 6⅝% TPL Notes		—		—		(0.2	)
Loss (gain) on repurchase of debt:
Partnership 5% Senior Notes		—		—		1.8
Partnership 4⅛% Senior Notes		—		—		(6.4	)
Partnership 6⅝% Senior Notes		—		—		(2.8	)
Partnership 6⅞% Senior Notes		—		—		(0.8	)
Partnership 6⅜% Senior Notes		—		—		(2.6	)
Partnership 5¼% Senior Notes		—		—		(4.0	)
Partnership 4¼% Senior Notes		—		—		(7.7	)
Partnership 6¾% Senior Notes		—		—		(2.4	)
Write-off of debt issuance costs:
TRP Revolver		1.3		—		0.9
TRC Revolver		0.7		—		—
TRC Senior secured term loan		—		3.7		—
Partnership 5% Senior Notes		—		0.2		4.2
Partnership 4⅛% Senior Notes		—		—		0.4
Partnership 6⅞% Senior Notes		—		—		4.9
Partnership 6⅜% Senior Notes		—		1.8		0.2
Partnership 5¼% Senior Notes		—		—		0.2
Partnership 4¼% Senior Notes		—		—		0.3
Partnership 6¾% Senior Notes		—		—		0.2
Loss (gain) from financing activities	$	2.0	$	16.8	$	48.2

Our ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows:

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 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.

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 17 – Fair Value Measurements for additional discussion of the fair value methodology.

In the first quarter of 2016, TRC sold in two tranches to investors in a private placement 965,100 shares of Series A Preferred Stock (“Series A Preferred”) with detachable Series A Warrants exercisable into a maximum of 13,550,004 shares of our common stock and Series B Warrants exercisable into a maximum of 6,533,727 shares of our common stock (collectively the “Warrants”) for an aggregate purchase price of $994.1 million in cash.

The Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter. The Series A Preferred ranks senior to the common outstanding stock with respect to the payment of dividends and distributions in liquidation. The Series A Preferred has no mandatory redemption date, but is redeemable at our election in year six for a 10% premium to the liquidation preference and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed by the end of year twelve, the investors have the right to convert the Series A Preferred into TRC common stock at an exercise price of $20.77, which represented a 10% premium over the ten-day volume weighted average price (“VWAP”) prior to the February 18, 2016 signing date ($18.88) of the Purchase Agreement underlying the first tranche. If the investors do not elect to convert their Series A Preferred into TRC common stock, Targa has a right after year twelve to force conversion, but only if the VWAP for the ten preceding trading days is greater than 120% of the conversion price. A change of control provision could result in forced redemption, at the option of the investor, if the Series A Preferred could not otherwise remain outstanding or be replaced with a “substantially equivalent security.” The change of control premium to the liquidation preference on the redemption is initially 25% in year one, 20% in year two, 15% in year three, 10% in years four through six and 5% thereafter.

The Series A Preferred ranks senior to the common outstanding stock with respect to the payment of dividends and distributions in liquidation. The holders of Series A Preferred generally only have voting rights in certain circumstances, subject to certain exceptions, which include:

The Series A Preferred is a hybrid security and is viewed as a debt host for the purpose of evaluating embedded derivatives. Bifurcation of the Company’s redemption provision is not required because the redemption provision is clearly and closely related to the preferred debt host. Further, both our and the investors’ conversion options qualify for a derivatives scope exception under ASC 815 – Derivatives and Hedging (“ASC 815”) applicable to embedded features that are indexed to an entity’s equity, and that would be classified as equity if freestanding.

The Series A Preferred does not qualify as a liability instrument under ASC 480 – Distinguishing Liabilities from Equity, because it is not mandatorily redeemable. However, as SEC Regulation S-X, Rule 5-02-27 does not permit a probability assessment for a change of control provision our Series A Preferred must be presented as mezzanine equity between liabilities and shareholders’ equity on our Consolidated Balance Sheets because a change of control event, although not considered probable, could force the Company to redeem the Series A Preferred. At each balance sheet date, we must re-evaluate whether the Series A Preferred continues to qualify for treatment as an equity instrument. Under the terms of the Registration Rights Agreement covering common stock issuable upon conversion of the Series A Preferred (the “Preferred Registration Rights Agreement”), we will cause a registration statement with respect to the common shares underlying the Series A Preferred to be declared effective within 12 years of the March 16, 2016 issue date (the “Effective Date”), and pay liquidated damages in the event we fail to do so. A maximum of 46,466,057 common shares would be issued upon conversion of the Series A Preferred.

