Item 1. Business.
Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”), to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. TRP is a leading provider of midstream natural gas and NGL services in the United States, with a growing presence in crude oil gathering and petroleum terminaling.
On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, “Buy-in Transaction”), by and among us, Targa Resources GP LLC (our “general partner”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”) pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP (the “TRC/TRP Merger”), with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.
At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.
Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
References to "units" refers to our units representing limited partner interests in the Partnership and not to the Preferred Units (as defined herein), and "unitholders" refers to the holders of units. As used herein, unless the context requires otherwise, the term "limited partner interests" refers to the units, the Preferred Units and the Incentive Distribution Rights (“IDRs”), collectively, and “limited partners” refers to the holders of limited partner interests.
Our Operations
We are engaged in the business of:
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gathering, compressing, treating, processing and selling natural gas;
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storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;
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gathering, storing and terminaling crude oil; and
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storing, terminaling and selling refined petroleum products.
To provide these services, we operate in two primary segments (previously referred to as divisions): (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).
Concurrent with the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure. The Gathering and Processing division was previously disaggregated into two reportable segments-(a) Field Gathering and Processing and (b) Coastal Gathering and Processing. The Logistics and Marketing division was previously disaggregated into two reportable segments-(a) Logistics Assets and (b) Marketing and Distribution. Management determined that the increase in activity within Field Gathering and Processing due to the acquisition by Targa of Atlas Energy LP (“ATLS”) and our acquisition of Atlas Pipeline Partners, L.P. (“APL”) (collectively, the “Atlas mergers”) coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team.
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; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain 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 operations are generally connected to and supplied in part by our Gathering and Processing operations and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington.
Our midstream natural gas and NGL services footprint was initially established through several acquisitions from Targa, totaling $3.1 billion, that occurred from 2007 through 2010. Since the completion of the final acquisitions from Targa in 2010, we have grown substantially. The expansion of our business has been fueled by a combination of major organic growth investments in our businesses and third-party acquisitions. 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”) and our 2015 acquisition of APL (renamed by us as Targa Pipeline Partners, L.P. or “TPL”). In these transactions we acquired (1) natural gas gathering, processing and treating assets in North Texas, West Texas, South Texas, Oklahoma, North Dakota, New Mexico and the Louisiana Gulf Coast, (2) crude oil gathering and terminal assets in North Dakota, and (3) NGL assets consisting of fractionation, transport, storage and terminaling facilities, low sulfur natural gas treating facilities (“LSNG”), pipeline transportation and distribution assets, propane storage and truck terminals primarily located near Houston, Texas and in Lake Charles, Louisiana.
Organic Growth Projects
We continue to invest significant capital to expand through organic growth projects. We have invested approximately $3.8 billion in growth capital expenditures since 2007, including approximately $0.5 billion in 2016. These expansion investments were distributed across our businesses, with 46% related to Logistics and Marketing and 54% to Gathering and Processing. We expect to continue to invest in both large and small organic growth projects in 2017. Assuming the closing of the Permian Acquisition (as defined below) occurs in the first quarter of 2017, we currently estimate that we will invest at least $700 million in growth capital expenditures (exclusive of outlays for business acquisitions) for announced projects in 2017.
Volatility of Commodity Prices
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. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Prices of oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related reduced activity levels from our customers. Beginning in the fourth quarter of 2014, oil, natural gas and NGL prices declined significantly primarily due to global supply and demand imbalances. Oil, natural gas and NGL prices continued to decline in 2015 and the first half of 2016, but have since experienced some recovery.
2016 Developments
Logistics and Marketing Segment Expansion
Cedar Bayou Fractionator Train 5
In June 2016, we commissioned an additional fractionator, Train 5, at our 88%-owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu, Texas. This expansion added 100 MBbl/d of fractionation capacity at CBF, and is 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 gross cost of Train 5 was approximately $331 million (our net cost was approximately $299 million).
Channelview Splitter
On December 27, 2015, we and an affiliate of Noble Group Ltd. (“Noble”) entered into a long-term, fee-based agreement (“Splitter Agreement”) under which Targa Terminals will build and operate a 35,000 barrel per day crude oil and condensate
splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”). The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter is expected to be completed by early 2018, and has an estimated total cost of approximately $140 million. As contemplated by the agreement entered into with Noble in December 2014 (the “December 2014 Agreement”), the Splitter Agreement completes and terminates the December 2014 Agreement, while retaining our economic benefits from that previous agreement. The first annual payment due under the Splitter Agreement was received in October 2016 and is reflected in deferred revenue as a component of other long-term liabilities on our Consolidated Balance Sheet.
Gathering and Processing Segment Expansion
Eagle Ford Shale Natural Gas Gathering and Processing Joint Ventures
In October 2015, we announced that we had entered into joint venture agreements with Sanchez Energy Corporation (“Sanchez”) to construct a new 200MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Plant”) and approximately 45 miles of associated pipelines. In July 2016, Sanchez sold its interest in the gathering joint venture to Sanchez Production Partners L.P. (“SPP”) and in November 2016 sold its interest in the processing joint venture to SPP. We own a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect Sanchez's Catarina gathering system to the plant. We hold a portion of the transportation capacity on the pipeline, and the gathering joint venture receives fees for transportation. We expect to invest approximately $125 million of growth capital expenditures related to the joint ventures.
The Raptor Plant will accommodate the growing production from Sanchez’s premier Eagle Ford Shale acreage position in Dimmit, La Salle and Webb Counties, Texas and from other third party producers. The plant and high pressure gathering lines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We will manage construction and operations of the plant and high pressure gathering lines, while the plant is expected to begin operations late in the first quarter of 2017 and to be fully operational in April 2017. Prior to the plant being placed in service, we benefit from Sanchez natural gas volumes that are processed at our Silver Oak facilities in Bee County, Texas.
Permian Basin Buffalo Plant
In April 2016, we commenced commercial operations of a new 200 MMcf/d cryogenic processing plant, known as the Buffalo Plant, in our WestTX system. This project also included the laying of new high and low pressure gathering lines in Martin and Andrews counties of Texas. Total growth capital expenditures for the Buffalo Plant were approximately $140 million (our net growth capital expenditures were approximately $102 million). The addition of the Buffalo Plant positions us to handle increasing production from our joint venture partner in WestTX, Pioneer (the largest active driller in the Spraberry and Wolfberry Trends), and from other active producers in the area.
Purchase of Versado Membership Interest
In October 2016, we acquired the remaining membership interest in Versado Gas Processors, L.L.C. (“Versado”) that we did not own. Targa held a 63% controlling interest in Versado prior to this transaction and already reported Versado on a consolidated basis. 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 3,600 miles of natural gas gathering pipelines.
Additional WestTX System Processing Capacity
In November 2016, we announced plans to restart the currently idled 45 MMcf/d Benedum cryogenic processing plant and to add 20 MMcf/d of capacity at our Midkiff plant in our WestTX system. The Benedum Plant was idled in September 2014 after the start-up of the 200 MMcf/d Edward Plant. The addition of 20 MMcf/d of capacity at our Midkiff plant will increase overall plant capacity of the Midkiff/Consolidator plant complex in Reagan County, Texas from 210 MMcf/d to 230 MMcf/d. Also in November 2016, we announced plans to build a new 200 MMcf/d cryogenic processing plant in WestTX (the “Joyce Plant”). The Joyce Plant is expected to be completed in early 2018.
In addition to the major projects noted above, we had other growth capital expenditures in 2016 and expect to have more in 2017 related to the continued build out of our gathering and processing infrastructure and logistics capabilities. We will continue to evaluate
other potential projects based on return profile, capital requirements and strategic need and may choose to defer projects depending on expected activity levels.
Permian Acquisition
On January 22, 2017, we entered into definitive agreements to purchase 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “Outrigger Delaware”) and Outrigger Midland Operating, LLC (“Outrigger Midland” and together with “Outrigger Delaware”, “Outrigger”) (the “Permian Acquisition”).
Outrigger Delaware’s gas gathering and processing and crude gathering systems are located in Loving, Winkler and Ward counties. 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. Outrigger Delaware’s assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Delaware system.
Outrigger Midland’s gas gathering and processing and crude gathering systems are located in Howard, Martin and Borden counties. 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. Outrigger Midland currently has 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Midland system.
We anticipate connecting Outrigger Delaware to our existing Sand Hills system and Outrigger Midland to our existing WestTX system during 2017, creating operational and capital synergies. We currently expect to close the transaction during the first quarter of 2017, subject to customary regulatory approvals and closing conditions.
Financing Activities
During the year ended December 31, 2016, we repurchased a portion of our outstanding senior notes on the open market, paying $534.3 million plus accrued interest to repurchase $559.2 million of the notes. The repurchases resulted in a $21.4 million net gain, which included the write-off of $3.5 million in related debt issuance costs. We may retire or purchase various series of the 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.
In October 2016, we 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”), yielding net proceeds of approximately $496.2 million and $496.2 million, respectively. The net proceeds from the offering of the 2016 Senior Notes (the “October 2016 Offering”), along with borrowings under our senior secured revolving credit facility (the “TRP Revolver”) were used to fund tender offers (the “Tender Offers”) for our 5% Senior Notes due January 2018 (the “5% Notes”), 6⅝% Senior Notes due October 2020 (the “6⅝% Notes”) and 6⅞% Senior Notes due February 2021 (the “6⅞% Notes” and together with the 5% Notes and 6⅝% Notes, the “Tender Notes”) and to fund redemption payments for the 6⅝% Notes and the 6⅞% Notes and the 6⅝% Senior Notes of Targa Pipeline Partners due October 2020 (the “6⅝% TPL Notes”).
The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date which totaled $1,138.3 million and we recorded 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 and $3.5 million of debt premiums. The aggregate principal amount of the notes redeemed following completion of the Tender Offers totaled $146.2 million and we recorded a loss due to debt extinguishment of approximately $9.7 million comprised of the $4.9 million premium paid, and a write-off of $1.1 million of debt issuance costs, $4.2 million of debt discounts and $0.5 million of debt premiums.
In October 2016, we entered into the Second Amendment and Restatement Agreement (the “Restatement”) to effectuate the Third Amended and Restated Credit Agreement (the “TRP Credit Agreement”). The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. The TRP Revolver continues to bear interest costs that are dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA, and the covenants also remained substantially the same. The TRP Credit Agreement designates TPL and certain of its subsidiaries as Restricted Subsidiaries and provides for certain changes to occur upon the Partnership receiving an investment grade credit rating from Moody’s or S&P, including the release of the security interests in all collateral at the request of the Partnership.
Subsequent to entering into the TRP Credit Agreement, we executed supplemental indentures relating to all of our outstanding series of Senior Notes to designate TPL and certain of its subsidiaries as guarantors of the Senior Notes.
In December 2016, we amended our account receivable securitization facility to extend the maturity to December 8, 2017 and to increase the facility size to $275.0 million from $225.0 million.
Growth Drivers
We believe that our near-term growth will be driven by the level of producer activity in the basins where our gathering and processing infrastructure is located and by the level of demand for services for our Downstream Business. We believe our assets are not easily duplicated, and in the current commodity price environment, are located in many of the most 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 third-party acquisitions will also continue to be a focus of our growth strategy.
Attractive Asset Positions
We believe that our positioning in some of the most attractive basins will allow us to capture increased natural gas supplies for processing. 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 resources 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 CBF Trains 3, 4 and 5. 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 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, 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.
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, provides us with a competitive advantage relative to other gathering and processing companies without these capabilities.
Bakken Shale / Three Forks opportunities
Although lower commodity prices have reduced producer activity in the Bakken Shale and Three Forks plays in the Williston Basin, we largely maintained our volumes of crude oil gathered and natural gas gathered and processed in 2016 by continuing to expand our infrastructure to capture additional volumes from wells that have already been drilled and that can be connected to our system.
Eagle Ford opportunities
As a result of our joint venture agreements with Sanchez in South Texas to construct a new 200 MMcf/d cryogenic processing plant and the associated infrastructure to connect to the Sanchez Catarina gathering system, we benefitted from increasing Sanchez production in the Eagle Ford play at our Silver Oak facilities. We expect to continue to benefit from increasing production at the Raptor Plant after the Raptor Plant is fully operational in April 2017.
Third party acquisitions
While our growth through 2010 was primarily driven by the implementation of a focused drop down strategy, we have a record of completing third party acquisitions. Since our formation, our strategy included approximately $13.1 billion in acquisitions and growth capital expenditures of which approximately $6.2 billion was for acquisitions from, or of, third parties. Additionally, we announced the Permian Acquisition in January 2017. We expect that third-party acquisitions will continue to be a focus of our growth strategy.
Competitive Strengths and Strategies
We believe that we are well positioned to execute our business strategies due to the following competitive strengths:
Strategically located gathering and processing asset base
Our gathering and processing businesses are strategically located in generally 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 asset are driven primarily by liquid hydrocarbon commodity prices. If drilling and production activities in these areas continue, we would likely increase the volumes of natural gas and crude oil available to our gathering and processing systems.
Leading fractionation, LPG export and NGL infrastructure position
We are one of the largest fractionators of NGLs in the Gulf Coast. Our fractionation assets are primarily located in Mont Belvieu, Texas and to a lesser extent Lake Charles, Louisiana, which are key market centers for NGLs. Our logistics operations at Mont Belvieu, the major U.S. hub of NGL infrastructure, include connection 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. The location and interconnectivity of these assets are not easily replicated, and we have additional capability to expand their capacity. We have extensive experience in operating these assets and developing, permitting and constructing new midstream assets.
Comprehensive package of midstream services
We provide a comprehensive package of services to natural gas and crude oil producers. These services are essential to gather crude and to gather, process and treat wellhead gas to meet pipeline standards and to extract NGLs for sale into petrochemical, industrial, commercial and export markets. We believe that our ability to provide these integrated services provides an advantage in competing for new supplies because we can provide substantially all of the services producers, marketers and others require for moving natural gas and NGLs from wellhead to market on a cost-effective basis. 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, the difficulty of permitting and constructing new midstream assets and the difficulty of developing the expertise necessary to operate them.
High quality and efficient assets
Our gathering and processing systems and logistics assets consist of high-quality, well-maintained facilities, resulting in low-cost, efficient operations. Advanced technologies have been implemented for processing plants (primarily cryogenic units utilizing centralized control systems), measurements (essentially all electronic and electronically linked to a central data-base) and operations and maintenance 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 $83.2 million per year over the last four 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 customers across our areas of operation. Consequently, we are not dependent on any one oil and gas basin or customer. 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. Closing the Permian Acquisition will also result in increasing fee-based cash flow as the entities acquired have primarily fee-based gathering and processing contracts.
Financial flexibility
We have historically maintained a conservative leverage ratio and ample liquidity and have funded our growth investments with a mix of equity and debt over time. Disciplined management of leverage, liquidity and commodity price volatility allow us to be flexible in our long-term growth strategy and enable us to pursue strategic acquisitions and large growth projects.
Experienced and long-term focused management team
Our current executive management team includes a number of individuals who formed us in 2004, and several others who managed many of our businesses prior to acquisition by Targa. They possess a breadth and depth of experience working in the midstream energy business. Other officers and key operational, commercial and financial employees have significant experience in the industry and with our assets and businesses.
Attractive cash flow characteristics
We believe that our strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows. Geographic, business and customer diversity enhances our cash flow profile. Our Gathering and Processing segment has a contract mix that is primarily percent-of-proceeds, but also has increasing components of fee-based revenues driven by fees added to percent-of-proceeds contracts for natural gas treating and compression, by new/amended contracts with a combination of percent-of-proceeds and fee-based components and by 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 and SouthTX. Contracts in our Coastal Gathering and Processing segment are primarily hybrid (percent-of-liquids with a fee floor) or percent-of-liquids contracts. 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 and future commodity purchases and sales through 2019 by entering into financially settled derivative transactions. These transactions include swaps, futures, purchased puts (or floors) and costless collars. The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and to mitigate the impact of fluctuations in commodity prices on cash flow. We have intentionally tailored our hedges to approximate specific NGL products and to approximate our actual NGL and residue natural gas delivery points. Although the degree of hedging will vary, we intend to continue to manage some of our exposure to commodity prices by entering into similar hedge transactions. We also monitor and manage our inventory levels with a view to mitigate losses related to downward price exposure.
Asset base well-positioned for organic growth
We believe that our asset platform and strategic locations allow us to maintain and potentially grow our volumes and related cash flows as our supply areas benefit from continued exploration and development over time. Technology advances have resulted in increased domestic oil and liquids-rich gas drilling and production activity. While recent commodity price levels have impacted 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. Our existing infrastructure has the capacity to handle some incremental increases in volumes without significant investments as well as opportunities to leverage existing assets with meaningful expansions. We believe that as domestic supply and demand for natural gas, crude oil and NGLs, and services for each grows over the long term, our infrastructure will increase in value as such infrastructure takes on increasing importance in meeting that growing supply and demand.
While we have set forth our strategies and competitive strengths above, our business involves numerous risks and uncertainties which
may prevent us from executing our strategies. These risks include the adverse impact of changes in natural gas, NGL and condensate/crude oil prices, the supply of or demand for these commodities, and our inability to access sufficient additional production to replace natural declines in production. For a more complete description of the risks associated with an investment in us, see “Item 1A.
Item 1A. Risk Factors.
Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. The nature of our business activities subjects us to certain hazards and risks. You should consider carefully the following risk factors together with all the other information contained in this report. If any of the following risks were actually 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, 2016, we had $4,002.2 million outstanding under our senior unsecured notes and $54.6 million of outstanding senior notes of TPL, excluding $0.5 million of unamortized net discounts and premiums. We also had $275.0 million outstanding under our accounts receivable securitization facility (the “Securitization Facility”). In addition, we had $150.0 million of borrowings outstanding, $13.2 million of letters of credit outstanding and $1,436.8 million of additional borrowing capacity available under the TRP Revolver. Our $1.6 billion TRP Revolver allows us to request increases in commitments up to an additional $500 million. For the years ended December 31, 2016, 2015 and 2014, our consolidated interest expense, net was $233.5 million, $207.8 million and $143.8 million.
This substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments, could have other important consequences to us, including the following:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
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satisfying our obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;
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we will need a portion of cash flow to make interest payments on debt, reducing the funds that would otherwise be available for operations and future business opportunities;
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our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.
Our long-term unsecured debt is currently rated by Standard & Poor’s Corporation (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”). As of December 31, 2016, our senior unsecured debt was rated “BB-” by S&P. As of December 31, 2016, our senior unsecured debt was rated “Ba3” by Moody’s. Any future downgrades in our credit ratings could negatively impact our cost of raising capital, and a downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public markets.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital, and such results may adversely affect our ability to make cash distributions. We may not be able to affect any of these actions on satisfactory terms, or at all.
Despite current indebtedness levels, we may still be able to incur substantially more debt. This could increase the risks associated with our substantial leverage.
We may be able to incur substantial additional indebtedness in the future. The TRP Revolver allows us to request increases in commitments up to an additional $500 million. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. If we incur additional debt, the risks associated with our substantial leverage would increase.
Increases in interest rates could adversely affect our business.
We have significant exposure to increases in interest rates. As of December 31, 2016, our total indebtedness was $4,481.8 million, excluding $0.5 million of unamortized net premiums, of which $4,056.8 million was at fixed interest rates and $425.0 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 $4.3 million. As a result of this amount of variable interest rate debt, our financial condition could be negatively affected by increases in interest rates.
The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.
The agreements governing our outstanding indebtedness contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interests. These agreements include covenants that, among other things, restrict our ability to:
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incur or guarantee additional indebtedness or issue additional preferred units;
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pay distributions on our equity securities or to our equity holders or redeem, repurchase or retire our equity securities or subordinated indebtedness;
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make investments and certain acquisitions;
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sell or transfer assets, including equity securities of our subsidiaries;
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engage in affiliate transactions,
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consolidate or merge;
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incur liens;
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prepay, redeem and repurchase certain debt, subject to certain exceptions;
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enter into sale and lease-back transactions or take-or-pay contracts; and
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change business activities conducted by us.
In addition, certain of our debt agreements require us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.
A breach of any of these covenants could result in an event of default under our debt agreements. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. For example, if we are unable to repay the accelerated debt under the TRP Revolver, the lenders under the TRP Revolver could proceed against the collateral granted to them to secure that indebtedness. If we are unable to repay the accelerated debt under the Securitization Facility, the lenders under the Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged substantially all of our assets as collateral under the TRP Revolver and the accounts receivables of Targa Receivables LLC under the Securitization Facility. If our 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 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 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. Beginning in the third quarter of 2014, crude oil and natural gas prices significantly declined and continued to decline during 2015 and remained depressed in 2016. The duration and magnitude of the recent decline in oil, gas and NGLs prices cannot be predicted. Our future cash flow may be materially adversely affected if we experience significant, prolonged price deterioration. The markets and prices for crude oil, natural gas and NGLs depend upon factors beyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:
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the impact of seasonality and weather;
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general economic conditions and economic conditions impacting our primary markets;
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the economic conditions of our customers;
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the level of domestic crude oil and natural gas production and consumption;
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the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;
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actions taken by foreign oil and gas producing nations;
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the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs;
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the availability and marketing of competitive fuels and/or feedstocks;
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the impact of energy conservation efforts;
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shareholder activism and activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas so as to minimize GHG emissions; and
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the extent of governmental regulation and taxation.
Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. For the year ended December 31, 2016, our percent-of-proceeds arrangements accounted for approximately 67% 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. Please see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Changes in future business conditions could cause recorded goodwill to become further impaired, and our financial condition and results of operations could suffer if there is an additional impairment of goodwill or other intangible assets with indefinite lives, intangible assets with definite lives, or property, plant and equipment assets.
We evaluate goodwill for impairment at least annually, as of November 30th, 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. During 2015 and 2016, global oil and natural gas commodity prices, particularly crude oil, significantly decreased as compared to 2014. This decrease in commodity prices has had, and is expected to continue to have, a negative impact on the demand for our services and our market capitalization. Based on the results of our annual evaluations in 2016 and 2015, we recorded goodwill impairments of $207.0 million for the year ended December 31, 2016 and $290.0 million for the year ended December 31, 2015, which are included in goodwill impairment in our Consolidated Statements of Operations. The carrying value of goodwill as of December 31, 2016 has been reduced to $210.0 million.
Should energy industry conditions further 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, cash flows and prospects of some of our customers. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from a decline in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Additionally, a decline in the share price of some of our public customers may place them in danger of becoming delisted from a public securities exchange, limiting their access to the public capital markets and further restricting their liquidity. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. To the extent one or more of our key customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues. Any material nonpayment or nonperformance by our key customers or our derivative counterparties could reduce our ability to make distributions to our unitholders.
Because of the natural decline in production in our operating regions and in other regions from which we source NGL supplies, our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.
Our gathering systems are connected to crude oil and natural gas wells from which production will naturally decline over time, which means that the cash flows associated with these sources of natural gas and crude oil will likely also decline over time. Our logistics assets are similarly impacted by declines in NGL supplies in the regions in which we operate as well as other regions from which we source NGLs. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas, NGL and crude oil supplies. A material decrease in natural gas or crude oil production from producing areas on which we rely, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas or crude oil that we process, NGL products delivered to our fractionation facilities or crude oil that we gather. Our ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successful drilling and production activity near our gathering systems and, in part, on the level of successful drilling and production in other areas from which we source NGL and crude oil supplies. We have no control over the level of such activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling 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. Beginning in the third quarter of 2014, crude oil and natural gas prices significantly declined and continued to decline during 2015 and remained depressed in 2016. 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 (including the Permian Acquisition, if it is completed) are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to make distributions to our limited partners. In addition, we may not achieve the expected results of the Permian Acquisition, if it is completed, and any adverse conditions or developments related to the Permian Acquisition, if it is completed, may have a negative impact on our operations and financial condition.
Our ability to grow depends, in part, on our ability to make acquisitions or develop growth projects that result in an increase in cash generated from operations. We are unable to acquire businesses from Targa in order to grow because Targa’s only assets currently are the interests in us that Targa owns. As a result, we will need to focus on third-party acquisitions and organic growth. If we are unable to make accretive acquisitions or develop accretive growth projects because we are (1) unable to identify attractive acquisition candidates and negotiate acceptable acquisition agreements or develop growth projects economically, (2) unable to obtain financing for these acquisitions or projects on economically acceptable terms, or (3) unable to compete successfully for acquisitions or growth projects, then our future growth and ability to increase distributions will be limited.
Any acquisition (including the Permian Acquisition, if it is completed) or growth project involves potential risks, including, among other things:
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operating a significantly larger combined organization and adding new or expanded operations;
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difficulties in the assimilation of the assets and operations of the acquired businesses or growth projects, especially if the assets acquired are in a new business segment and/or geographic area;
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the risk that crude oil and natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
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the failure to realize expected volumes, revenues, profitability or growth;
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the failure to realize any expected synergies and cost savings;
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coordinating geographically disparate organizations, systems and facilities;
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the assumption of environmental and other unknown liabilities;
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limitations on rights to indemnity from the seller in an acquisition or the contractors and suppliers in growth projects;
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the failure to attain or maintain compliance with environmental and other governmental regulations;
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inaccurate assumptions about the overall costs of equity or debt;
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the diversion of management’s and employees’ attention from other business concerns; and
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customer or key employee losses at the acquired businesses or to a competitor.
If these risks materialize, any acquired assets or growth project may inhibit our growth, fail to deliver expected benefits and/or add further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition or growth project. If we consummate any future acquisition or growth project, our capitalization and results of operations may change significantly and you may not have the
opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions or growth projects.
Our acquisition and growth strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants and new opportunities created by industry expansion. A material decrease in such divestitures or in opportunities for economic commercial expansion would limit our opportunities for future acquisitions or growth projects and could adversely affect our operations and cash flows available for distribution to our limited partners.
Acquisitions may significantly increase our size and diversify the geographic areas in which we operate and growth projects may increase our concentration in a line of business or geographic region. We may not achieve the desired effect from any future acquisitions or growth projects.
Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new 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 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 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 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 such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
Our acquisition and growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow through acquisitions or growth projects.
We continuously consider and enter into discussions regarding potential acquisitions and growth projects. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders. These factors may impair our ability to execute our acquisition and growth strategy.
In addition, we are experiencing increased competition for the types of assets we contemplate purchasing or developing. Current economic conditions and competition for asset purchases and development opportunities could limit our ability to fully execute our acquisition and growth strategy.
Demand for propane is significantly impacted by weather conditions and therefore seasonal and requires increases in inventory to meet seasonal demand.
Weather conditions have a significant impact on the demand for propane because domestic end-users principally utilize propane for heating purposes. Warmer-than-normal temperatures in one or more regions in which we operate can significantly decrease the total volume of propane we sell. Lack of consumer domestic demand for propane may also adversely affect the retailers with which we transact our wholesale propane marketing operations, exposing us to retailers’ inability to satisfy their contractual obligations to us.
If our general partner loses any of its named executive officers, our business may be adversely affected.
Our success is dependent upon the efforts of the named executive officers of our general partner. The named executive officers of our general partner are responsible for executing our business strategies. There is substantial competition for qualified personnel in the midstream natural gas industry. Our general partner may not be able to retain its existing named executive officers or fill new positions or vacancies created by expansion or turnover. Our general partner has not entered into employment agreements with any of its named executive officers. In addition, it does not maintain “key man” life insurance on the lives of any of its named executive officers. A loss of one or more of the named executive officers of our general partner could harm our business and prevent us from implementing our business strategies.
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 business, 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. 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. In addition, 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 the future. 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. Please 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 and NGLs, 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 and NGLs 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 at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of 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.
Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.
Natural Gasoline. Natural gasoline is used as a blending component for certain refined petroleum products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation, and in demand for ethylene and propylene, could adversely affect demand for natural gasoline.
NGLs and products produced from NGLs also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect both demand for the services we provide and NGL prices, which could negatively impact our results of operations and financial condition.
We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.
We do not own most of the land on which our pipelines, terminals and compression facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-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.
Weather may limit our ability to operate our business and could adversely affect our operating results.
The weather in the areas in which we operate can cause disruptions and in some cases suspension of our operations. For example, unseasonably wet weather, extended periods of below freezing weather, or hurricanes may cause disruptions or suspensions of our operations, which could adversely affect our operating results. Some forecasters expect that potential climate changes may have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events and could have an adverse effect on our operations.
Our business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.
Our operations are subject to many hazards inherent in gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; gathering, storing and terminaling crude oil; and storing and terminaling refined petroleum products, including:
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damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;
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inadvertent damage from third parties, including from motor vehicles and construction, farm or utility equipment;
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damage that is the result of our negligence or any of our employees’ negligence;
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leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
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spills or other unauthorized releases of natural gas, NGLs, crude oil, other hydrocarbons or waste materials that contaminate the environment, including soils, surface water and groundwater, and otherwise adversely impact natural resources; and
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other hazards that could also result in personal injury, loss of life, pollution and/or suspension of operations.
These risks could result in substantial losses due to personal injury, loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental 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 gas and hazardous liquids pipelines that, in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. Among other things, these regulations require operators of covered pipelines to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquids pipelines. We currently estimate an average annual cost of $3.6 million between 2017 and 2019 to implement pipeline integrity management program testing along certain segments of our 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 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 imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register is uncertain given the recent change in Presidential Administrations. In a second example, in March 2016, PHMSA announced a proposed rulemaking that would impose
new or more stringent requirements for certain gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their MAOP; and imposing increased integrity management requirements. 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.
Failure to comply with environmental laws or regulations 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 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, and imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA 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 delays 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.
Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, 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 oil and natural gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate the flow of 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 December 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, as the State of New York did in 2015. 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. New or more stringent laws or regulations 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, or increased litigation. Any one or more of such developments could reduce demand for our gathering, processing and fractionation services.
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 our interest in VGS, which is subject to extensive FERC regulation, and the Driver Residue Pipeline and TPL SouthTex Transmission pipeline, which are each subject to more limited FERC regulation, our operations are generally exempt from FERC regulation under the NGA, 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.
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 to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems other than VGS and the Driver Residue Pipeline have not been regulated by FERC as a natural gas company under the NGA, 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. 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. 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 and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
At the federal level, no comprehensive climate change legislation has been implemented 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. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering, compression and boosting facilities and blowdowns of natural gas transmission pipelines, beginning with the 2016 reporting year, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rules with the new source performance standards.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 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 will expand previously issued New Source Performance Standards published by the EPA in 2012 and 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. In November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from facilities and operators in the oil and natural gas industry. The EPA has indicated that it intended to use the information from this request to develop Existing Source Performance Standards (ESPS) for the oil and gas industry. Additionally, in December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but does include pledges to voluntarily limit or reduce future emissions.
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 or additional operating restrictions. 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 June 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 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.
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 October 2015, PHMSA proposed new more stringent regulations for hazardous liquid pipelines, including extending certain integrity management assessment and repair requirements to pipelines not currently subject to integrity management regulations and requiring that all pipelines have a means of detecting leaks. In another 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, 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 MAOP; and 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. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements and also require consideration of seismicity in evaluating threats to pipelines.
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.
The enactment 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 requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain 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. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin in the future, although current rules do not result in requirements for our swap dealer counterparties to collect margin from us for our hedging transactions. Posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows.
The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.
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.
Our interstate common carrier liquids pipelines are regulated by the FERC.
Targa NGL has interstate NGL pipelines that are considered common carrier pipelines subject to regulation by FERC under the ICA. More specifically, Targa NGL owns a twelve-inch diameter pipeline that runs between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move mixed NGL and purity NGL products. Targa NGL also owns an eight-inch diameter pipeline and a twenty-inch diameter pipeline, each of which run between Mont Belvieu, Texas and Galena Park, Texas. The eight-inch and the twenty-inch pipelines are 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. The ICA requires that we maintain tariffs on file with FERC for each of these pipelines. 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 nondiscriminatory. All shippers on these pipelines are our subsidiaries.
Targa NGL also owns a twelve-inch diameter pipeline that runs between Mont Belvieu, Texas, and Galena Park, Texas, that transports NGLs and that has qualified for a waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. The crude oil pipeline system that is part of the Badlands assets also qualifies for such a waiver. Such waivers are subject to revocation, however, and should the pipelines’ circumstances change, FERC could, either at the request of other entities or on its own initiative, assert that some or all of the transportation on these pipelines is within its jurisdiction. In the event that FERC were to determine that one or both of these pipelines no longer qualified for a waiver, the Partnership would likely be required to file a tariff with FERC for one or both of these pipelines, as applicable, 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.
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.
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 certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating 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 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 other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage 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 continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.
Risks Related to Our Structure
Targa controls our general partner, which has sole responsibility for conducting our business and managing our operations. Targa
has conflicts of interest with us and may favor its own interests to your detriment.
Targa owns and controls our general partner. All of our general partner’s directors and all of its executive officers are directors or officers of Targa. Therefore, conflicts of interest may arise between Targa, including our general partner, on the one hand and us and our limited partners, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests over the interests of our limited partners. These conflicts include, among others, the following situations:
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neither our partnership agreement nor any other agreement requires Targa to pursue a business strategy that favors us. Targa’s directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Targa, which may be contrary to our interests; and
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our general partner is allowed to take into account the interests of parties other than us, such as Targa or its owners, in resolving conflicts of interest.
Targa is not limited in its ability to compete with us and is under no obligation to offer assets it may acquire to us, which could limit our ability to acquire additional assets or businesses.
Our partnership agreement does not prohibit Targa from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Targa may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competition from Targa could adversely impact our results of operations and cash available for distribution.
The credit and business risk profile of our general partner could adversely affect our credit ratings and profile.
The credit and business risk profiles of our general partner may be factors in credit evaluations of us. This is because the general partner can exercise significant influence over our business, including our cash distribution and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of the general partner, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness.