The detachable Warrants have a seven-year term and were exercisable beginning on September 16, 2016. They were issued in two series: Series A Warrants exercisable into a maximum number of 13,550,004 shares of our common stock with an exercise price of $18.88 and 6,533,727 Series B Warrants with an exercise price of $25.11. The Warrants may be net settled in cash or shares of common stock at the Company’s option. The Warrants qualify as freestanding financial instruments and meet the derivatives accounting scope exception in ASC 815 because they are indexed to our equity and otherwise meet the applicable criteria for equity classification. The portion of proceeds allocated to the Series A and Series B Warrants was recorded as additional paid-in capital. Pursuant to the terms of the Registration Rights Agreement covering the common stock issuable upon exercise of the Warrants (the “Warrants Registration Rights Agreement”), we filed a prospectus supplement on June 30, 2016 (the “Warrants Prospectus Supplement”) to our May 2016 Shelf and together with the Warrants Prospectus Supplement, the “Warrants Registration Statement”) for the registered resale by the selling stockholders described therein of 20,083,731 common shares, which is the maximum amount that could be issued upon conversion of the Warrants. We have granted certain demand and piggyback registration rights with respect to the holders of the common shares underlying the Warrants pursuant to the Warrants Registration Rights Agreement. Also under the Warrants Registration Rights Agreement, we are required to use commercially reasonable efforts to keep the Warrants Registration Statement to be continuously effective, until the earliest to occur of the following: (a) the date on which all Registrable Securities (as defined under the Warrants Registration Rights Agreement) covered by the Warrants Registration Statement have been distributed, (b) the date on which there are no longer any Registrable Securities outstanding and (c) the later of (1) the fourth anniversary of the date on which all Warrants have been converted into common shares and (2) if and only if any holder of Registrable Securities is an “affiliate” (as such term is defined in Rule 144 promulgated under the Securities Act) of the Company, the earlier of (x) the date on which such holder is no longer an “affiliate” (as such term is defined in Rule 144 promulgated under the Securities Act) of the Company and (y) March 16, 2028. See Note 13 – Common Stock and Related Matters for further information regarding the exercise of Warrants.

Net cash proceeds were allocated on a relative fair value basis to the Series A Preferred, Series A Warrants and Series B Warrants. The $178.1 million discount on the Series A Preferred created by the relative fair value allocation of proceeds, which is not subject to periodic accretion, would be reported as a deemed dividend in the event a redemption occurs. As described below, $614.4 million of the $787.1 million allocated to the Series A Preferred was allocated to additional paid-in capital to give effect to the intrinsic value of a beneficial conversion feature (“BCF”).

ASC 470-20-20 – Debt – Debt with conversion and Other Options (“ASC 470-20”) defines BCF as a nondetachable conversion feature that is in the money at the issuance date. We were required by ASC 470-20 to allocate a portion of the proceeds from the preferred offering equal to the intrinsic value of the BCF to additional paid-in capital. The intrinsic value of the BCF is calculated at the issuance date as the difference between the “accounting conversion price” and the market price of our common shares multiplied by the number of shares into which our Series A Preferred is convertible. The accounting conversion price of $17.02 per share is different from the $20.77 per share contractual conversion price. It is derived by dividing the proceeds allocated to the Series A Preferred by the number of common shares into which the Series A Preferred shares are convertible. We are recording the accretion of the $614.4 million Series A Preferred discount attributable to the BCF as a deemed dividend using the effective yield method over the twelve-year period prior to the effective date of the holders’ conversion right.

We have the right to redeem the Series A Preferred beginning after year five. As such, we can effectively mitigate or limit the Series A Preferred Holders’ ability to benefit from their conversion right after year twelve by paying either a $96.5 million (10%) redemption premium in year six or a $48.3 million (5%) redemption premium in years seven through twelve. In either case, the redemption premium would be significantly less than the $614.4 million BCF required to be recognized under GAAP. Upon exercise of our redemption rights, any previously recognized accretion of deemed dividends would be reversed in the period of redemption and reflected as income attributable to common shareholders in our Consolidated Statements of Operations and related per share amounts.

As of December 31, 2018, we have accrued cumulative preferred dividends of $22.9 million, which were paid on February 14, 2019. During the years ended December 31, 2018, 2017 and 2016, we paid $91.7 million, $91.7 million and $49.7 million of dividends at $23.75 per share to preferred shareholders, and recorded deemed dividends of $29.2 million, $25.7 million and $18.2 million attributable to accretion of the preferred discount resulting from the BCF accounting described above. Such accretion is included in the book value of the Series A Preferred Stock.

In May 2016, we entered into an equity distribution agreement under the May 2016 Shelf (the “May 2016 EDA”), pursuant to which we may sell, at our option, up to an aggregate of $500.0 million of our common stock. The common stock available for sale under the May 2016 EDA was registered pursuant to a registration statement on Form S-3 filed on May 23, 2016. During 2016, we issued 11,074,266 shares of common stock under the May 2016 EDA, receiving net proceeds of $494.0 million. In December 2016, we terminated the May 2016 EDA with a remaining amount of $2.2 million.

In December 2016, we entered into another equity distribution agreement under the May 2016 Shelf (the “December 2016 EDA”), pursuant to which we may sell, at our option, up to an aggregate of $750.0 million of our common stock. In connection with the December 2016 EDA we terminated the May 2016 EDA. During 2016, we issued 1,487,100 shares of common stock under the December 2016 EDA, receiving net proceeds of $78.7 million. For the year ended December 31, 2017, we issued 6,433,561 shares of common stock under our December 2016 EDA, receiving net proceeds of $343.1 million. For the year ended December 31, 2018, we issued 6,315,711 shares of common stock under our December 2016 EDA, receiving net proceeds of $318.6 million. In September 2018, we terminated the December 2016 EDA.

On May 9, 2017, we entered into an equity distribution agreement under the May 2016 Shelf (the “May 2017 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock. For the year ended December 31, 2017, no shares of common stock were issued under the May 2017 EDA. For the year ended December 31, 2018, we issued 7,527,902 shares of common stock under the May 2017 EDA, receiving net proceeds of $364.9 million. As of December 31, 2018, we have $382.1 million remaining under the May 2017 EDA.

On June 1, 2017, we completed a public offering of 17,000,000 shares of our common stock at a price to the public of $46.10, providing net proceeds after underwriting discounts, commissions and other expenses of $777.3 million. We used the net proceeds from this public offering to fund a portion of the capital expenditures related to the construction of the Grand Prix NGL pipeline, repay outstanding borrowings under our credit facilities, redeem the Partnership’s 6⅜% Senior Notes, and for general corporate purposes.

On September 20, 2018, we entered into an equity distribution agreement under the May 2016 Shelf (the “September 2018 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock. For the year ended December 31, 2018, no shares of common stock were issued under the September 2018 EDA.

On February 17, 2016, we completed the TRC/TRP Merger and issued 104,525,775 shares of our common stock in exchange for all of the outstanding common units of the Partnership that we previously did not own. See Note 2 – Basis of Presentation.

During 2016, 19,983,843 Warrants were exercised and net settled for 11,336,856 shares of common stock. For the year ended December 31, 2017, no detachable Warrants were exercised. As a result, Series A Warrants exercisable into a maximum of 67,392 shares of common stock and Series B Warrants exercisable into maximum of 32,496 shares of common stock were outstanding as of December 31, 2017. In the first quarter of 2018, the remaining 99,888 Warrants were exercised and net settled by us for 58,814 shares of common stock.

The following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2018, 2017 and 2016:

On February 17, 2016, TRC completed the TRC/TRP Merger, indirectly acquiring all of the outstanding common units not already owned by us and our subsidiaries. As a result of the TRC/TRP Merger, we own all of the Partnership’s outstanding common units.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by us or our subsidiaries was converted into the right to receive 0.62 shares of our common stock. We issued 104,525,775 shares of our common stock to third-party unitholders of the common units of the Partnership in exchange for all of the 168,590,009 outstanding common units of the Partnership that we 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, TRC caused the TRP common units to be delisted from the NYSE and deregistered under the Exchange Act. As a result of the completion of the TRC/TRP Merger, the TRP common units are no longer publicly traded. The Partnership’s 5,000,000 Preferred Units remain outstanding as preferred limited partner interests in the Partnership and continue to trade on the NYSE.

As a result of the TRC/TRP Merger, we are entitled to receive all Partnership distributions from available cash on the Partnership’s common units after payment of preferred unit distributions each quarter. The Partnership has discretion under the Third A&R Partnership Agreement as to whether to distribute all available cash for any period. See Note 2 – Basis of Presentation.

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, the Partnership 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 the 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 the 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 the Partnership issued to the 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.

Subsequent to the TRC/TRP Merger, 58,621,036 common units and 1,196,346 general partner units were issued for our 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 the general partner. In December 2016, we made a $190.0 million capital contribution to the Partnership which was allocated accordingly. For the years ended December 31, 2018, 2017 and 2016, we made total capital contributions to the Partnership of $600.0 million, $1,720.0 million and $1,381.0 million.

In October 2015, under the April 2013 Shelf, the Partnership 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, the Partnership sold an additional 600,000 Preferred Units at a price of $25.00 per unit. The Partnership received net proceeds after costs of approximately $121.1 million. The Partnership used the net proceeds from this offering to reduce borrowings under its senior secured credit facility and for general partnership purposes. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”

Distributions on the Partnership’s 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 the Partnership’s general partner. Distributions on the Preferred Units will be payable out of amounts legally available 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%.

At any time on or after November 1, 2020, the Partnership 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, the Partnership (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 the Partnership does 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 the Partnership Agreement. If the Partnership exercises (or a third party with our prior written consent exercises) its redemption rights relating to any Preferred Units, the holders of those Preferred Units 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 the Partnership Agreement.

As of December 31, 2018, the Partnership has 5,000,000 Preferred Units outstanding. The Partnership paid $11.3 million of distributions each year to the Preferred Unitholders for 2018, 2017 and 2016. The Preferred Units are reported as noncontrolling interests in our financial statements.

In January and February 2019, the board of directors of the general partner of the Partnership 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.