Targa, the owner of our general partner and all of our common units, is dependent on the cash distributions from its indirect general partner and limited partner equity interests in us to provide working capital. Any distributions by us to such entities will be made only after satisfying our then-current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or more risky than ours.
Our partnership agreement limits our general partner’s fiduciary duties to our limited partners and restricts the remedies available to limited partners for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, Targa. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of or factors affecting us;
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provides that our general partner does not have any liability to us or our limited partners for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of limited partners must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties, or must be “fair and reasonable” to us, as determined by our general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
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provides that our general partner and its officers and directors are not liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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provides that in resolving conflicts of interest, it is presumed that in making its decision the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Your liability may not be limited if a court finds that limited partner action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in Louisiana, Texas, Oklahoma and North Dakota as well as other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or that your right to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Limited partners may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, limited partners may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to limited partners if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Risks Related to the Preferred Units
We cannot assure you that we will be able to pay distributions on our Preferred Units regularly, and the agreements governing our indebtedness may limit the cash available to make distributions on the Preferred Units.
Subject to the limitations on restricted payments contained in our indentures and in our senior secured credit agreement, we distribute all of our “available cash” each quarter to our limited partners and our general partner. “Available cash” is defined in our partnership agreement and described below under “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities-Distributions of Available Cash-Definition of Available Cash.” As a result, we do not expect to accumulate significant amounts of cash. Depending on the timing and amount of our cash distributions, these distributions could significantly reduce the cash available to us in subsequent periods to make payments on the Preferred Units.
The Preferred Units are subordinated to our existing and future debt obligations, and could be diluted by the issuance of additional units, including additional Preferred Units, and by other transactions.
The Preferred Units are subordinated to all of our existing and future indebtedness (including indebtedness outstanding under our senior secured credit facility, our existing senior notes and indebtedness outstanding under our Securitization Facility). The payment of principal and interest on our debt reduces cash available for distribution to us and on our units, including the Preferred Units. The issuance of additional units pari passu with or senior to the Preferred Units would dilute the interests of the holders of the Preferred Units, and any issuance of senior securities or parity securities (each as defined in our partnership agreement) or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Preferred Units.
Our ability to issue parity securities in the future could adversely affect the rights of holders of our Preferred Units.
We are allowed to issue additional Preferred Units and parity securities without any vote of the holders of the Preferred Units, except where the cumulative distributions on the Preferred Units or any parity securities are in arrears. The issuance of additional Preferred Units or any parity securities would have the effect of reducing the amounts available to the holders of the outstanding Preferred Units upon our liquidation, dissolution or winding up if we do not have sufficient funds to pay all liquidation preferences of the Preferred Units and parity securities in full. It also would reduce amounts available to make distributions on the outstanding Preferred Units if we do not have sufficient funds to pay distributions on all outstanding Preferred Units and parity securities.
In addition, although holders of Preferred Units are entitled to limited voting rights, with respect to certain matters the Preferred Units will generally vote separately as a class along with all other series of our parity securities that we may issue upon which like voting
rights have been conferred and are exercisable. As a result, the voting rights of holders of Preferred Units may be significantly diluted, and the holders of such other series of Parity Securities that we may issue may be able to control or significantly influence the outcome of any vote. Future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Preferred Units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.
Tax Risks to Holders of Preferred Units
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to you may be substantially reduced.
A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested and do not plan to request a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions instead of as guaranteed payments for the use of capital, as described further below. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you may be substantially reduced. Therefore, treatment of us as a corporation may result in a material reduction in the anticipated cash flow.
At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income and franchise taxes and other forms of taxation. For example, we are subject to the Texas franchise tax at a maximum effective rate of 0.75% of our gross income apportioned to Texas in the prior year. Imposition of any such tax on us by any other state will reduce the cash available for distribution to you.
The tax treatment of publicly traded partnerships or an investment in us could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in us may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.
Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in us.
On January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect the Partnership’s ability to be treated as a partnership for U.S. federal income tax purposes.
The tax treatment of distributions on our Preferred Units as guaranteed payments for the use of capital is uncertain.
The tax treatment of distributions on our Preferred Units is uncertain. We will treat the holders of Series A Preferred Units as partners for tax purposes and will treat distributions on the Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Preferred Units as ordinary income. We anticipate accruing and making guaranteed payment distributions on a monthly basis. However, the accrual of such a guaranteed payment is not contingent upon a cash distribution, and holders of Preferred Units will recognize taxable income from such accrual even in the absence of a contemporaneous cash distribution. Otherwise, the holders of Preferred Units are generally neither anticipated to share in our items of income, gain, loss or deduction, nor be allocated any share of our nonrecourse liabilities. If the Preferred Units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Preferred Units.
You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
Our partners, including holders of Preferred Units, may receive allocations of taxable income that are different in amount than the cash we distribute. You are required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that resulting from that income.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our Preferred Units that may result in adverse tax consequences to them.
Investment in the Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. Although the issue is not free from doubt, we will treat distributions to non-U.S. holders of the Preferred Units as “effectively connected income” (which will subject holders to U.S. net income taxation and possibly the branch profits tax) that are subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. holders. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income, or UBTI, for federal income tax purposes. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning our Preferred Units.
If the IRS contests the federal income tax positions we take, the market for our Preferred Units may be adversely affected and the cost of any contest will reduce our cash available for distribution to you. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to you.
We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Preferred Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our partners because the costs will reduce our cash available for distribution.
Recently enacted legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our partners may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, partners during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.
A Holder of Preferred Units whose units are the subject of a securities loan (e.g., a loan to cover a short sale of units) may be considered to have disposed of those units. If so, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.
Because there are no specific rules governing the federal tax consequences of loaning a partnership interest, a Holder of Preferred Units whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case the holder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan, and the holder may recognize gain or loss from such disposition. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
You may be subject to state and local taxes and return filing requirements in jurisdictions where you do not live as a result of investing in our preferred units.
In addition to federal income taxes, Holders of Preferred Units may be subject to return filing requirements and other taxes, including state, local and non-U.S. income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which the preferred unitholder is a resident. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. You may be subject to penalties for failure to comply with return filing requirements. It is your responsibility to file all U.S. federal, state and local tax returns.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
A description of our properties is contained in “Item 1. Business” in this Annual Report.
Our principal executive offices are located at 1000 Louisiana Street, Suite 4300, Houston, Texas 77002 and our telephone number is 713-584-1000.
Item 3.
Item 3. Legal Proceedings.
Litigation related to TRC/TRP Merger
On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), Targa Resources GP LLC (“TRP GP”), the members of the board of TRP GP (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”). This lawsuit was styled Leslie Blumberg et al. v. TRC Resources Corp., et al., Cause No. 2015-75481, in the 234th Judicial District Court of Harris County, Texas (the “State Court Lawsuit”). The State Court Plaintiffs amended the State Court Lawsuit on July 26, 2016.
The State Court Plaintiffs alleged several causes of action challenging the TRC/TRP Merger. Generally, the State Court Plaintiffs alleged that (i) the members of the TRP GP Board breached express and/or implied duties under the Partnership Agreement and (ii) TRC, TRP GP, and Merger Sub aided and abetted in these alleged breaches of duties. The State Court Plaintiffs further alleged, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair, (e) the TRP GP Board had conflicts of interest due to TRC’s control of TRP GP, (f) the TRP GP Conflicts Committee’s financial advisor was conflicted and conducted flawed analyses, and (g) the joint proxy statement/prospectus filed in connection with the TRC/TRP Merger (the “Proxy”) failed to disclose allegedly material information concerning, among other things, (i) the TRC and TRP projections included in the Proxy, and (ii) the analyses conducted by the TRP GP Conflicts Committee’s financial advisor in connection with the TRC/TRP Merger.
Based on these allegations, the State Court Plaintiffs sought damages and attorneys’ fees. On February 26 and 29, 2016, the State Court Defendants filed general denials and asserted affirmative defenses. On August 26, 2016, the State Court Defendants filed Special Exceptions and a Motion for Summary Judgment. On December 5, 2016, the Court granted Defendants’ Motion for Summary Judgment and dismissed the State Court Lawsuit in its entirety with prejudice.
Environmental Proceedings
On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014. The Monument Gas Plant is owned by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A. Inc. The Partnership has been in discussions with the New Mexico Environment Department to resolve the alleged violations. The New Mexico Environment Department has offered to settle the matter for $29,223.
We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.
Item 4.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
Our common units were listed on the NYSE under the symbol “NGLS” prior to the closing of the TRC/TRP Merger on February 17, 2016. As of February 10, 2017, there were 275,168,410 common units outstanding.
On February 17, 2016, TRC completed the TRC/TRP Merger, pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our 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, our common units are no longer publicly traded. The Preferred Units remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
The following table sets forth the high and low sales prices of our common units as reported by the NYSE and the amount of cash distributions declared for the periods indicated:
______________________________________
(1)
Public shares were traded through February 17, 2016.
(2)
Distribution per common unit is no longer relevant after the TRC/TRP Merger.
There is no established trading market for the 5,629,136 general partner units held only by our general partner.
Distributions of Available Cash
General
As a result of the TRC/TRP Merger, Targa owns all of our outstanding common units. We have discretion under the Third A&R Partnership Agreement as to whether to distribute all available cash for any period. See Note 10 - Debt Obligations and Note 12 - Partnership Units and Related Matters of the “Consolidated Financial Statements” included in this Annual Report.
The following table details the distributions declared or paid by the Partnership during the periods presented:
Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDRs of $9.375 million were reallocated to common unitholders for each of the four quarters of 2015. The IDR Giveback Amendment covered sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015. The IDR Giveback resulted in reallocation of IDR payments to common unitholders of $6.25 million for each of the first three quarters of 2016.
On October 19, 2016, we executed the Third A&R Partnership Agreement, which became effective on December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the IDRs held by 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.
Definition of Available Cash
Under the partnership agreement, the term “available cash,” is defined, for any quarter or month, as applicable, as the sum of all cash and cash equivalents on hand at the end of that quarter or month, as applicable, and all additional cash and cash equivalents on hand immediately prior to the date of the distribution of available cash resulting from borrowings for working capital purposes subsequent to the end of that quarter or month, as applicable, less the amount of any cash reserves established by our general partner to:
•
provide for the proper conduct of our business (including reserves for future capital expenditures and for anticipated future credit needs);
•
comply with applicable law or any loan agreements, security agreements, mortgages, debt instruments or other agreements;
•
provide funds for distributions on and redemptions with respect to the Preferred Units; or
•
provide funds for further distributions.
The amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. The board of directors of our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business, including reserves to provide funds for distributions on and redemptions with respect to the Preferred Units. These can also include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to our unitholders, reserves to reduce debt or, as necessary, reserves to comply with the terms of any of our agreements or obligations. We will be prohibited from making any distributions to unitholders if it would cause an event of default or if an event of default exists under our credit agreement or indentures.
Preferred Units
Distributions on the Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on the Preferred Units will be paid out of amounts legally available therefor to, but not including, November 1, 2020, at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on the Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. For the year ended December 31, 2016, we have paid $11.3 million in distributions to the holders of our Preferred Units. See Note 12 - Partnership Units and Related Matters of the “Consolidated Financial Statements” included in this Annual Report.
Recent Sales of Unregistered Equity Securities
In connection with the Third A&R Partnership Agreement, TRP issued to the General Partner (i) 20,380,286 common units and 424,590 General Partner units in exchange for the cancellation of the IDRs and (ii) 11,267,485 common units and 234,739 General Partner units in exchange for cancellation of the Special GP Interest. These common units and General Partner units were issued on December 1, 2016 pursuant to the exemption offered by Section 4(a)(2) of the Securities Exchange Act of 1934.
Repurchase of Equity by Targa Resources Partners LP or Affiliated Purchasers
None.
Item 6.
Item 6. Selected Financial Data.
The following table presents selected historical consolidated financial and operating data of Targa Resources Partners LP for the periods ended, and as of, the dates indicated. We derived this information from our historical “Consolidated Financial Statements” and accompanying notes. The information in the table below should be read together with, and is qualified in its entirety by reference to, those financial statements and notes in this Annual Report.
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(1)Distributions declared per unit are no longer relevant after the TRC/TRP Merger.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our historical financial statements and notes included in Part IV of this Annual Report.
Overview
Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by TRC. Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC’s acquisition on February 17, 2016 of all our outstanding common units that it and its subsidiaries did not already own. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
Targa Resources GP LLC, our general partner, is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa.
On February 17, 2016, TRC completed the previously announced transactions contemplated by the Merger Agreement, by and among us, our general partner, TRC and Merger Sub pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP, with TRP continuing as the surviving entity and as a subsidiary of TRC. Following the closing of the TRC/TRP Merger on February 17, 2016, TRC owns all our outstanding common units.
Our Operations
We are engaged in the business of:
•
gathering, compressing, treating, processing and selling natural gas;
•
storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;
•
gathering, storing and terminaling crude oil; and
•
storing, terminaling and selling refined petroleum products.
To provide these services, we operate in two primary segments (previously referred to as divisions): (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).
Concurrent with the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure. The Gathering and Processing division was previously disaggregated into two reportable segments-(a) Field Gathering and Processing and (b) Coastal Gathering and Processing. The Logistics and Marketing division was previously disaggregated into two reportable segments-(a) Logistics Assets and (b) Marketing and Distribution. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team.
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; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain 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 operations are generally connected to and supplied in part by our Gathering and Processing operations and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington.
Other contains the results (including any hedge ineffectiveness) of our commodity derivative activities that are included in operating margin.
Volatility of Commodity Prices
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. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Prices of oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related reduced activity levels from our customers. Beginning in the fourth quarter of 2014, oil, natural gas and NGL prices declined significantly primarily due to global supply and demand imbalances. Oil, natural gas and NGL prices continued to decline in 2015 and the first half of 2016, but have experienced some recovery.
2016 Developments
Logistics and Marketing Segment Expansion
Cedar Bayou Fractionator Train 5
In June 2016, we commissioned an additional fractionator, Train 5, at our 88%-owned CBF in Mont Belvieu, Texas. This expansion added 100 MBbl/d of fractionation capacity at CBF, and is 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 gross cost of Train 5 was approximately $331 million (our net cost was approximately $299 million).
Channelview Splitter
On December 27, 2015, we and Noble entered into the Splitter Agreement under which we will build the Channelview Splitter, which will have the capability to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter is expected to be completed by early 2018, and has an estimated total cost of approximately $140 million. As contemplated by the December 2014 Agreement, the Splitter Agreement completes and terminates the December 2014 Agreement, while retaining our economic benefits from that previous agreement. The first annual payment due under the Splitter Agreement was received in October 2016 and is reflected as deferred revenue as a component of other long-term liabilities on our Consolidated Balance Sheet.
Gathering and Processing Segment Expansion
Eagle Ford Shale Natural Gas Gathering and Processing Joint Ventures
In October 2015, we announced that we had entered into the Carnero Joint Ventures with Sanchez to construct the Raptor Plant and approximately 45 miles of associated pipelines. In July 2016, Sanchez sold its interest in the gathering joint venture to SPP and in November 2016 sold its interest in the processing joint venture to SPP. We own a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect Sanchez's Catarina gathering system to the plant. We hold a portion of the transportation capacity on the pipeline, and the gathering joint venture receives fees for transportation. We expect to invest approximately $125 million of growth capital expenditures related to the joint ventures.
The Raptor Plant will accommodate the growing production from Sanchez’s premier Eagle Ford Shale acreage position in Dimmit, La Salle and Webb Counties, Texas and from other third party producers. The plant and high pressure gathering lines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We will manage construction and operations of the plant and high pressure gathering lines, while the plant is expected to begin operations late in the first quarter of 2017 and be fully operational in April 2017. Prior to the plant being placed in service, we benefit from Sanchez natural gas volumes that are processed at our Silver Oak facilities in Bee County, Texas.
Permian Basin Buffalo Plant
In April 2016, we commenced commercial operations of a new 200 MMcf/d cryogenic processing plant, known as the Buffalo Plant, in our WestTX system. This project also included the laying of new high and low pressure gathering lines in Martin and Andrews counties of Texas. Total growth capital expenditures for the Buffalo Plant were approximately $140 million (our net growth capital expenditures were approximately $102 million). The addition of the Buffalo Plant positions us to handle increasing production from our joint venture partner in WestTX, Pioneer (the largest active driller in the Spraberry and Wolfberry Trends), and from other active producers in the area.
Purchase of Versado Membership Interest
In October 2016, we acquired the remaining membership interest in Versado that we did not own. Targa held a 63% controlling interest in Versado prior to this transaction and already reported Versado on a consolidated basis. 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 3,600 miles of natural gas gathering pipelines.