The following table sets forth a reconciliation of net income and weighted average shares outstanding (in millions) used in computing basic and diluted net income per common share:

The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shares would have been anti-dilutive (in millions on a weighted-average basis):

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:

		Gross Presentation								Pro Forma Net Presentation
December 31, 2018		Asset		Liability			Collateral			Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	100.0	$	(33.6	)	$	(14.2	)	$	70.0	$	(17.8	)
	Counterparties without offsetting positions - assets		15.3		-			-			15.3		-
	Counterparties without offsetting positions - liabilities		-		-			-			-		-
			115.3		(33.6	)		(14.2	)		85.3		(17.8	)
Long Term Position
	Counterparties with offsetting positions or collateral		8.9		(3.1	)		-			5.9		(0.1	)
	Counterparties without offsetting positions - assets		25.2		-			-			25.2		-
	Counterparties without offsetting positions - liabilities		-		-			-			-		-
			34.1		(3.1	)		-			31.1		(0.1	)
Total Derivatives
	Counterparties with offsetting positions or collateral		108.9		(36.7	)		(14.2	)		75.9		(17.9	)
	Counterparties without offsetting positions - assets		40.5		-			-			40.5		-
	Counterparties without offsetting positions - liabilities		-		-			-			-		-
		$	149.4	$	(36.7	)	$	(14.2	)	$	116.4	$	(17.9	)

		Gross Presentation								Pro Forma Net Presentation
December 31, 2017		Asset		Liability			Collateral			Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	37.9	$	(74.7	)	$	22.9		$	13.8	$	(27.7	)
	Counterparties without offsetting positions - assets		-		-			-			-		-
	Counterparties without offsetting positions - liabilities		-		(5.0	)		-			-		(5.0	)
			37.9		(79.7	)		22.9			13.8		(32.7	)
Long Term Position
	Counterparties with offsetting positions or collateral		23.2		(17.3	)		-			14.8		(8.9	)
	Counterparties without offsetting positions - assets		-		-			-			-		-
	Counterparties without offsetting positions - liabilities		-		(2.3	)		-			-		(2.3	)
			23.2		(19.6	)		-			14.8		(11.2	)
Total Derivatives
	Counterparties with offsetting positions or collateral		61.1		(92.0	)		22.9			28.6		(36.6	)
	Counterparties without offsetting positions - assets		-		-			-			-		-
	Counterparties without offsetting positions - liabilities		-		(7.3	)		-			-		(7.3	)
		$	61.1	$	(99.3	)	$	22.9		$	28.6	$	(43.9	)

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 the Partnership’s 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 17 – Fair Value Measurements and Note 27 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

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.

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.

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:

Contingent consideration liabilities related to business acquisitions are carried at fair value.

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:

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:

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:

__________________________________________________________________________________________________________________________________

We provide general and administrative and other services to the Partnership, associated with the Partnership’s existing assets and assets acquired from third parties. The Partnership Agreement between the Partnership and us, as general partner of the Partnership, governs the reimbursement of costs incurred on the behalf of the Partnership.

The employees supporting the Partnership’s operations are employees of us. The Partnership reimburses us for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to the Partnership’s assets, and for the provision of various general and administrative services for the benefit of the Partnership. We perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Since October 1, 2010, after the final conveyance of assets by us to the Partnership, substantially all of our general and administrative costs have been and will continue to be allocated to the Partnership, other than (1) costs attributable to our status as a separate reporting company and (2) until March 2018, our costs of providing management and support services to certain unaffiliated spun-off entities.

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.

Since March 2018, Sajet has been accounted for on a consolidated basis in our consolidated financial statements.

Future non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter:

We and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We and the Partnership are also parties 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.

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.

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.

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.

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.

We are exposed to changes in interest rates, primarily as a result of variable rate borrowings under the TRC Revolver, the TRP Revolver, and the Securitization Facility.

We maintain coverage in various insurance programs, which provides us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations. Management believes that we have 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, we 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.

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 27 – Segment Information.

Components of the federal and state income tax provisions for the periods indicated are as follows:

Our deferred income tax assets and liabilities at December 31, 2018 and 2017 consist of differences related to the timing of recognition of certain types of costs as follows:

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.

As a result of the TRC/TRP Merger, TRC acquired all of the common units of the Partnership owned by the public. In exchange for said units, TRC transferred its stock with a fair market value as of the close of business February 16, 2016, of approximately $1.8 billion and TRC assumed TRP's liabilities of approximately $5.4 billion, resulting in a purchase price of $7.3 billion. The transaction constituted a taxable sale, which resulted in an adjustment to the tax basis in the underlying assets deemed acquired in the common partnership unit acquisition. A deferred tax liability of approximately $865.0 million related to the book tax basis difference in this investment was recorded, computed as $4.1 billion book basis in excess of $1.8 billion tax basis at TRC's statutory rate of 37.34% at the time of the transaction.

As of December 31, 2018, we have total net operating loss carryforwards of $2.7 billion, $1.7 billion of which expire between 2036 and 2037 and $1.0 billion which will not expire, but is limited to offset 80% of taxable income per year. Management believes it more likely than not that the deferred tax asset will be fully utilized.

Set forth below is the reconciliation between our income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in our Consolidated Statements of Operations for the periods indicated:

We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves for uncertain income tax positions have been recorded.