Additional WestTX System Processing Capacity
In November 2016, we announced plans to restart the currently idled 45 MMcf/d Benedum cryogenic processing plant and to add 20 MMcf/d of capacity at our Midkiff plant in our WestTX system. The Benedum Plant was idled in September 2014 after the start-up of the 200 MMcf/d Edward Plant. The addition of 20 MMcf/d of capacity at our Midkiff plant will increase overall plant capacity of the Midkiff/Consolidator plant complex in Reagan County, Texas from 210 MMcf/d to 230 MMcf/d. Also in November 2016, we announced plans to build the Joyce Plant, which is expected to be completed in early 2018.
In addition to the major projects noted above, we had other growth capital expenditures in 2016 and expect to have more in 2017 related to the continued build out of our gathering and processing infrastructure and logistics capabilities. We will continue to evaluate other potential projects based on return profile, capital requirements and strategic need and may choose to defer projects depending on expected activity levels.
Permian Acquisition
On January 22, 2017, we entered into definitive agreements to purchase 100% of the membership interests of Outrigger Delaware and Outrigger Midland (the “Permian Acquisition”).
Outrigger Delaware’s gas gathering and processing and crude gathering systems are located in Loving, Winkler and Ward counties. 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. Outrigger Delaware’s assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Delaware system.
Outrigger Midland’s gas gathering and processing and crude gathering systems are located in Howard, Martin and Borden counties. 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. Outrigger Midland currently has 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Midland system.
We anticipate connecting Outrigger Delaware to our existing Sand Hills system and Outrigger Midland to our existing WestTX system during 2017, creating operational and capital synergies. We currently expect to close the transaction during the first quarter of 2017, subject to customary regulatory approvals and closing conditions.
Financing Activities
During the year ended December 31, 2016, we repurchased a portion of our outstanding senior notes on the open market, paying $534.3 million plus accrued interest to repurchase $559.2 million of the notes. The repurchases resulted in a $21.4 million net gain, which included the write-off of $3.5 million in related debt issuance costs.
We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
In October 2016, we issued the 2016 Senior Notes yielding net proceeds of approximately $496.2 million and $496.2 million, respectively. The net proceeds from the October 2016 Offering, along with borrowings under the TRP Revolver were used to fund tender offers for other series of senior notes and to fund redemption payments for certain note balances remaining after completion of the tender offers. The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date, totaling $1,138.3 million and we recorded 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 and $3.5 million of debt premiums. The aggregate principal amount of the notes redeemed following completion of the Tender Offers totaled $146.2 million and we recorded a loss due to debt extinguishment of approximately $9.7 million comprised of the $4.9 million premium paid, and a write-off of $1.1 million of debt issuance costs, $4.2 million of debt discounts and $0.5 million of debt premiums.
In October 2016, we entered into the Restatement to effectuate the TRP Credit Agreement. The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. The TRP Revolver continues to bear interest costs that are dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA, and the covenants also remained substantially the same. The TRP Credit Agreement designates TPL and certain of its subsidiaries as Restricted Subsidiaries and provides for certain changes to occur upon our receiving an investment grade credit rating from Moody’s or S&P, including the release of the security interests in all collateral at our request.
Subsequent to entering into the TRP Credit Agreement, we executed supplemental indentures relating to all our outstanding series of Senior Notes to designate TPL and certain of its subsidiaries as guarantors of the Senior Notes.
In December 2016, we amended our account receivable securitization facility to extend the maturity to December 8, 2017 and increase the facility size to $275.0 million. The Securitization Facility provides up to $275.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 8, 2017. Under the Securitization Facility, Targa Midstream Services LLC (“TMS”), a consolidated subsidiary of the Partnership, contributes certain receivables to Targa Gas Marketing LLC (“TGM”), a consolidated subsidiary of the Partnership, and TGM and another consolidated subsidiary of the Partnership (Targa Liquids Marketing and Trade LLC (“TLMT”)) sell or contribute 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 a third-party financial institution. Receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of TMS, TGM, TLMT or the Partnership. Any excess receivables are eligible to satisfy the claims of creditors of TMS, TGM, TLMT or the Partnership. As of December 31, 2016, total funding under the Securitization Facility was $275.0 million.
Factors That Significantly Affect Our Results
Our results of operations are substantially impacted by changes in commodity prices, the volumes that move through our gathering, processing and logistics assets, contract terms, the impact of hedging activities and the cost to operate and support assets.
Commodity Prices
The following table presents selected average annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periods presented:
________
(1)
Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.
(2)
“Illustrative Targa NGL” pricing is weighted using average quarterly prices from Mont Belvieu Non-TET monthly commercial index and represents the following composition for the periods noted:
2016: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline
2015: 37% ethane, 35% propane, 12% normal butane, 6% isobutane and 10% natural gasoline
2014: 44% ethane, 30% propane, 10% normal butane, 5% isobutane and 11% natural gasoline
(3)
Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX.
Volumes
In our gathering and processing operations, plant inlet volumes, crude oil volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a regional basis and more broadly by the impact of prices for oil, natural gas and NGLs on exploration and production activity in the areas of our operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to our Downstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available pipeline capacity to transport NGLs to our fractionators and our competitive and contractual position relative to other fractionators.
Contract Terms, Contract Mix and the Impact of Commodity Prices
Because of the potential for significant volatility of natural gas and NGL 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 material 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. For example, our Badlands and SouthTX crude oil and natural gas contracts are essentially 100% fee-based.
The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. During periods of low relative demand for available fractionation capacity, rates were low and frac-or-pay contracts were not readily available. The current demand for fractionation services has grown resulting in increases in fractionation fees and contract term. In addition, reservation fees are required. Increased demand for export services also supports fee-based contracts. The Logistics and Marketing segment includes both fee-based and percent-of-proceeds contracts.
Impact of Our Commodity Price Hedging Activities
We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes and future commodity purchases and sales through 2019 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 may buy calls in connection with swap positions to create a price floor with upside. 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 NGL prices. For additional information regarding our hedging activities, see “Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our customers.
Risk Management
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all our commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operation. 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 equity volumes, NGL equity volumes and condensate equity volumes and future commodity purchases and sales through 2019. The current market conditions may also impact our ability to enter into future commodity derivative contracts.
Commodity Price Risk
A significant portion of our revenues is 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 and NGLs 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, 2016, we have hedged the commodity price associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing operations, (ii) NGL and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements and (iii) future commodity purchases and sales 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 hedging transactions are typically 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 natural gas and NGL prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.
We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas and NGL prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.
During the years ended December 31, 2016, 2015 and 2014, our operating revenues increased (decreased) by $40.1 million, $74.0 million, and $(9.6) 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 OCI 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 asset position of $119.5 million at December 31, 2015 to a net liability position of $53.3 million at December 31, 2016. The fixed prices we currently expect to receive on derivative contracts are below the aggregate forward prices for commodities related to those contracts, creating this net liability position.
As of December 31, 2016, we had the following derivative instruments that will settle during the years ending below:
Natural GAS
(1)
Other includes derivative agreements entered into for the purpose of hedging future commodity purchases and sales in our Logistics and Marketing segment.
NGLs
(1)
Other includes derivative agreements entered into for the purpose of hedging future commodity purchases and sales in our Logistics and Marketing segment.
(2)
The “Future” line items are comprised of futures transactions entered into on both the Intercontinental Exchange (“ICE”) and Chicago Mercantile Exchange (“CME”).
CONDENSATE
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). For derivative instruments not designated as cash flow hedges these contracts are marked-to-market and recorded in revenues.
We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. For the contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those contracts which we are unable to obtain quoted prices for at least 90% of the full term of the commodity contract, the valuations are classified as Level 3 within the fair value hierarchy. See Note 14 - Fair Value Measurements in this Annual Report for more information regarding classifications within the fair value hierarchy.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the Securitization Facility. As of December 31, 2016, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRP Revolver and the Securitization Facility will also increase. As of December 31, 2016, we had $425.0 million in outstanding variable rate borrowings under the TRP Revolver and the Securitization Facility. A hypothetical change of 100 basis points in the interest rate of our variable debt would impact our annual interest expense by $4.3 million.
Counterparty Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the International Swap Dealers Association agreements with all 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 $21.9 million as of December 31, 2016. The range of losses attributable to our individual counterparties would be between $1.3 million and $3.8 million, depending on the counterparty in default.
Customer Credit Risk
We extend credit to customers and other parties in the normal course of business. We have an established policy and various procedures to manage our credit exposure risk, including initial and subsequent credit risk analyses, credit limits and terms and 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, 2016, our operating income would decrease by $6.7 million in the year of the assessment.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Our “Consolidated Financial Statements,” together with the report of our independent registered public accounting firm, begin on page in this Annual Report.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Annual Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2016, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
(a)
Management’s Report on Internal Control Over Financial Reporting
Our Management’s Report on Internal Control Over Financial Reporting is included on page of this Annual Report and is incorporated herein by reference. Management concluded that our internal control over financial reporting was effective as of December 31, 2016.
(b)
Changes in Internal Control Over Financial Reporting
In our Form 10-K for the year ended December 31, 2015, we identified and disclosed a material weakness in our controls over the valuation of certain assets in the Atlas mergers. Specifically, we did not have adequate controls in place over our review procedures associated with the development and application of inputs, assumptions, and calculations used in cash flow-based fair value measurements associated with business combinations, thus they did not operate as designed and at an appropriate level of detail commensurate with our financial reporting requirements. To remediate the material weakness, we implemented formal processes covering the development, application and review of inputs, assumptions, and calculations used in cash flow-based value measurements. We tested our formal processes in conjunction with developing our cash flow estimates necessary for our annual goodwill impairment evaluation in the fourth quarter of fiscal 2016. We successfully completed the testing necessary to conclude that this material weakness has been remediated.
There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
We are a limited partnership and, therefore, have no officers or directors. Unless otherwise indicated, references to our officers and directors in Items 10 through 14 of this Annual Report refer to the officers and directors of our general partner.
Management of Targa Resources Partners LP
Targa Resources GP LLC, our general partner, manages our operations and activities. Our general partner is not currently elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes fiduciary duties to our unitholders, but our partnership agreement contains various provisions modifying and restricting its fiduciary duties. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.
The directors of our general partner oversee our operations. Our general partner currently has ten directors. Targa GP Inc. elects all members to the board of directors of our general partner (the “Board”) and our general partner has six directors that are independent as defined under the independence standards established by the NYSE. The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating/corporate governance committee.
The Board has a standing audit committee (the “Audit Committee”) that consists of three directors. The members of our Audit Committee are Messrs. Tong and Redd and Ms. Fulton. Mr. Tong is the Chairman of this committee. Our board of directors has affirmatively determined that Messrs. Tong and Redd and Ms. Fulton are independent as described in the rules of the NYSE and the Exchange Act. Our board of directors has also determined that, based upon relevant experience, Mr. Tong is an “audit committee financial expert” as defined in Item 407 of Regulation S-K of the Exchange Act. This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the Audit Committee oversees our compliance programs relating to legal and regulatory requirements. We have adopted an Audit Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.
The compensation of our general partner’s executive officers is set by Targa, the indirect parent of our general partner, with the Board playing no role in the process. Compensation decisions relating to oversight of the long-term incentive plan described below, however, are made by the Board. While the Board may establish a compensation committee in the future, it has no current plans to do so.
All of our executive management personnel are employees of Targa Resources and devote their time as needed to conduct our and Targa’s business and affairs. These officers of Targa Resources manage the day-to-day affairs of our business. Because Targa’s only cash generating assets are direct and indirect partnership interests in us, we expect that our executive officers will devote a substantial majority of their time to our business. We expect the amount of time that the executive management personnel of our general partner devote to our business in future periods to be driven by the needs and demands of our ongoing business and business development efforts, which are likely to increase as our asset base and operations increase in size. However, depending on how our business develops and the nature of the business development efforts by executive management, the amount of time that the executive management team of our general partner devotes to our business may increase or decrease in future periods. We also utilize a significant number of employees of Targa Resources to operate our business and provide us with general and administrative services. We reimburse Targa for allocated expenses of operational personnel who perform services for our benefit, allocated general and administrative expenses and certain direct expenses. See “Reimbursement of Expenses of Our General Partner” included in this Item 10.
Directors, Executive Officers and Other Officers
Our general partner’s directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the Board. There are no family relationships among any of our general partner’s directors or executive officers. The following table shows information with respect to the current directors, executive officers and other officers of Targa Resources GP LLC as of February 17, 2017:
Name
Age
Position
Joe Bob Perkins
Chief Executive Officer and Director
James W. Whalen
Executive Chairman of the Board and Director
Michael A. Heim
Vice Chairman of the Board and Director
Jeffrey J. McParland
President-Finance and Administration
Paul W. Chung
Executive Vice President, General Counsel and Secretary
Matthew J. Meloy
Executive Vice President and Chief Financial Officer
John R. Sparger
Senior Vice President and Chief Accounting Officer
D. Scott Pryor
Executive Vice President - Logistics and Marketing
Patrick J. McDonie
Executive Vice President - Southern Field Gathering and Processing
Dan C. Middlebrooks
Executive Vice President - Northern Field Gathering and Processing
Clark White
Executive Vice President - Engineering and Operations
Rene R. Joyce
Director
Charles R. Crisp
Director
Chris Tong
Director
Ershel C. Redd Jr.
Director
Laura C. Fulton
Director
Waters S. Davis, IV
Director
Robert B. Evans
Director
Joe Bob Perkins has served as Chief Executive Officer and director of the Company and our general partner since January 1, 2012. Mr. Perkins previously served as President of the Company between the date of its formation on October 27, 2005 and December 31, 2011 and of our general partner between October 2006 and December 31, 2011. He also served as President of predecessor companies from 2003 through 2005. Mr. Perkins was an independent consultant in the energy industry from 2002 through 2003 and was an active partner in an outdoor advertising firm during a portion of such time period. Mr. Perkins served as President and Chief Operating Officer for the Wholesale Businesses, Wholesale Group and Power Generation Group of Reliant Resources, Inc. and its parent/predecessor companies, from 1998 to 2002 and Vice President, Corporate Planning and Development, of Houston Industries from 1996 to 1998. He served as Vice President, Business Development, of Coral Energy Holding, L.P. (“Coral”) from 1995 to 1996 and as Director, Business Development, of Tejas Gas Corporation (“Tejas”) from 1994 to 1995. Prior to 1994, Mr. Perkins held various positions with the consulting firm of McKinsey & Company and with an exploration and production company. Mr. Perkins’ intimate knowledge of all facets of the Company, derived from his service as President from its founding through 2011 and his current service as Chief Executive Officer and director, coupled with his broad experience in the oil and gas industry, and specifically in the midstream sector, his engineering and business educational background and his experience with the investment community enable Mr. Perkins to provide a valuable and unique perspective to the board on a range of business and management matters.
James W. Whalen has served as Executive Chairman of the Board of the Company and our general partner since January 1, 2015. Mr. Whalen has also served as a director of the Company since its formation on October 27, 2005 and of our general partner since February 2007. He also served as director of an affiliate of the Company during 2004 and 2005. Mr. Whalen previously served as Advisor to Chairman and CEO of the Company and our general partner between January 1, 2012 and December 31, 2014. He served as Executive Chairman of the Board of the Company between October 25, 2010 and December 31, 2011 and of our general partner between December 15, 2010 and December 31, 2011. He also served as President-Finance and Administration of the Company between January 2006 and October 2010 and our general partner between October 2006 and December 2010 and for various Targa subsidiaries since November 2005. Between October 2002 and October 2005, Mr. Whalen served as the Senior Vice President and Chief Financial Officer of Parker Drilling Company. Between January 2002 and October 2002, he was the Chief Financial Officer of Diversified Diagnostic Products, Inc. He served as Chief Commercial Officer of Coral from February 1998 through January 2000. Previously, he served as Chief Financial Officer for Tejas from 1992 to 1998. Mr. Whalen brings a breadth and depth of experience as an executive, board member, and audit committee member across several different companies and in energy and other industry areas. His valuable management and financial expertise includes an understanding of the accounting and financial matters that the Company and industry address on a regular basis.
Michael A. Heim has served as a director of the Company since March 1, 2016 and Vice Chairman of the Board since March 11, 2016. He has also served as a director and Vice Chairman of the Board of our general partner since November 12, 2015. Mr. Heim previously served as President and Chief Operating Officer of the Company and our general partner between January 1, 2012 and November 12, 2015. Mr. Heim previously served as Executive Vice President and Chief Operating Officer of the Company between the date of its formation on October 27, 2005 and December 2011 and of our general partner between October 2006 and December 2011. He also served as an officer of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliate during 2003. Mr. Heim also served as a consultant in the energy industry from 2001 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Heim served as Chief Operating Officer and Executive Vice President of Coastal Field Services, a subsidiary of The Coastal Corp. (“Coastal”) a diversified energy company, from 1997 to 2001 and President of Coastal States Gas Transmission Company from 1997 to 2001. In these positions, he was responsible for Coastal’s midstream gathering, processing, and marketing businesses. Prior to 1997, he served as an officer of several other Coastal exploration and production, marketing and midstream subsidiaries.
Jeffrey J. McParland has served as President - Finance and Administration of the Company since October 25, 2010 and of our general partner since December 15, 2010. He also served as Executive Vice President and Chief Financial Officer of the Company between October 27, 2005 and October 25, 2010. He also served as an officer of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliate during 2003. He served as Executive Vice President and Chief Financial Officer of our general partner between October 2006 and December 15, 2010 and served as a director of our general partner from October 2006 to February 2007. Mr. McParland served as Treasurer of the Company from October 27, 2005 until May 2007 and of our general partner from October 2006 until May 2007. Mr. McParland served as Senior Vice President, Finance of Dynegy Inc., a company engaged in power generation, the midstream natural gas business and energy marketing, from 2000 to 2002. In this position, he was responsible for corporate finance and treasury operations activities. He served as Senior Vice President, Chief Financial Officer and Treasurer of PG&E Gas Transmission, a midstream natural gas and regulated natural gas pipeline company, from 1999 to 2000. Prior to 1999, he worked in various engineering and finance positions with companies in the power generation and engineering and construction industries.
Paul W. Chung has served as Executive Vice President, General Counsel and Secretary of the Company since its formation on October 27, 2005 and of our general partner since October 2006. He also served as an officer of an affiliate of the Company during 2004 and 2005. Mr. Chung served as Executive Vice President and General Counsel of Coral from 1999 to April 2004; Shell Trading North America Company, a subsidiary of Shell Oil Company (“Shell”), from 2001 to April 2004; and Coral Energy, LLC from 1999 to 2001. In these positions, he was responsible for all legal and regulatory affairs. He served as Vice President and Assistant General Counsel of Tejas from 1996 to 1999. Prior to 1996, Mr. Chung held a number of legal positions with different companies, including the law firm of Vinson & Elkins L.L.P.
Matthew J. Meloy has served as Executive Vice President and Chief Financial Officer of the Company and our general partner since May 2015. He also served as Treasurer of the Company and our general partner until December 2015. Mr. Meloy previously served as Senior Vice President, Chief Financial Officer and Treasurer of the Company since October 25, 2010 and of our general partner since December 15, 2010. He also served as Vice President - Finance and Treasurer of the Company between April 2008 and October 2010, and as Director, Corporate Development of the Company between March 2006 and March 2008 and of our general partner between March 2006 and March 2008. He has served as Vice President - Finance and Treasurer of our general partner between April 2008 and December 15, 2010. Mr. Meloy was with The Royal Bank of Scotland in the structured finance group, focusing on the energy sector from October 2003 to March 2006, most recently serving as Assistant Vice President.
John R. Sparger has served as Senior Vice President and Chief Accounting Officer of the Company since January 2006 and of our general partner since October 2006. Mr. Sparger served as Vice President, Internal Audit of the Company between October 2005 and January 2006. He also served as an officer of an affiliate of the Company during 2004 and 2005. Mr. Sparger served as a consultant in the energy industry from 2002 through September 2004, providing advice to various energy companies and entities regarding processes, systems, accounting and internal controls. Prior to 2002, he worked in various accounting and administrative positions with companies in the energy industry, audit and consulting positions in public accounting and consulting positions with a large international consulting firm.
D. Scott Pryor, has served as Executive Vice President - Logistics and Marketing of the Company and our general partner since November 12, 2015. Mr. Pryor previously 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.
Patrick J. McDonie, has served as Executive Vice President - Southern Field Gathering and Processing of the Company and our general partner since November 12, 2015. Mr. McDonie previously 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.
Dan C. Middlebrooks, has served as Executive Vice President - Northern Field Gathering and Processing of the Company and our general partner since November 12, 2015. Mr. Middlebrooks 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 - Supply and Business Development of various subsidiaries of Targa Operating between June 2010 and May 2014 and has held officer positions with other Partnership subsidiaries since 2008.
Clark White, has served as Executive Vice President - Engineering and Operations of the Company and our general partner since November 12, 2015. Mr. White previously served as Senior Vice President - Field G&P of Targa Operating and various other
subsidiaries of the Partnership between June 2014 and November 2015. He also served as Vice President of Targa Operating between July 2011 and May 2014 and has held officer positions with other Partnership subsidiaries since 2003.
Rene R. Joyce has served as a director of the Company since its formation on October 27, 2005 and of our general partner since October 2006. Mr. Joyce previously served as Executive Chairman of the Board of our general partner between January 1, 2012 and December 31, 2014. He also served as Chief Executive Officer of the Company between October 27, 2005 and December 31, 2011 and our general partner between October 2006 and December 31, 2011. He also served as an officer and director of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliate during 2003. He also served as a member of the supervisory directors of Core Laboratories N.V. until May 2013. 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 council on the full range of business, technical, and professional matters.
Charles R. Crisp has served as a director of the Company since its formation on October 27, 2005 and of our general partner since March 1, 2016. He also served as a director of an affiliate of the Company during 2004 and 2005. Mr. Crisp was President and Chief Executive Officer of Coral Energy, LLC, a subsidiary of Shell from 1999 until his retirement in November 2000, and was President and Chief Operating Officer of Coral from January 1998 through February 1999. Prior to this, Mr. Crisp served as President of the power generation group of Houston Industries and, between 1988 and 1996, as President and Chief Operating Officer of Tejas. Mr. Crisp is also a director of Southern Company Gas (formerly known as AGL Resources Inc.), a subsidiary of The Southern Company, EOG Resources Inc. and Intercontinental Exchange Inc. Mr. Crisp brings extensive energy experience, a vast understanding of many aspects of our industry and experience serving on the boards of other public companies in the energy industry. His leadership and business experience and deep knowledge of various sectors of the energy industry bring a crucial insight to the board of directors.
Chris Tong has served as a director of the Company since January 2006 and of our general partner since March 1, 2016. Mr. Tong is a director of Kosmos Energy Ltd. He also served as a director of Cloud Peak Energy Inc. from October 2009 until May 2012. He served as Senior Vice President and Chief Financial Officer of Noble Energy, Inc. from January 2005 until August 2009. He also served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. from August 1997 until December 2004. Prior thereto, he was Senior Vice President of Finance of Tejas Acadian Holding Company and its subsidiaries, including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions from August 1996 until August 1997, and had served in other treasury positions with Tejas since August 1989. Mr. Tong brings a breadth and depth of experience as a chief financial officer in the energy industry, a financial executive, a director of other public companies and a member of other audit committees. He brings significant financial, capital markets and energy industry experience to the board and in his position as the chairman of our Audit Committee.
Ershel C. Redd Jr. has served as a director of the Company since February 2011 and of our general partner since March 1, 2016. Mr. Redd has served as a consultant in the energy industry since 2008 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Redd was President and Chief Executive Officer of El Paso Electric Company, a public utility company, from May 2007 until March 2008. Prior to this, Mr. Redd served in various positions with NRG Energy, Inc., a wholesale energy company, including as Executive Vice President - Commercial Operations from October 2002 through July 2006, as President - Western Region from February 2004 through July 2006, and as a director between May 2003 and December 2003. Mr. Redd served as Vice President of Business Development for Xcel Energy Markets, a unit of Xcel Energy Inc., from 2000 through 2002, and as President and Chief Operating Officer for New Century Energy’s (predecessor to Xcel Energy Inc.) subsidiary, Texas Ohio Gas Company, from 1997 through 2000. Mr. Redd brings to the Company extensive energy industry experience, a vast understanding of varied aspects of the energy industry and experience in corporate performance, marketing and trading of natural gas and natural gas liquids, risk management, finance, acquisitions and divestitures, business development, regulatory relations and strategic planning. His leadership and business experience and deep knowledge of various sectors of the energy industry bring a crucial insight to the board of directors.
Laura C. Fulton has served as a director of the Company since February 26, 2013 and of our general partner since March 1, 2016. Ms. Fulton has served as the Chief Financial Officer of Hi-Crush Proppants LLC since April 2012 and Hi-Crush GP LLC, the general partner of Hi-Crush Partners LP, since May 2012. From March 2008 to October 2011, Ms. Fulton served as Executive Vice President, Accounting and then Executive Vice President, Chief Financial Officer of AEI Services, LLC (“AEI”), an owner and operator of essential energy infrastructure assets in emerging markets. Prior to AEI, Ms. Fulton spent 12 years with Lyondell
Chemical Company in various capacities, including as general auditor responsible for internal audit and the Sarbanes-Oxley certification process, and as the assistant controller. Prior to that, she spent 11 years with Deloitte & Touche in public accounting, with a focus on audit and assurance. As a chief financial officer, general auditor and external auditor, Ms. Fulton brings to the company extensive financial, accounting and compliance process experience. Ms. Fulton’s experience as a financial executive in the energy industry, including her current position with a master limited partnership, also brings industry and capital markets experience to the board.
Waters S. Davis, IV has served as director of the Company since July 2015 and of our general partner since March 1, 2016. Mr. Davis has served as President of National Christian Foundation, Houston since July 2014. Mr. Davis was Executive Vice President of NuDevco LLC from December 2009 to December 2013. Prior to his employment with NuDevco, he served as President of Reliant Energy Retail Services from June 1999 to January 2002 and as Executive Vice President of Spark Energy from April 2007 to November 2009. He previously served as a senior executive at a number of private companies and as an advisor to a private equity firm, providing operational and strategic guidance. Mr. Davis also serves as a director of Milacron Holdings Corp. Mr. Davis brings expertise in the retail energy, midstream and services industries, which enhances his contributions to the board of directors.
Robert B. Evans has served as a director of the Company since March 1, 2016 and of our general partner since February 2007. Mr. Evans is also a director of New Jersey Resources Corporation, Sprague Resources GP LLC and One Gas, Inc. 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.
Reimbursement of Expenses of Our General Partner
Under the terms of our Partnership Agreement, we reimburse Targa for all direct and indirect expenses, as well as expenses otherwise allocable to us in connection with the operation of our business, incurred on our behalf, which includes certain operating and direct expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for our benefit. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. We reimburse Targa for the direct expenses to provide these services as well as other direct expenses it incurs on our behalf, such as compensation of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits. Other than Targa’s direct costs of being a public reporting company, substantially all of Targa’s general and administrative costs have been, so long as Targa’s only cash-generating assets consist of its interest in us, and will continue to be allocated to us. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Corporate Governance
Code of Business Conduct and Ethics
Our general partner has adopted a Code of Ethics For Chief Executive Officer and Senior Financial Officers (the “Code of Ethics”), which applies to our general partner’s Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller and all of our other senior financial and accounting officers, and our Code of Conduct (the “Code of Conduct”), which applies to officers, directors and employees of the Company and its subsidiaries, including our general partner. In accordance with the disclosure requirements of applicable law or regulation, we intend to disclose any amendment to, or waiver from, any provision of the Code of Ethics or Code of Conduct under Item 5.05 of a current report on Form 8-K.
Available Information
We make available, free of charge within the “Corporate Governance” section of our website at http://www.targaresources.com and in print to any unitholder who so requests, our Corporate Governance Guidelines, Code of Ethics, Code of Conduct and the Audit Committee Charter. Requests for print copies may be directed to: Investor Relations, Targa Resources Partners LP, 1000 Louisiana, Suite 4300, Houston, Texas 77002 or made by telephone by calling (713) 584-1000. The information contained on or connected to, our internet website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
Corporate Governance Guidelines
Our general partner’s board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE.
Executive Sessions of Non-Management Directors
Our non-management directors meet in executive session without management participation at regularly scheduled executive sessions. These meetings are chaired by Mr. Crisp.
Interested parties may communicate directly with our non-management directors by writing to: Non-Management Directors, Targa Resources Partners LP, 1000 Louisiana, Suite 4300, Houston, Texas 77002.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our directors, executive officers and 10% unitholders to file with the SEC reports of ownership and changes in ownership of our equity securities that are registered pursuant to Section 12 of the Exchange Act. Based solely upon a review of the copies of the Form 3, 4 and 5 reports furnished to us and certifications from our directors and executive officers, we believe that during 2016, all of our directors, executive officers and beneficial owners of more than 10% of our Preferred Units complied with Section 16(a) filing requirements applicable to them.
Item 11.
Item 11. Executive Compensation.
COMPENSATION DISCUSSION AND ANALYSIS
The following Compensation Discussion and Analysis (“CD&A”) contains statements regarding our compensation programs and our executive officers’ business priorities related to our compensation programs and target payouts under the programs. These business priorities are disclosed in the limited context of our compensation programs and should not be understood to be statements of management’s expectations or estimates of results or other guidance.
Overview
Neither we nor our general partner directly employ any of the persons responsible for managing our business. Any compensation decisions that are required to be made by our general partner will be made by the board of directors of our general partner, which does not have a compensation committee. All of our general partner’s executive officers are employees of Targa Resources Corp.
For 2016, our general partner’s “named executive officers,” identified in the Summary Compensation Table, were:
Name
Position During 2016
Joe Bob Perkins
Chief Executive Officer
Michael A. Heim
Vice Chairman of the Board
Jeffrey J. McParland
President-Finance and Administration
Paul W. Chung
Executive Vice President, General Counsel and Secretary
Matthew J. Meloy
Executive Vice President and Chief Financial Officer
The named executive officers of Targa also served as executive officers of our general partner during 2016. The named executive officers devote their time as needed to the conduct of our business and affairs and the conduct of the Company’s business and affairs. Immediately prior to completion of the merger pursuant to which the Company acquired all of the Partnership common units not already owned by it (the “Buy-In Transaction”) on February 17, 2016, the Company owned an 8.8% interest in the Partnership, including the 2% general partner interest, and was the indirect parent of the general partner. Following completion of the Buy-In Transaction, the Partnership’s common units ceased to be publicly traded.
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 the Company and for the services they provide to our general partner and us for the years indicated. For 2016, all decisions regarding named executive officer compensation were made by the Compensation Committee of Targa’s board of directors (the “Compensation Committee”). During 2016, we reimbursed the Company and its affiliates for the compensation of the named executive officers pursuant to our partnership agreement. See “-Certain Relationships and Related Transactions, and Director Independence-Partnership Agreement” for additional information regarding our reimbursement obligations for 2016.
The Compensation Committee believes that the actions it has taken to govern compensation in a responsible way as described in this CD&A and our performance demonstrates that the compensation programs are structured to pay reasonable amounts for performance based on Targa’s understanding of the markets in which we compete for executive talent.
Targa held its last advisory say on pay vote regarding executive compensation at its 2014 Annual Meeting. At that meeting, more than 99% of the votes cast by Targa’s shareholders approved the compensation paid to its named executive officers as described in the CD&A and the other related compensation tables and disclosures contained in Targa’s Proxy Statement filed with the SEC on April 7, 2014. Targa’s board of directors and the Compensation Committee reviewed the results of this vote and concluded that, with this level of support, no changes to the compensation design and philosophy needed to be considered as a result of the say on pay vote. In accordance with the preference expressed by Targa’s shareholders to conduct an advisory vote on executive compensation every three years, the next advisory vote will occur this year at the 2017 Annual Meeting. At the 2017 Annual Meeting, Targa’s shareholders will also have the opportunity to vote on the frequency of future advisory votes on executive compensation. We are generally not subject to the advisory say on pay vote requirements under the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.
The following CD&A is presented from the perspective of the Compensation Committee and discusses our general partner’s named executive officers in their roles as officers of Targa. The elements of compensation and the Compensation Committee’s decisions with respect to determination on payments are not subject to approval by the board of directors of our general partner or the board of directors of Targa (the “Targa Board”). All members of the board of directors of our general partner are members of the Targa Board. As used in this CD&A (other than in this “Overview”), references to “our,” “we,” “us,” the “Company,” and similar terms refer to Targa, references to the “Board” or “Board of Directors” refers to the Targa Board, and references to the Partnership refer to us, Targa Resources Partners LP.
Summary of Key Strategic Results
As noted above, our main source of cash flow is from our general and limited partner interests and, prior to completion of the Buy-In Transaction, our incentive distribution rights 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, our 2016 strategic and operational accomplishments and our 2016 financial results (including the financial results of the Partnership on a consolidated basis) demonstrate the performance of our businesses through the industry downturn, which, along with our ongoing growth capital expenditure programs, have allowed us to increase both our business scale and diversity. In summary, some of our more significant financial, operational and strategic highlights in 2016 included:
•
Excellent execution across our businesses, despite a commodity price environment substantially below expectations, with Partnership Adjusted EBITDA of $1.047 billion, Field G&P and export volumes essentially flat to 2015 and at or above public guidance, and dividend coverage that achieved public guidance;
•
Excellent execution on 2016 growth capital expenditures of approximately $506 million for expansion projects completed or on track to be completed on time and near budget;
•
Continued development of our potential future expansion project portfolio;
•
Excellent financial execution including capital raising and balance sheet and liquidity management while funding growth expenditures and maintaining dividend per share; and
•
A continued strong track record and performance regarding safety, including industry safety recognition in 2016, although less than satisfactory performance with respect to maintaining adequate internal controls, and strong compliance performance in all other aspects of our business, including environmental and regulatory compliance.
See “-Components of Executive Compensation Program for Fiscal 2016-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, 2016 for a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities.