	Year Ended December 31,
	2018			2017			2016
Cash:
Interest paid, net of capitalized interest (1)	$	217.2		$	212.2		$	282.0
Income taxes paid, net of refunds		(0.5	)		(67.5	)		(10.6	)
Non-cash investing activities:
Deadstock commodity inventory transferred to property, plant and equipment	$	49.0		$	9.0		$	17.4
Impact of capital expenditure accruals on property, plant and equipment		216.2			205.4			27.6
Transfers from materials and supplies inventory to property, plant and equipment		12.7			3.6			2.4
Contribution of property, plant and equipment to investments in unconsolidated affiliates		16.0			1.0			—
Change in ARO liability and property, plant and equipment due to revised cash flow estimate		1.8			3.1			(9.1	)
Property, plant and equipment received in asset exchange		24.1			—			—
Receivable for asset exchange		15.0			—			—
Asset received related to conveyance of ownership interest in investment in unconsolidated affiliate		3.0			—			—
Non-cash financing activities:
Reduction of Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements	$	13.7		$	9.7		$	8.7
Allocation of Series A Preferred Stock net book value of BCF to additional paid-in capital		—			—			614.4
Accrued dividends of Series A Preferred Stock		—			—			22.9
Accretion of deemed dividends on Series A Preferred Stock		29.2			25.7			18.2
Transfer within additional paid-in capital for exercise of Warrants		0.9			—			181.5
Impact of accounting standard adoption recorded in retained earnings		5.2			56.1			—
Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures):
Contingent consideration recorded at the acquisition date	$	—		$	416.3		$	—
Non-cash balance sheet movements related to the purchase of noncontrolling interests in subsidiary (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures):
Additional paid-in capital	$	—		$	(13.9	)	$	65.0
Deferred tax liability		—			13.9			—
Noncontrolling interests		—			—			(65.0	)
Non-cash balance sheet movements related to the TRC/TRP Merger:
Prepaid transaction costs reclassified in the additional paid-in capital		—			—			4.5
Issuance of common stock		—			—			0.1
Additional paid-in capital		—			0.3			3,207.5
Accumulated other comprehensive income		—			—			55.8
Noncontrolling interests		—			—			(4,119.7	)
Deferred tax liability		—			(0.3	)		856.3
Non-cash balance sheet movements related to acquisition of related party:
Noncontrolling interest	$	1.1		$	—		$	—

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, we 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 our common stock to our outside directors. In 2018, 2017 and 2016, we 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, we 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 – In 2018, 2017 and 2016, we issued 112,438, 84,221 and 153,252 shares of restricted stock awards in lieu of cash bonuses in the form of RSUs for our 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.

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.

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.

In 2007, both we and the Partnership 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 us or our affiliates. The awards under this plan included performance units, phantom units and director grants. The Partnership 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, we 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 we assumed all Partnership obligations associated with the Plan existing prior to its 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.

The performance units granted under the TRP LTIP were linked to the performance of the Partnership’s 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 the 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 DERs 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.

In 2015, the Partnership granted phantom units under the LTIP to various employees of Targa. These phantom units were denominated with respect to its common units, but not otherwise linked to the performance of its 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.

In connection with the APL merger in 2015, the Partnership 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.

Starting in 2012, the common units granted to the Partnership’s 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.

The TRC/TRP Merger did not trigger the acceleration of any time-based vesting of any of the Partnership’s 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 the Partnership. All such outstanding awards were converted into comparable time-based RSUs based on our 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:

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 DERs will ultimately be equal to the cash paid to the grantee upon vesting. However, throughout the vesting period we 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.

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.

Pursuant to ASU 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting, tax benefits of dividends on share-based payment awards should be recognized as income tax benefits or expenses in the income statement. We adopted the applicable amendments in the second quarter of 2016 and recognized $0.7 million, $3.1 million and $0.5 million tax deficiencies as income tax expenses for the years ended December 31, 2018, 2017 and 2016.

In January 2019, the Compensation Committee of the Targa board of directors made the following awards under the 2010 TRC Plan.

We have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). We also contribute an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. We made contributions to the 401(k) plan totaling $19.5 million, $16.5 million and $14.4 million during 2018, 2017, and 2016.

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.

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.

The following table shows our consolidated revenues by product and service for the periods presented:

The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:

Our results of operations by quarter for the years ended December 31, 2018 and 2017 were as follows:

The condensed parent only financial statements represent the financial information required by Rule 5-04 of the Securities and Exchange Commission Regulation S-X for Targa Resources Corp.

In the condensed financial statements, Targa’s investments in consolidated subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the consolidated subsidiaries are recorded in the balance sheets. The income (loss) from operations of the consolidated subsidiaries is reported as equity in income (loss) of consolidated subsidiaries. Other comprehensive income has been adjusted for Targa’s share of the investees’ currently reported other comprehensive income.

A substantial amount of Targa’s operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Targa’s consolidated financial statements, which begin on page F-1 in this Annual Report.