As we enter 2017, our industry continues to be significantly impacted by low crude oil, natural gas and NGL prices. In this period of commodity price uncertainty, we have adapted our business strategies to preserve liquidity and financial strength. We believe the Buy-In Transaction, which was completed on February 17, 2016, and other financial measures completed during 2016, including the private placement of the Series A Preferred Stock by the Company, the senior notes offerings by the Partnership and the amendment and extension of the Partnership’s credit facility, have already provided immediate benefits and will provide long-term benefits to the Company’s and the Partnership’s investors, and best positions the combined companies to manage successfully through the current commodity price environment with an improved coverage and credit profile, simplified corporate structure and lower cost of capital.
Summary of 2016 and 2017 Compensation Decisions
While the compensation arrangements for our named executive officers during fiscal 2016 remained substantially similar to those in place during fiscal 2015, specific compensatory actions in 2016 included the following:
•
2016 Annual Bonus Pool and NEO Awards Paid in a Combination of Stock and Cash. Even though our overall performance of the 2016 business priorities significantly exceeded expectations for the year (as was the case for 2015), in light of the challenging industry conditions in 2016 and early 2017 and continued uncertainty in the market, the bonus pool was funded at 125% of target under the 2016 Bonus Plan. In connection with this approval and our current focus on reducing cash expenses, the Compensation Committee approved settlement of the 2016 bonuses in a combination of cash and restricted stock unit awards, instead of all-cash bonuses, for all Company officers including the named executive officers. The restricted stock unit awards will vest in full three years after the date of grant of the award, subject to continued employment of the officers through that date. See “-Components of Executive Compensation Program for Fiscal 2016-Annual Incentive Bonus” for additional information.
•
No Changes to NEO Compensation Levels (Except for Mr. Meloy). In the context of the difficult industry environment, the Compensation Committee approved management’s recommendations for no changes to the base salaries, target bonus percentages and long-term equity incentive award opportunities for the named executive officers for 2016, other than Mr. Meloy. The changes to Mr. Meloy’s compensation were made consistent with a multi-year phased transition to bring his total direct compensation more closely in line with the total direct compensation provided to similarly situated executives at companies within our 2016 Peer Group, adjusted for company size.
•
CEO and Executive Chairman Base Salary Paid in Stock. Consistent with the recommendation of Mr. Perkins and Mr. Whalen, and at their request and in the context of a difficult industry environment including commodity price levels and related uncertainties and the resulting impact on the Company’s businesses and customers, the Compensation Committee approved awards of quarterly grants of restricted stock to Mr. Perkins and to Mr. Whalen in lieu of all of their 2016 base salary. See “-Components of Executive Compensation Program for Fiscal 2016-Base Salary” for additional information.
•
No Partnership Equity Awards Due to Buy-In Transaction. For 2016, the Compensation Committee awarded the full amount of the annual long-term equity incentive awards in the form of restricted stock unit awards under our Stock Incentive Plan (instead of utilizing a combination of long-term incentive awards settled in both Company equity and Partnership equity as had been the case in recent years) due to the pending closing of the Buy-In Transaction, which resulted in Partnership common units ceasing to be publicly traded. As discussed in further detail below under “-Changes for 2017-Long-Term Equity Incentive Awards,” for the Company’s 2017 long-term equity incentive awards, the Compensation Committee granted a portion of such 2017 awards in the form of performance share units tied to relative total shareholder return.
With respect to 2017 compensation, the Compensation Committee has made the following determinations, which are described in greater detail below under “-Changes for 2017”:
•
Increases to 2017 Total Compensation and Limited Increases to Base Pay. For 2017, base salary raises were approved for the named executive officers (other than Messrs. Heim and McParland) ranging from 2.0% to 3.4%. The Compensation Committee authorized base salary increases for certain 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 2017 Peer Group, adjusted for company size, and, in the case of Mr. Meloy, to reflect professional growth and the assumption of additional responsibilities. See “-Changes for 2017-2017 Peer Group” for a description of the companies that comprise the 2017 Peer Group. In addition, for 2017 under our annual incentive bonus plan, the target bonus percentages for our named executive officers (other than Mr. Heim) were increased in order to align their total direct compensation more closely with the total direct compensation provided to similarly situated officers at companies within our 2017 Peer Group, adjusted for company size. For similar reasons, the long-term equity incentive award opportunities for 2017 for the named executive officers (other than Mr. Heim) were also increased.
•
New Performance-Based Equity Award Component. For 2017, the Compensation Committee awarded long-term equity incentive awards in the form of both restricted stock unit awards and performance share units 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 the members of a specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periods. The overall performance period for the 2017 performance share units begins on January 1, 2017 and is designated to end on December 31, 2019, 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 three year relative TSR over the entirety of the 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. 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 Compensation Committee in its discretion. Provided a named executive officer remains continuously employed through the end of 2019, he will become vested, as soon as practicable following December 31, 2019, in a number of performance share units equal the target number awarded multiplied by the TSR performance factor, and vested performance share units will be settled by the issuance of Company common stock. The Compensation Committee believes the performance share unit awards further align the interests of named executive officers and shareholders and provide meaningful incentives to the management team to consistently increase shareholder value over the long-term.
Discussion and Analysis of Executive Compensation
Compensation Philosophy and Elements
The following compensation objectives guide the Compensation Committee in its deliberations about executive compensation matters:
•
Competition Among Peers. The Compensation Committee believes our executive compensation program should enable us to attract and retain key executives by providing a total compensation program that is competitive with the market in which we compete for executive talent, which encompasses not only diversified midstream companies but also other energy industry companies as described in “-Methodology and Process-Role of Peer Group and Benchmarking” below.
•
Accountability for Performance. The Compensation Committee believes our executive compensation program should ensure an alignment between our strategic, operational and financial performance and the total compensation received by our named executive officers. This includes providing compensation for performance that reflects individual and company performance both in absolute terms and relative to our Peer Group.
•
Alignment with Shareholder Interests. The Compensation Committee believes our executive compensation program should ensure a balance between short-term and long-term compensation while emphasizing at-risk or variable compensation as a valuable means of supporting our strategic goals and aligning the interests of our named executive officers with those of our shareholders.
•
Supportive of Business Goals. The Compensation Committee believes that our total compensation program should support our business objectives and priorities.
Consistent with this philosophy and the compensation objectives, our 2016 executive compensation program consisted of the following elements:
Compensation Element
Description
Role in Total Compensation
Base Salary
Competitive fixed-cash compensation based on an individual’s role, experience, qualifications and performance
•A core element of competitive total compensation, important in attracting and retaining key executives
Annual Incentive Bonus
Variable payouts tied to achievement of annual financial, operational and strategic business priorities and determined in the sole discretion of the Compensation Committee
•Aligns named executive officers with annual strategic, operational and financial results
•Recognizes individual and performance-based contributions to annual results
•Supplements base salary to help attract and retain executives
Long-Term Equity Incentive Awards
Restricted stock 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
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” cash change in control payments
Accelerated vesting of equity awards upon certain change in control transactions and qualifying termination events
Continued vesting of equity awards following retirement, subject to provision of consulting services or compliance with non-compete obligations
•Helps mitigate possible disincentives to pursue value-added merger or acquisition transactions if employment prospects are uncertain
•Provides assistance with transition if post-transaction employment is not offered
•Allows the Company to benefit from employee non-compete obligations and ongoing access to cooperative employees
Perquisites
None, other than minimal parking subsidies
•The Compensation Committee’s policy is not to pay for perquisites for any of our named executive officers, other than minimal parking subsidies
Fiscal 2016 Total Direct Compensation
We review the mix of base salary, annual incentive bonuses and long-term equity incentive awards (i.e., total direct compensation) each year for the Company and for our Peer Group. We view the various components of total direct compensation as related but distinct and emphasize pay for performance, with a significant portion of total direct compensation reflecting a risk aspect tied to long-
and short-term financial and strategic goals. Although we typically target annual long-term equity incentive awards as a percentage of base salary, we have historically not operated under any formal policies or specific guidelines for allocating compensation between long-term and currently paid out compensation, between cash and non-cash compensation, or among different forms of non-cash compensation. However, we believe that our compensation packages are representative of an appropriate mix of compensation components, and we anticipate that we will generally continue to utilize a similar, though not identical, mix of compensation in future years. As recommended by the Compensation Consultant, the Compensation Committee seeks to provide our named executive officers with a mix of base salary and short- and long-term incentives that is generally in line with that provided to similarly situated executives in our Peer Group, adjusted for company size.
The approximate allocation of target total direct compensation for our named executive officers in fiscal 2016 is presented below. This reflects (i) the salary rates in effect as of December 31, 2016, (ii) target annual incentive bonuses for services performed in fiscal 2016, and (iii) the grant date fair value of long-term equity incentive awards granted during fiscal 2016 (excluding the grant date fair value of equity awards granted in 2016 in lieu of 2015 annual incentive cash bonus payments and the grant date fair value of restricted stock awards received by Mr. Perkins in lieu of 2016 base salary).
Fiscal 2016 Target Total Direct Compensation
(1) Mr. Perkins elected to receive quarterly grants of restricted stock awards in lieu of all of his 2016 base salary.
(2) Annual incentive bonuses actually paid for 2016 were paid 50% in cash and 50% in the form of restricted stock unit awards that will vest in full three years after the date of the award, subject to continued employment of the officers through that date.
Over the last four 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 the peer companies. The implied market median compensation level is determined by the Compensation Consultant using a regression analysis for our Peer Group that adjusts for 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 four 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 with dashed border, the 90th percentile is shown as the white bar with dotted border and the target compensation for our Chief Executive Officer is shown as the yellow bar.
Because incentive compensation (i.e., target annual incentive bonus and grant date fair value of long-term equity incentive awards) comprised 82% of our Chief Executive Officer’s total direct compensation opportunity for 2016 and he elected to receive quarterly grants of restricted stock in lieu of all of his 2016 base salary, 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 performance of our common stock.
Annual Total Shareholder Return
In the last four calendar years, we have delivered annual total returns to our shareholders of 120.7% (for 2016), -71.3% (for 2015), 23.3% (for 2014) and 70.8% (for 2013).
Methodology and Process
Role of Compensation Consultant in Setting Compensation
The Compensation Committee retained BDO as its independent Compensation Consultant to advise the Compensation Committee on matters related to executive and non-management director compensation for 2016. During 2015 and 2016, the Compensation Committee received advice from the Compensation Consultant with respect to the development and structure of our 2016 executive compensation program. As discussed above under “Meetings and Committees of Directors-Committees of the Board of Directors-Compensation Committee,” the Compensation Committee has concluded that we do not have any conflicts of interest with the Compensation Consultant.
Role of Peer Group and Benchmarking
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 factor 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) available compensation data, rankings and comparisons, (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 our 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 2016 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.
Because many companies in the Peer Group may be 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 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 2016, the regressed data was analyzed separately for each of the three comparator groups and then weighted as follows to develop a reference point 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). For 2016, the “Peer Group” companies (for purposes of determining 2016 compensation levels) were:
•
Midstream Companies: Access Midstream Partners, L.P., Boardwalk Pipeline Partners, L.P., Buckeye Partners, L.P., Crestwood Equity Partners, L.P., DCP Midstream Partners, L.P., Enable Midstream Partners, L.P., Enbridge Energy Partners, L.P., Energy Transfer Partners, L.P., EnLink Midstream Partners, L.P., Enterprise Products Partners L.P., Genesis Energy, L.P., Magellan Midstream Partners, L.P., MarkWest Energy Partners, L.P., NuStar Energy L.P., ONEOK, Inc., Plains All American Pipeline, L.P., Regency Energy Partners L.P., Summit Midstream Partners, L.P. and Williams Companies, Inc.
•
E&P peer companies: Apache Corporation, Cabot Oil & Gas Corporation, Cimarex Energy Company, Denbury Resources Inc., Devon Energy Corporation, EOG Resources, Inc., Halcon Resources Corporation, Murphy Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Pioneer Natural Resources Company, QEP Resources, Inc., SM Energy Company, Southwestern Energy Company and Ultra Petroleum Corporation
•
Utility peer companies: AGL Resources, Inc., Ameren Corporation, Atmos Energy Corporation, CenterPoint Energy, Inc., Dominion Resources, Inc., DTE Energy Company, Enbridge Inc., EQT Corporation, National Fuel Gas Company, NiSource Inc., Questar Corporation, Sempra Energy, Spectra Energy Corp. and TransCanada Corporation
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. Based upon the recommendation of our Compensation Consultant, we made the following changes to the 2015 Peer Group used for compensation comparison purposes to create the 2016 Peer Group: (i) added Crestwood Equity Partners, L.P. as a Midstream Company and (ii) removed Atlas as a Midstream Company due to its acquisition by the Company in 2015.
Senior management and the Compensation Committee review our compensation-setting practices and Peer Group companies on at least an annual basis. See “-Changes for 2017-2017 Peer Group” for a description of the changes that were made to the Peer Group for 2017 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 submits emerging conclusions to the Chairman of the Compensation Committee, meets periodically with the full Compensation Committee together with the 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, the full Board of Directors and/or, prior to the Buy-In Transaction, the full board of directors of the General Partner. The Chairman of the Compensation Committee may request that senior management provide him with additional information or reconsider or revise the proposal. The resulting recommendation is then submitted for consideration to the full Compensation Committee, which typically invites other members of the Board of Directors and, prior to the Buy-In Transaction, the directors of the General Partner, and also meets separately with the Compensation Consultant. 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 other than our Section 16 officers. Our executive officers are delegated the authority and responsibility to determine the compensation for all other employees.
Components of Executive Compensation Program for Fiscal 2016
Base Salary
The base salaries for our named executive officers are set and reviewed annually by the Compensation Committee. Base salaries for our named executive officers have been established based on Peer Group analysis and historical salary levels for these officers, as well as the relationship of their salaries to those of our other executive officers, taking into consideration the value of the total direct compensation opportunities available to our executive officers, including the annual incentive bonus and long-term equity incentive award components of our compensation program. The other factors listed above under “- Methodology and Process - Role of Peer Group and Benchmarking” are also considered.
For 2016, at management’s recommendation and as a result of a challenging industry environment, the Compensation Committee did not authorize any changes to the base salary rates in effect for the named executive officers during 2016, other than for Mr. Meloy, whose base salary was increased from $400,000 to $460,000, effective March 1, 2016. The change to Mr. Meloy’s base salary is part of a phased transition to bring his total direct compensation more closely in line with the total direct compensation provided to similarly situated executives. The 2016 base salary rates for our named executive officers were as follows:
Prior Salary
Base Salary Effective March 1, 2016
Percent Increase
Joe Bob Perkins
$ 725,000
$ 725,000
0%
Michael A. Heim
600,000
600,000
0%
Jeffrey J. McParland
500,000
500,000
0%
Paul W. Chung
490,000
490,000
0%
Matthew J. Meloy
400,000
460,000
15%
Consistent with the recommendation of Mr. Perkins and Mr. Whalen, and at their request and in the context of a difficult industry environment including commodity price levels and related uncertainties and the resulting impact on the Company’s businesses and customers, the Compensation Committee approved quarterly grants of restricted stock to Mr. Perkins and to Mr. Whalen in lieu of all of their 2016 base salary. These restricted stock awards were granted on the last business day of each quarter, except for the fourth quarter when the awards were granted in connection with the last payroll run of the calendar year, each with a one year vesting period. The number of restricted shares 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 all trading days during the quarter ending on the date that was five business days prior to the grant date.
Annual Incentive Bonus
For 2016, our named executive officers were eligible to receive annual incentive bonuses under the 2016 Annual Incentive Plan (the “2016 Bonus Plan”), which was approved by the Compensation Committee in January 2016. 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 and will generally be determined near or following the end of the year to which the bonus relates.
Target Bonus Amounts. The target amount of the bonus pool for the named executive officers is equal to the sum of the target bonus amounts for all named executive officers in the 2016 Bonus Plan. 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 2016 Bonus Plan, the percentage of base salary that was set as the “target” amount for each named executive officer’s bonus was as follows:
Target Bonus Percentage
(as a % of Base Salary)
Target Bonus Amount
Joe Bob Perkins
100%
$ 725,000
Michael A. Heim
90%
540,000
Jeffrey J. McParland
90%
450,000
Paul W. Chung
90%
441,000
Matthew J. Meloy
90%
414,000
For 2016, the target bonus percentage for Mr. Meloy was increased from 80% to 90% to align his total direct compensation more closely with the total direct compensation provided to similarly situated executives. The Compensation Committee did not change the target bonus percentages for the other named executive officers from the levels in effect in 2015.
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.
2016 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 2016 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 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 2016 Bonus Plan, the Compensation Committee focused on the business priorities listed in the table below. The 2016 business priorities are substantially similar to those in effect for 2015 but were revised to modify certain objectives and to remove certain goals that had been achieved in 2015 (such as closing of the Atlas mergers and expansion of certain capabilities of our Badlands operations). 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.
2016 Business Priority
Committee Consensus
Overall Assessment
Execute on all business dimensions, including the 2016 business plan and dividend guidance
Exceeded
•Closed corporate restructuring with Buy-In Transaction in the first quarter
•Excellent execution across our businesses, particularly given the current industry environment and despite a commodity price environment substantially below expectations:
oYear-over-year volumes essentially flat for Field G&P inlet, Badlands crude oil and LPG exports; while fractionation volumes decreased and Badlands gas volumes increased
oMet or exceeded volume beginning of year guidance for Field G&P and LPG exports, and met dividend coverage guidance provided during the year
oExcellent balance sheet and liquidity management while funding $506 million of growth capital expenditures and maintaining flat dividend per share
oSignificant operating cost savings and improvements in G&P margins
•Strong track record and performance regarding safety and compliance in all aspects of our business, including on-going training and environmental and regulatory compliance; continued industry recognition through safety awards
•Did not maintain adequate controls over the valuation of certain assets in the Atlas mergers or effective controls over the preparation and review of income tax provisions for interim periods
•Successful talent retention and hiring while continuing organizational realignments to streamline operations and to provide development opportunities for employees
•Closed or entered into definitive agreements for several strategic acquisitions, including:
oChevron’s interest in the Versado G&P business
oOutrigger’s Midland and Delaware Basin G&P and crude oil gathering operations
•2016 growth capital expenditures of approximately $506 million completed or on track to be completed on or ahead of schedule and on or below budget, including:
oStart-up of CBF Train 5
oStart-up of Buffalo Plant
oOngoing construction of Noble Crude and Condensate Splitter; Sanchez Energy JV in South Texas; and Joyce Processing Plant in West Texas
•Continued development of our potential future expansion project portfolio
•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 negotiation of contract renewals and new dedications
Continue priority emphasis and strong performance relative to a safe workplace
Strongly Achieved
Reinforce business philosophy and mindset that promote compliance in all aspects of our business including environmental and regulatory compliance
Not Achieved with respect to internal controls
Exceeded in all other dimensions
Continue to attract and retain the operational and professional talent needed in our businesses
Exceeded
Continue to control all costs-operating, capital and general and administrative (“G&A”) consistent with the existing business environment
Exceeded
Execute on major capital and development projects-finalizing negotiations, completing projects on time and on budget, and optimizing economics and capital funding
Exceeded
Pursue selected growth opportunities, including gathering and processing (“G&P”) build outs, fee-based capital expenditure projects, and potential purchases of strategic assets
Exceeded
Pursue commercial and financial approaches to achieve maximum value and manage risks, including contract, credit, inventory, interest rate and commodity price exposures
Exceeded
After assessing the results of the 2016 business priorities as summarized above, the Compensation Committee determined in January 2017 that overall performance relative to the 2016 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 2016 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 2016. 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.
Despite the Compensation Committee’s determination that overall performance of the 2016 business priorities substantially exceeded expectations for the year, in light of the challenging industry conditions in 2016 and early 2017 and continued uncertainty in the market, the Compensation Committee, in its sole discretion, approved an annual bonus pool equal to 125% of the target level under the 2016 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 2016. As a result, the Compensation Committee determined that a performance multiplier of 1.0x should be applied to each named executive officer for 2016 based on his individual performance and performance as part of the executive team.
Settlement of 2016 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 2016 bonuses in a combination of cash and restricted stock unit awards, instead of all-cash bonuses, for all Company officers including the named executive officers. All other employees of the Company and its subsidiaries received payment of their awards under the 2016 Bonus Plan solely in the form of cash.
Specifically, the Compensation Committee determined that approximately 50% of each officer’s total bonus amount would be settled in the form of restricted stock unit awards, resulting in these officers receiving restricted stock unit awards corresponding to approximately 62.5% of their respective target bonus amounts under the 2016 Bonus Plan. The number of restricted stock units actually awarded to each named executive officer will be determined by dividing the total dollar value allocated to the equity portion of the bonus amount by the ten-day average closing price of the shares of common stock for the first ten trading days of 2017. These restricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officers through that date. The following table reflects the awards actually received by our named executive officers under the 2016 Bonus Plan, including the approximate value of restricted stock unit awards to be received:
Target Bonus Amount
Individual Performance Factor
Company Performance Factor
Total Bonus Amount To Be Received
Cash Amount To Be Paid
Approximate Value of Restricted Stock Units To Be Awarded
Joe Bob Perkins
$725,000
1.0
1.25
$906,250
$453,125
$453,125
Michael A. Heim
540,000
1.0
1.25
675,000
337,500
337,500
Jeffrey J. McParland
450,000
1.0
1.25
562,500
281,250
281,250
Paul W. Chung
441,000
1.0
1.25
551,250
275,625
275,625
Matthew J. Meloy
414,000
1.0
1.25
517,500
258,750
258,750
Long-Term Equity Incentive Awards
In connection with our initial public offering in December 2010, we adopted 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 will be asked to approve the amendment and restatement of the Stock Incentive Plan in order to make available additional shares of common stock for the future grant of equity-based awards to our officers, employees, consultants and directors. See “Item 5 - Approval of the Amended and Restated 2010 Stock Incentive Plan.”
In addition, prior to the Buy-In Transaction, 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 Buy-In Transaction, 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 2016. 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 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. Our named executive officers have historically received annual long-term equity incentive compensation in a combination of awards related to our common stock granted under the Stock Incentive Plan and awards related to the Partnership’s common units granted under the Long-Term Incentive Plan. For example, for 2015, our named executive officers’ long-term incentive compensation was allocated approximately (i) forty percent (40%) to restricted stock units under the Stock Incentive Plan, which are time-based awards that capture absolute total return performance of our common stock, and (ii) sixty percent (60%) equity-settled performance unit awards under the Partnership’s Long-Term Incentive Plan, which were intended to reflect both the absolute total return of the Partnership’s common units and variable performance based on the total return of the Partnership’s units in relation to that of specified peer companies. Due to the then pending Buy-In Transaction, which resulted in the Partnership’s common units ceasing to be publicly traded, the Compensation Committee determined that the long-term equity incentive component of our named executive officers’ compensation for 2016 would consist solely of restricted stock unit awards under the Stock Incentive Plan. See “-Changes for 2017-Long-Term Equity Incentive Awards” below for a description of performance-based equity awards granted as part of our named executive officers’ 2017 compensation.
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 2016, 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:
Percentage of Base Salary
Total Dollar Value of Long-Term Equity Incentive Awards
Joe Bob Perkins
350%
$ 2,537,500
Michael A. Heim
250%
1,500,000
Jeffrey J. McParland
200%
1,000,000
Paul W. Chung
200%
980,000
Matthew J. Meloy
190%
874,000
For 2016, the percentage of base salary used to determine the total dollar value of the annual long-term equity incentive awards granted to all named executive officers remained the same as in 2015, and the actual total dollar value of the long-term equity incentive awards granted in 2016 therefore also remained the same for all named executives officers (other than Mr. Meloy, whose total dollar value increased due to the increase in his base salary rate for the applicable period).
2016 Restricted Stock Unit Awards. On January 19, 2016, our named executive officers were awarded equity-settled restricted stock units under the Stock Incentive Plan in the following amounts: (i) 102,484 restricted stock units to Mr. Perkins, (ii) 60,582 restricted stock units to Mr. Heim, (iii) 40,388 restricted stock units to Mr. McParland, (iv) 39,580 restricted stock units to Mr. Chung and (v) 35,299 restricted stock units to Mr. Meloy. 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.
Conversion of Outstanding Partnership Equity Awards in the Buy-In Transaction. Upon completion of the Buy-In Transaction, all outstanding performance unit awards previously granted under the Partnership’s Long-Term Incentive Plan (which, as described above, was assumed by the Company in connection with the Buy-In Transaction), were converted and restated into comparable awards under the Equity Compensation Plan based on the Company’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the Buy-In Transaction, into an award to acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Company common shares determined by multiplying the number of performance units subject to each award by the exchange ratio in the Buy-In Transaction (0.62), rounded down to the nearest whole share, and eliminating the performance factor which was based on the Partnership’s common units. 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. There was no acceleration of vesting and no monetary value received by our named executive officers in connection with the conversion.
Severance and Change in Control Benefits
The Executive Officer Change in Control Program (the “Change in Control Program”), in which each of our named executive officers is eligible to participate, provides for post-termination payments following a qualifying termination of employment in connection with a change in control event, or what is commonly referred to as a “double trigger” benefit. The vesting of certain of our long-term equity incentive compensation awards accelerates upon a change in control irrespective of whether the officer is terminated, and/or upon certain termination of employment events, such as death, disability or a termination by us without cause. 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 in our long-term equity incentive awards create important retention tools for us and are consistent with the 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.
On December 3, 2015, the Company amended the Change in Control Program to exclude the direct or indirect purchase of the Partnership or the General Partner by the Company or any of its affiliates from the definition of “change in control.” As a result, the consummation of the Buy-In Transaction in February 2016 did not constitute a change in control event for purposes of the Change in Control Program. The Buy-In Transaction also did not trigger the accelerated vesting of any of our outstanding long-term equity incentive compensation awards. See “- Components of Executive Compensation Program for Fiscal 2016-Long-Term Equity Incentive Awards” for a discussion of the impact of the Buy-In Transaction on performance unit awards previously granted under the Partnership’s Long-Term Incentive Plan.
Retirement, Health and Welfare, and Other Benefits
We offer eligible employees participation in a section 401(k) tax-qualified, defined contribution plan (the “401(k) Plan”) to enable employees to save for retirement through a tax-advantaged combination of employee and company contributions and to provide employees the opportunity to manage directly their retirement plan assets through a variety of investment options. Our employees, including our named executive officers, are eligible to participate in our 401(k) Plan and may elect to defer up to 30% of their eligible compensation on a pre-tax basis (or on a post-tax basis via a Roth contribution) and have it contributed to the 401(k) Plan, subject to certain limitations under the Internal Revenue Code of 1986, as amended (the “Code”). In addition, we make the following contributions to the 401(k) Plan for the benefit of our employees, including our named executive officers: (i) 3% of the employee’s eligible compensation, and (ii) an amount equal to the employee’s contributions to the 401(k) Plan up to 5% of the employee’s eligible compensation. In addition, we may also make discretionary contributions to the 401(k) Plan for the benefit of employees depending on our performance. Company contributions to the 401(k) Plan may be subject to certain limitations under the Code for certain employees. We do not maintain a defined benefit pension plan or a nonqualified deferred compensation plan for our named executive officers or other employees.
All full-time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, life insurance, dental coverage and disability insurance. It is the Compensation Committee’s policy not to pay for perquisites for any of our named executive officers, other than minimal parking subsidies.
Changes for 2017
In consultation with the Compensation Consultant, the Compensation Committee has reviewed our executive compensation program and has made certain changes for 2017, 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 and of our Chief Financial Officer was below the total direct compensation levels of similarly situated executives at peer companies, considering for example, the 2016 Peer Group pay programs adjusted for size using the regression analysis along with 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.
2017 Peer Group
In light of the Buy-In Transaction and significant 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, we made certain changes to the 2016 Peer Group used for compensation comparison purposes to create the 2017 Peer Group. A more traditional benchmark of Midstream Companies without regression was also considered, along with survey results and comparisons with individual companies and positions. We believe the 2017 Peer Group provides a more relevant and complete set of peers based on our corporate structure following the Buy-In Transaction and changes in the current circumstances of the included companies, including such companies’ organization, operations, market presence, business challenges and completed or announced corporate transactions.
Specifically, we removed the peer companies listed in the following table that were previously included in the 2016 Peer Group, many of which were subsidiary master limited partnerships that have, in some cases, been replaced with their public parent corporations as reflected in the second chart below.:
Midstream
E&P
Utilities
Access Midstream Partners, L.P.
Halcon Resources Corp.
Spectra Energy Corp
Enbridge Energy Partners, L.P.
Ultra Petroleum Corp.
Energy Transfer Partners, L.P.
MarkWest Energy Partners, L.P.
Plains All American Pipeline, L.P.
Regency Energy Partners, L.P.
In addition, we added the peer companies listed in the following table to the 2017 Peer Group:
Midstream
E&P
Utilities
Energy Transfer Equity, L.P.
Concho Resources, Inc.
Entergy Corporation
Holly Energy Partners, L.P.
Continental Resources, Inc.
Xcel Energy Inc.
Kinder Morgan, Inc.
Diamondback Energy, Inc.
Plains GP Holdings, L.P.
Energen Corp.
SemGroup Corporation
Parsley Energy, Inc.
Spectra Energy Corp.
Range Resources Corporation
Tallgrass Energy Partners, LP
RSP Permian, Inc.
WPX Energy, Inc.
As a result of the above changes, the 2017 Peer Group companies (for purposes of determining 2017 compensation levels) are:
•
Midstream Companies: Boardwalk Pipeline Partners, L.P., Buckeye Partners, L.P., Crestwood Equity Partners, L.P., DCP Midstream Partners, L.P., Enable Midstream Partners, L.P., L.P., Energy Transfer Equity, L.P., EnLink Midstream Partners, L.P., Enterprise Products Partners L.P., Genesis Energy, L.P., Holly Energy Partners, L.P., Kinder Morgan, Inc., Magellan Midstream Partners, L.P., NuStar Energy L.P., ONEOK, Inc., Plains GP Holdings, L.P., SemGroup Corporation, Spectra Energy Corp., Summit Midstream Partners, L.P., Tallgrass Energy Partners, L.P., and Williams Companies, Inc.
•
E&P peer companies: Apache Corporation, Cabot Oil & Gas Corporation, Cimarex Energy Company, Concho Resources, Inc., Continental Resources, Inc., Denbury Resources Inc., Devon Energy Corporation, Diamondback Energy, Inc., Energen Corp., EOG Resources, Inc., Murphy Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Parsley Energy, Inc., Pioneer Natural Resources Company, QEP Resources, Inc., Range Resources Corporation, RSP Permian, Inc., SM Energy Company, Southwestern Energy Company and WPX Energy, Inc.
•
Utility peer companies: AGL Resources, Inc., Ameren Corporation, Atmos Energy Corporation, CenterPoint Energy, Inc., Dominion Resources, Inc., DTE Energy Company, Enbridge Inc., Entergy Corporation, EQT Corporation, National Fuel Gas Company, NiSource Inc., Questar Corporation, Sempra Energy, TransCanada Corporation and Xcel Energy Inc.
Base Salary
The Compensation Committee has authorized, and executive management will implement, the following base salaries for our named executive officers effective March 1, 2017:
Effective March 1, 2017
Current Salary
Joe Bob Perkins
$750,000
$725,000
Michael A. Heim
600,000
600,000
Jeffrey J. McParland
500,000
500,000
Paul W. Chung
500,000
490,000
Matthew J. Meloy
475,000
460,000
The Compensation Committee authorized base salary increases for the named executive officers (other than Messrs. Heim and McParland), 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 in the case of Mr. Meloy, to reflect professional growth and the assumption of additional responsibilities. Although Mr. Perkins received quarterly grants of restricted stock in lieu of all of his 2016 base salary, for 2017 he will receive his base salary in cash.
Annual Incentive Bonus
In preparing our business plan for 2017, 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 2017 Annual Incentive Plan (the “2017 Bonus Plan”). The 2017 business priorities are the same eight business priorities as in effect for 2016, except that the priority related to executing on all business dimensions has been refined to include the 2017 business plan and public guidance.
The overall threshold, target and maximum funding percentages for the 2017 Bonus Plan remain the same as for the 2016 Bonus Plan. The target bonus percentages of the named executive officers (other than Mr. Heim) have been increased for 2017. The following table shows the target bonus percentages for our named executive officers effective March 1, 2017:
Effective March 1, 2017
Current Percentage
Joe Bob Perkins
190%
100%
Michael A. Heim
90%
90%
Jeffrey J. McParland
100%
90%
Paul W. Chung
100%
90%
Matthew J. Meloy
110%
90%
As with the 2016 Bonus Plan, funding of the bonus pool and the payment of individual bonuses to executive management, including our named executive officers, is subject to the sole discretion of the Compensation Committee.
Long-Term Equity Incentive Awards
The Compensation Committee also approved increases in the percentage of base salary used to determine the total dollar value of the annual long-term equity incentive awards granted to the named executive officers (other than Mr. Heim). The following table shows the new percentages approved for long-term incentive awards for our named executive officers effective for 2017:
2017 Percentage
Current Percentage
Joe Bob Perkins
400%
350%
Michael A. Heim
250%
250%
Jeffrey J. McParland
225%
200%
Paul W. Chung
225%
200%
Matthew J. Meloy
250%
190%
In addition, the Compensation Committee, in consultation with the Compensation Consultant, determined that it was appropriate to incorporate a long-term equity incentive award component for 2017 that included performance-based vesting conditions, similar to the equity-settled performance unit awards that were granted to the named executive officers under the Partnership’s Long-Term Incentive Plan prior to the Buy-In Transaction. As a result, for 2017, 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 2017, 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 20, 2017, our named executive officers were awarded equity-settled restricted stock units under the Stock Incentive Plan in the following amounts: (i) 25,742 restricted stock units to Mr. Perkins, (ii) 12,871 restricted stock units to Mr. Heim, (iii) 9,653 restricted stock units to Mr. McParland, (iv) 9,653 restricted stock units to Mr. Chung and (v) 10,190 restricted stock units to Mr. Meloy. 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 2017. On January 20, 2017, our named executive officers were awarded equity-settled performance share units under the Stock Incentive Plan in the following target amounts: (i) 25,742 performance share units to Mr. Perkins, (ii) 12,871 performance share units to Mr. Heim, (iii) 9,653 performance share units to Mr. McParland, (iv) 9,653 performance share units to Mr. Chung and (v) 10,190 performance share units to Mr. Meloy. 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 2017 performance share units, the LTIP Peer Group is composed of the Company and the following other companies:
Boardwalk Pipeline Partners L.P.