Delaware		20-3701075
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

811 Louisiana Street, Suite 2100, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

Facility	% Owned		Gross Capacity (MBbl/d) (1)		Gross Throughput 2018 (MBbl/d)
Operated Facilities:
Lake Charles Fractionator (Lake Charles, LA) (2)		100.0		55.0		7.1
Cedar Bayou Fractionator (Mont Belvieu, TX) (3)		88.0		493.0		405.7
Targa LSNG Hydrotreater (Mont Belvieu, TX)		100.0		35.0
LSNG treating volumes						35.2
Benzene treating volumes (4)						2.6
Non-operated Facilities:
Gulf Coast Fractionator (Mont Belvieu, TX)		38.8		125.0		116.4

Facility	% Owned	Location	Description	Throughput for 2018 (MMgal) (1)		Usable Storage Capacity (MMgal)
Calvert City Terminal	100	Marshall County, KY	Propane terminal		9.5		0.1
Greenville Terminal	100	Washington County, MS	Marine propane terminal		20.8		1.5
Port Everglades Terminal	100	Broward County, FL	Marine propane terminal		15.4		1.6
Tyler Terminal	100	Smith County, TX	Propane terminal		13.9		0.2
Abilene Transport (2)	100	Taylor County, TX	Raw NGL transport terminal		24.5		0.1
Bridgeport Transport (2)	100	Jack County, TX	Raw NGL transport terminal		89.0		0.1
Gladewater Transport (2)	100	Gregg County, TX	Raw NGL transport terminal		5.4		0.3
Chattanooga Terminal	100	Hamilton County, TN	Propane terminal		13.9		0.9
Sparta Terminal	100	Sparta County, NJ	Propane terminal		15.0		0.2
Hattiesburg Terminal (3)	50	Forrest County, MS	Propane terminal		411.9		179.8
Winona Terminal	100	Flagstaff County, AZ	Propane terminal		11.0		0.3
Jacksonville Transload (4)	100	Duval County, FL	Butane transload		1.6		—
Fort Lauderdale Transload (4)	100	Broward County, FL	Butane transload		1.8		—
Eagle Lake Transload (4)	100	Polk County, FL	Butane/propane transload		4.6		—

Period		Total number of shares withheld (1)				Average price per share				Total number of shares purchased as part of publicly announced plans				Maximum number of shares that may yet to be purchased under the plan
October 1, 2018 - October 31, 2018			29		$		58.51				—				—

	Natural Gas $/MMBtu (1)		Illustrative Targa NGL $/gal (2)		Crude Oil $/Bbl (3)
2018
4th Quarter	$	3.66	$	0.69	$	58.83
3rd Quarter		2.91		0.88		69.50
2nd Quarter		2.80		0.75		67.90
1st Quarter		2.99		0.71		62.89
2018 Average		3.09		0.76		64.78

2017
4th Quarter	$	2.93	$	0.74	$	55.39
3rd Quarter		2.99		0.63		48.19
2nd Quarter		3.19		0.55		48.29
1st Quarter		3.31		0.61		51.86
2017 Average		3.11		0.63		50.93

2016
4th Quarter	$	2.98	$	0.53	$	47.73
3rd Quarter		2.81		0.45		44.94
2nd Quarter		1.95		0.46		45.59
1st Quarter		2.09		0.36		33.45
2016 Average		2.46		0.45		42.93

Title of each class		Name of each exchange on which registered
Common Stock		New York Stock Exchange


Large accelerated filer	☑	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

PART I

Item 1. Business.	4

Item 1A. Risk Factors.	33

Item 1B. Unresolved Staff Comments.	53

Item 2. Properties.	53

Item 3. Legal Proceedings.	53

Item 4. Mine Safety Disclosures.	53

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	54

Item 6. Selected Financial Data.	56

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.	57

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.	84

Item 8. Financial Statements and Supplementary Data.	88

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	88

Item 9A. Controls and Procedures.	88

Item 9B. Other Information.	88

PART III

Item 10. Directors, Executive Officers and Corporate Governance.	89

Item 11. Executive Compensation.	95

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	124

Item 13. Certain Relationships and Related Transactions, and Director Independence.	126

Item 14. Principal Accounting Fees and Services.	130

PART IV

Item 15. Exhibits, Financial Statement Schedules.	131

Item 16. Form 10-K Summary.	141

SIGNATURES

Signatures	142

Bbl		Barrels (equal to 42 U.S. gallons)
BBtu		Billion British thermal units
Bcf		Billion cubic feet
Btu		British thermal units, a measure of heating value
/d		Per day
GAAP		Accounting principles generally accepted in the United States of America
gal		U.S. gallons
LIBOR		London Interbank Offered Rate
LPG		Liquefied petroleum gas
MBbl		Thousand barrels
MMBbl		Million barrels
MMBtu		Million British thermal units
MMcf		Million cubic feet
MMgal		Million U.S. gallons
NGL(s)		Natural gas liquid(s)
NYMEX		New York Mercantile Exchange
NYSE		New York Stock Exchange
SCOOP		South Central Oklahoma Oil Province
STACK		Sooner Trend, Anadarko, Canadian and Kingfisher

	Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations			Consolidated Operating Margin
	(In millions)
2018	$	968.4	$	592.5	$	(37.1	)	$	—		$	1,523.8
2017		783.8		511.8		(9.6	)		(0.1	)		1,285.9
2016		577.1		574.4		62.9			(0.1	)		1,214.3

	February 21, 2019
	(In millions)
	TRC			TRP			Consolidated Total
Cash on hand	$	17.8		$	283.2		$	301.0
Total availability under the TRC Revolver		670.0			—			670.0
Total availability under the TRP Revolver		—			2,200.0			2,200.0
Total availability under the Securitization Facility		—			378.0			378.0
		687.8			2,861.2			3,549.0

Less: Outstanding borrowings under the TRC Revolver		(450.0	)		—			(450.0	)
Outstanding borrowings under the TRP Revolver		—			(400.0	)		(400.0	)
Outstanding borrowings under the Securitization Facility		—			(378.0	)		(378.0	)
Outstanding letters of credit under the TRP Revolver		—			(71.7	)		(71.7	)
Total liquidity	$	237.8		$	2,011.5		$	2,249.3

Three Months Ended	Date Paid or To Be Paid		Total Common Dividends Declared			Amount of Common Dividends Paid or To Be Paid			Accrued Dividends (1)			Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
2018
December 31, 2018	February 15, 2019	$		215.2	$		211.2	$		4.0	$		0.91000
September 30, 2018	November 15, 2018			212.5			208.6			3.9			0.91000
June 30, 2018	August 15, 2018			208.9			205.2			3.7			0.91000
March 31, 2018	May 16, 2018			203.1			199.7			3.4			0.91000

	Fair Value		Result of 10% Price Decrease		Result of 10% Price Increase
Natural gas	$	34.1	$	56.2	$	12.2
NGLs		57.1		99.2		15.2
Crude oil		21.5		33.3		9.9
Total	$	112.7	$	188.7	$	37.3

Name	Age	Position
Joe Bob Perkins	58	Chief Executive Officer and Director
James W. Whalen	77	Executive Chairman of the Board and Director
Michael A. Heim	70	Vice Chairman of the Board and Director
Matthew J. Meloy	41	President
Jeffrey J. McParland	64	President – Administration
Patrick J. McDonie	58	President – Gathering and Processing
D. Scott Pryor	56	President – Logistics and Marketing
Robert M. Muraro	42	Chief Commercial Officer
Jennifer R. Kneale	40	Chief Financial Officer
Paul W. Chung	58	Executive Vice President, General Counsel and Secretary
Clark White	59	Executive Vice President – Engineering and Operations
John R. Klein	68	Senior Vice President and Chief Accounting Officer
Rene R. Joyce	71	Director
Charles R. Crisp	71	Director
Chris Tong	62	Director
Ershel C. Redd Jr.	71	Director
Laura C. Fulton	55	Director
Waters S. Davis, IV	65	Director
Robert B. Evans	70	Director
Beth A. Bowman	62	Director


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


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


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)


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)

	Prior Salary		Base Salary Effective March 1, 2018		Percent Increase (approximate)
Joe Bob Perkins	$	750,000	$	850,000		13	%
Matthew J. Meloy		475,000		525,000		11	%
Jennifer R. Kneale		245,000		350,000		43	%
Patrick J. McDonie		425,000		475,000		12	%
D. Scott Pryor		425,000		475,000		12	%
Paul W. Chung		500,000		525,000		5	%

	Target Bonus Percentage (as a % of Base Salary)			Target Bonus Amount
Joe Bob Perkins		200	%	$	1,700,000
Matthew J. Meloy		125	%		656,250
Jennifer R. Kneale		60	%		210,000
Patrick J. McDonie		100	%		475,000
D. Scott Pryor		100	%		475,000
Paul W. Chung		100	%		525,000


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 a 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

	Target Bonus Amount ($)		Individual Performance Factor		Company Performance Factor		Total Bonus Amount To Be Received		Cash Amount to be Paid ($)		Approximate Value and Number of Restricted Stock Units Awarded (#)
Joe Bob Perkins	$	1,700,000		1.00		1.7	$	2,890,000	$	—	70,419 RSUs
Matthew J. Meloy		656,250		1.00		1.7		1,115,625		1,115,625		—
Jennifer R. Kneale		210,000		1.25		1.7		446,250		446,250		—
Patrick J. McDonie		475,000		1.00		1.7		807,500		807,500		—
D. Scott Pryor		475,000		1.00		1.7		807,500		807,500		—
Paul W. Chung		525,000		1.00		1.7		892,500		892,500		—

	Percentage of Base Salary			Total Dollar Value of Long-Term Equity Incentive Awards
Joe Bob Perkins		550	%	$	4,675,000
Matthew J. Meloy		500	%		2,625,000
Jennifer R. Kneale		225	%		787,500
Patrick J. McDonie		250	%		1,187,500
D. Scott Pryor		250	%		1,187,500
Paul W. Chung		250	%		1,312,500


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.

	Effective March 1, 2019		Current Salary
Joe Bob Perkins	$	900,000	$	850,000
Matthew J. Meloy		600,000		525,000
Jennifer R. Kneale		400,000		350,000
Patrick J. McDonie		500,000		475,000
D. Scott Pryor		500,000		475,000
Paul W. Chung		560,000		525,000

	Effective March 1, 2019			Current Percentage
Joe Bob Perkins		230	%		200	%
Matthew J. Meloy		200	%		125	%
Jennifer R. Kneale		100	%		60	%
Patrick J. McDonie		100	%		100	%
D. Scott Pryor		100	%		100	%
Paul W. Chung		100	%		100	%

	2019 Percentage			Current Percentage
Joe Bob Perkins		725	%		550	%
Matthew J. Meloy		500	%		500	%
Jennifer R. Kneale		400	%		225	%
Patrick J. McDonie		325	%		250	%
D. Scott Pryor		325	%		250	%
Paul W. Chung		250	%		250	%


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.

Name	401(k) and Profit Sharing Plan		Dollar Value of Life Insurance Premiums		Total
Joe Bob Perkins	$	22,000	$	1,310	$	23,310
Matthew J. Meloy		22,000		1,037		23,037
Jennifer R. Kneale		22,000		535		22,535
Patrick J. McDonie		22,000		928		22,928
D. Scott Pryor		22,000		928		22,928
Paul W. Chung		22,000		1,092		23,092

	Stock Awards
Name	Number of Shares That Have Not Vested (1)		Market Value of Shares That Have Not Vested (2)		Performance Share Units: Number of Unearned Units That Have Not Vested (3)		Performance Share Units: Market or Payout Value of Unearned Units That Have Not Vested (4)
Joe Bob Perkins		297,040	$	10,699,381		90,911	$	3,274,623
Matthew J. Meloy		147,157		5,300,595		45,716		1,646,699
Jennifer R. Kneale		65,984		2,376,744		9,894		356,373
Patrick J. McDonie		107,090		3,857,382		23,580		849,352
D. Scott Pryor		109,852		3,956,869		23,580		849,352
Paul W. Chung		92,361		3,326,843		28,555		1,028,551

	January 20, 2017 Award				January 17, 2018 Award
	Awards Granted		(a) Adjusted for Performance Factor (TSR)		Awards Granted		(b) Adjusted for Performance Factor (TSR)
Joe Bob Perkins		25,742		32,178		46,987		58,734
Matthew J. Meloy		10,190		12,738		26,383		32,979
Jennifer R. Kneale		—		—		7,915		9,894
Patrick J. McDonie		6,929		8,661		11,935		14,919
D. Scott Pryor		6,929		8,661		11,935		14,919
Paul W. Chung		9,653		12,066		13,191		16,489

	Stock Awards
Name	Number of Shares Acquired on Vesting		Value Realized on Vesting (1)
Joe Bob Perkins		69,856	$	2,937,702
Matthew J. Meloy		8,942		448,329
Jennifer R. Kneale		490		25,299
Patrick J. McDonie		12,535		627,431
D. Scott Pryor		8,774		440,239
Paul W. Chung		11,530		578,084

Name	Change in Control (No Termination)		Qualifying Termination Following Change in Control		Termination by us without Cause		Termination for Death or Disability
Joe Bob Perkins	$	15,552,017	$	23,244,506		—	$	15,552,017
Matthew J. Meloy		7,822,416		11,422,680		—		7,822,416
Jennifer R. Kneale		3,172,359		4,852,359		—		3,172,359
Patrick J. McDonie		5,433,894		8,340,408		—		5,433,894
D. Scott Pryor		5,564,586		8,471,100		—		5,564,586
Paul W. Chung		4,993,916		8,204,912		—		8,471,100

Name	Change in Control			Termination for Death or Disability
Joe Bob Perkins	$	15,552,017	(1)	$	15,552,017	(1)
Matthew J. Meloy		7,822,416	(2)		7,822,416	(2)
Jennifer R. Kneale		3,172,359	(3)		3,172,359	(3)
Patrick J. McDonie		5,433,894	(4)		5,433,894	(4)
D. Scott Pryor		5,564,586	(5)		5,564,586	(5)
Paul W. Chung		4,993,916	(6)		4,993,916	(6)

Name	Fees Earned or Paid in Cash		Stock Awards (1)		Total Compensation
Charles R. Crisp	$	122,000	$	118,120	$	240,120
Ershel C. Redd Jr.		95,500		118,120		213,620
Chris Tong		121,500		118,120		239,620
Laura C. Fulton		95,500		118,120		213,620
Waters S. Davis, IV		112,000		118,120		230,120
Rene R. Joyce		94,000		118,120		212,120
Robert B. Evans		97,000		118,120		215,120
Beth A. Bowman (2)		34,333		41,426		75,759