NuStar Energy, L.P.
Buckeye Partners, L.P.
ONEOK, Inc.
DCP Midstream Partners L.P.
Plains GP Holdings, L.P.
Enable Midstream Partners L.P.
Tallgrass Energy Partners, L.P.
EnLink Midstream Partners L.P.
Williams Companies, Inc.
Genesis Energy, L.P.
This peer group is a subset of the 2017 Midstream Peer Group which has been adjusted for size by the regression analysis, except that the LTIP Peer Group 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 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.
The overall performance period for the 2017 performance share units begins on January 1, 2017 and is designated to end on December 31, 2019, 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 three year relative TSR over the entirety of the 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 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 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 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 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 2019, he will become vested, as soon as practicable following December 31, 2019, in a number of performance share units equal to the target number awarded multiplied by the 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 2019, 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.
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.
Retention Awards
In support of the Company’s succession planning and management development goals, on January 20, 2017, the Compensation Committee also awarded special retention awards to certain executive officers. The special retention awards were granted in the form of restricted stock units that vest 30%, 30% and 40% on the fourth, fifth and sixth annual anniversaries, respectively, of the date of grant of the awards, subject to continued employment. Mr. Meloy is the only named executive officer who received a special retention award, and he received 50,000 restricted stock units.
Other Compensation Matters
Accounting Considerations. We account for the equity compensation expense for our employees, including our named executive officers, under the rules of Financial Accounting Standards Board (“FASB”), Accounting Standards Codification (“ASC”) Topic 718, which requires us to estimate and record an expense for each award of long-term equity incentive compensation over the vesting period of the award. Accounting rules also require us to record cash compensation as an expense at the time the obligation is accrued.
Clawback Policy. To date, we have not adopted a formal clawback policy to recoup incentive-based compensation upon the occurrence of a financial restatement, misconduct, or other specified events. However, 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, do 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.
Compensation Risk Assessment
The Compensation Committee reviews the relationship between our risk management policies and compensation policies and practices each year and, for 2016, 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 2016 with three-year vesting periods serves our executive compensation program’s goal of aligning the interests of executives and shareholders, thereby reducing the incentives to unnecessary risk-taking.
Compensation Committee Report
Messrs. Davis, Crisp and Evans are the current members of our Compensation Committee. Following the completion of the Buy-In Transaction, additional directors were elected to the Board and the membership of the Compensation Committee was changed to balance the workload of directors serving on this and other committees. As part of this change, effective March 1, 2016, Mr. Redd resigned as member and Chairman of the Compensation Committee and Ms. Fulton resigned as a member of the Compensation Committee. The Board of Directors appointed Mr. Davis as the Chairman of the Compensation Committee and Mr. Evans as a member of the Compensation Committee. In fulfilling its oversight responsibilities, the Compensation Committee, as currently composed, 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, 2016 and in our proxy statement. Based on these reviews and discussions, the Compensation Committee, as currently composed, 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, 2016 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 Compensation Committee
Waters S. Davis, IV, Chairman
Charles R. Crisp,
Committee Member
Robert B. Evans,
Committee Member
EXECUTIVE COMPENSATION
Summary Compensation Table for 2016
The following Summary Compensation Table sets forth the compensation of our named executive officers for 2016, 2015 and 2014. 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 (1)
Bonus (2)
Stock Awards ($) (3)
All Other Compensation (4)
Total
Joe Bob Perkins
Chief Executive Officer
$ -
$ 453,125
$ 3,534,138
$ 1,616
$ 3,988,879
697,500
-
2,066,608
22,720
2,786,828
554,167
1,120,000
1,552,665
21,931
3,248,763
Matthew J. Meloy
Executive Vice President and Chief Financial Officer
450,000
258,750
909,856
22,270
1,640,876
395,833
-
618,968
22,196
1,036,997
366,667
562,500
519,890
21,548
1,470,605
Michael A. Heim
Vice Chairman of the Board
600,000
337,500
1,552,084
22,784
2,512,368
589,167
-
1,221,592
22,628
1,833,387
526,667
963,000
1,112,536
21,874
2,624,077
Jeffrey J. McParland
President-Finance and Administration
500,000
281,250
1,127,299
22,520
1,931,069
495,000
-
814,407
22,448
1,331,855
463,333
846,000
738,476
21,745
2,069,554
Paul W. Chung
Executive Vice President, General Counsel and Secretary
490,000
275,625
1,104,764
22,494
1,892,883
485,000
-
798,112
22,422
1,305,534
(1)
The Compensation Committee approved quarterly grants of restricted stock to Mr. Perkins in lieu of all of his 2016 base salary. These restricted stock awards were granted on March 31, 2016, June 30, 2016, September 30, 2016 and December 20, 2016. Please see “Compensation Discussion and Analysis-Components of Executive Compensation Program for Fiscal 2016-Base Salary.” See also “-Grants of Plan-Based Awards for 2016.”
(2)
For 2016, amounts reported in the “Bonus” column represents the portion of the bonus awarded pursuant to our 2016 Bonus Plan that was paid to the named executive officers in cash. The Compensation Committee approved settlement of the 2016 bonuses in a combination of cash and restricted stock unit awards. Specifically, the Compensation Committee determined that 50% of each officer’s total bonus amount would be settled in the form of restricted stock unit awards, resulting in these officers receiving restricted stock unit awards corresponding to 62.5% of their respective target bonus amounts under the 2016 Bonus Plan. These restricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officers through that date. These awards will be granted on February 28, 2017, and will therefore be reported as compensation in the Summary Compensation Table for 2017 in accordance with SEC rules. Please see “Compensation Discussion and Analysis-Components of Executive Compensation Program for Fiscal 2016-Annual Incentive Bonus.” As discussed above, payments pursuant to our Bonus Plan are discretionary and not based on specific objective performance measures.
(3)
Amounts reported in the “Stock Awards” column represent the aggregate grant date fair value of restricted stock and restricted stock unit awards granted under our Stock Incentive Plan in 2016 (including restricted stock unit awards granted on February 29, 2016 in connection with awards earned under our 2015 Bonus Plan and restricted stock awards granted to Mr. Perkins in lieu of all of his 2016 base salary), computed in accordance with FASB ASC Topic 718. Assumptions used in the calculation of these amounts are included in Note 22 - Compensation Plans to our “Consolidated Financial Statements” in our Annual Report on Form 10-K for fiscal year 2016. Detailed information about the value attributable to specific awards is reported in the table under “-Grants of Plan-Based Awards for 2016” below. The grant date fair value of each restricted stock unit subject to the restricted stock unit awards granted on January 19, 2016, assuming vesting will occur, is $16.450. The grant date fair value of each restricted stock unit subject to the restricted stock unit awards granted on February 29, 2016, assuming vesting will occur, is $26.335. For 2015, the Compensation Committee provided that no bonuses would be paid to our named executive officers in cash under the 2015 Bonus Plan, and that these officers would instead receive restricted stock unit awards in an amount corresponding to 75% of their respective target bonus amounts under the 2015 Bonus Plan. These restricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officers through that date. Because these awards were granted on February 29, 2016, they are reported as compensation in the Summary Compensation Table for 2016 in accordance with SEC rules. The grant date fair value of the shares subject to the restricted stock awards granted to Mr. Perkins in lieu of his 2016 base salary is discussed below in footnote (2) to the Grants of Plan-Based Awards for 2016 table below.
(4)
For 2016, “All Other Compensation” includes (i) the aggregate value of all employer-provided contributions to our 401(k) plan and (ii) the dollar value of life insurance premiums paid by the Company with respect to life insurance for the benefit of each named executive officer.
Name
401(k) and Profit Sharing Plan
Dollar Value of Life Insurance Premiums
Total
Joe Bob Perkins (1)
$ -
$ 1,616
$1,616
Matthew J. Meloy
21,200
1,070
22,270
Michael A. Heim
21,200
1,584
22,784
Jeffrey J. McParland
21,200
1,320
22,520
Paul W. Chung
21,200
1,294
22,494
Name
401(k) and Profit Sharing Plan
Dollar Value of Life Insurance Premiums
Total
_________________
(1)
Because Mr. Perkins received restricted stock awards in lieu of his base salary he did not qualify for company contributions to the 401(k) plan.
Grants of Plan-Based Awards for 2016
The following table and the footnotes thereto provide information regarding grants of plan-based equity awards made to the named executive officers during 2016:
Name
Grant Date
Stock Awards: Number of Shares of Stock or Units (1)
Grant Date Fair Value of Equity Awards (2)
Mr. Perkins
01/19/16
102,484
$1,685,862
02/29/16
38,320
1,009,157
03/31/16
7,713
227,418
06/30/16
4,644
195,907
09/30/16
4,214
208,698
12/20/16
3,684
207,096
Mr. Meloy
01/19/16
35,299
580,669
02/29/16
12,500
329,188
Mr. Heim
01/19/16
60,582
996,574
02/29/16
21,094
555,510
Mr. McParland
01/19/16
40,388
664,383
02/29/16
17,578
462,917
Mr. Chung
01/19/16
39,580
651,091
02/29/16
17,227
453,673
(1)
The grants on January 19, 2016 are the annual long-term equity incentive awards for 2016 granted to our named executive officers in the form of restricted stock unit awards under our Stock Incentive Plan. The grants on February 29, 2016 are restricted stock unit awards granted in lieu of any cash payments under the 2015 Bonus Plan. The grants to Mr. Perkins on March 31, 2016, June 30, 2016, September 30, 2016 and December 20, 2016 are restricted stock awards granted in lieu of his cash salary during 2016.
(2)
The dollar amounts shown for the restricted stock unit awards granted on January 19, 2016 are determined by multiplying the shares reported in the table by $16.450, which is the grant date fair value of the awards computed in accordance with FASB ASC Topic 718. The dollar amounts shown for the restricted stock units granted on February 29, 2016 are determined by multiplying the shares reported in the table by $26.335, which is the grant date fair value of the awards computed in accordance with FASB ASC Topic 718. The dollar amounts shown for the restricted stock awards granted to Mr. Perkins on March 31, 2016, June 30, 2016, September 30, 2016 and December 20, 2016 are determined by multiplying the shares reported in the table by $29.485, $42.185, $49.525 and $56.215, respectively, which is the grant date fair value of the awards computed in accordance with FASB ASC Topic 718.
Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table
A discussion of 2016 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 2016 restricted stock unit awards under our Stock Incentive Plan and restricted stock awards to Mr. Perkins in lieu of his cash salary for 2016. Further discussion regarding restricted stock units granted in February 2016 in lieu of cash payments under our 2015 Bonus Plan are described in our proxy statement for our 2016 annual meeting of stockholders, filed with the Securities and Exchange Commission on March 25, 2016. In addition, a discussion of the conversion in 2016 of outstanding performance unit awards previously granted under the Partnership’s Long Term Incentive Plan into comparable awards under the Company’s Equity Compensation Plan is set forth in “Compensation Discussion and Analysis” under “Components of Executive Compensation Program for Fiscal 2016 -- Long-Term Equity Incentive Awards -- Conversion of Outstanding Partnership Equity Awards in the Buy-In Transaction.”
Outstanding Equity Awards at 2016 Fiscal Year-End
The following table and the footnotes related thereto provide information regarding equity-based awards outstanding as of December 31, 2016 for each of our named executive officers.
(1)
Represents the following shares of restricted stock and restricted stock units under our Stock Incentive Plan and restricted stock units under our Equity Compensation Plan (which were formerly outstanding performance unit awards previously granted under the Partnership’s Long Term Incentive Plan and converted into comparable awards related to Company common stock in connection with the Buy-In Transaction) held by our named executive officers:
January 14, 2014 Award (a)
January 14, 2014 Award (b)
January 15, 2015 Award (c)
January 21, 2015 Award (d)
January 19, 2016 Award (e)
February 29, 2016 Award (f)
In Lieu of Salary Awards (g)
Total
Joe Bob Perkins
4,823
15,176
9,912
19,944
102,484
38,320
20,255
210,914
Matthew J. Meloy
1,615
5,082
2,969
5,973
35,299
12,500
-
63,438
Michael A. Heim
3,456
10,874
5,859
11,789
60,582
21,094
-
113,654
Jeffrey J. McParland
2,294
7,218
3,906
7,860
40,388
17,578
-
79,244
Paul W. Chung
2,245
7,064
3,828
7,702
39,580
17,227
-
77,646
(a)
The restricted shares subject to the January 14, 2014 awards vested on January 14, 2017.
(b)
The Partnership performance units awarded January 14, 2014 were converted to Company restricted stock units at a ratio of 1 to 0.62 and 100% of the restricted stock units will vest on June 30, 2017.
(c)
The restricted stock units subject to the January 15, 2015 awards are subject to the following vesting schedule: 100% of the restricted stock units vest on June 30, 2018, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period.
(d)
The Partnership performance units awarded January 21, 2015 were converted to Company restricted stock units at a ratio of 1 to 0.62 and 100% of the restricted stock units vest on January 21, 2018, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period.
(e)
The restricted stock units subject to the January 19, 2016 awards are subject to the following vesting schedule: 100% of the restricted stock units vest on January 19, 2019, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period.
(f)
The restricted stock units awarded February 29, 2016 in settlement of awards under the 2015 Bonus Plan are subject to the following vesting schedule: 100% of the restricted stock units vest on February 28, 2019, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period.
(g)
The restricted stock awarded to Mr. Perkins in lieu of 2016 salary was awarded March 31, 2016 (7,713 shares), June 30, 2016 (4,644 shares), September 30, 2016 (4,214 shares) and December 20, 2016 (3,684 shares). 100% of each award will vest one year following the date of grant, contingent upon continuous employment.
The treatment of the outstanding restricted stock awards and restricted stock unit awards upon certain terminations of employment (including retirement) or the occurrence of a change in control is described below under “-Potential Payments Upon Termination or Change in Control.”
(2)
The dollar amounts shown are determined by multiplying the number of shares of restricted stock or the number of restricted stock units reported in the table by the closing price of a share of our common stock on December 30, 2016 ($56.07), which was the last trading day of fiscal 2016. The amounts do not include any related dividends accrued with respect to the awards.
Option Exercises and Stock Vested in 2016
The following table provides the amount realized during 2016 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 2016 year and, currently, there are no options outstanding under any of our plans.
(1)
Includes: (i) the following shares of restricted stock granted under our Stock Incentive Plan on January 15, 2013, which vested on January 15, 2016 for each Named Executive Officer respectively: (a) 5,035; (b) 1,866; (c) 4,399; (d) 3,390; and (e) 3,307; and (ii) the following restricted
stock units (former equity-settled performance unit awards under the Partnership’s Long-Term Incentive Plan that were converted into comparable awards related to Company common stock in connection with the Buy-In Transaction) originally granted on January 15, 2013 and August 12, 2013, which vested on June 30, 2016 for each Named Executive Officer respectively: (a) 18,620; (b) 16,269; (c) 12,537; (d) 6,903; and (e) 12,231.
(2)
Computed: (i) with respect to the restricted stock awards granted under our Stock Incentive Plan by multiplying the number of shares of stock vesting by the closing price of a share of common stock on the January 15, 2016 vesting date ($17.04) and does not include associated dividends accrued during the vesting period and (ii) with respect to the restricted stock units (former equity-settled performance unit awards) by multiplying the number of restricted stock units vesting by the closing price of a share of common stock on the June 30, 2016 vesting date ($42.14) and does not include associated distributions or dividends accrued during the vesting period.
Pension Benefits
Other than our 401(k) Plan, we do not have any plan that provides for payments or other benefits at, following, or in connection with, retirement.
Non-Qualified Deferred Compensation
We do not have any plan that provides for the deferral of compensation on a basis that is not tax qualified.
Potential Payments Upon Termination or Change in Control
Aggregate Payments
The table below reflects the aggregate amount of payments and benefits that we believe our named executive officers would have received under the Change in Control Program, Stock Incentive Plan and Equity Compensation Plan upon certain specified termination of employment and/or a change in control events, in each case, had such event occurred on December 31, 2016. 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 2016 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.”
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
$ 12,768,033
$ 17,158,985
$ 2,420,279
$ 12,904,551
Matthew J. Meloy
3,856,666
6,533,101
762,248
3,898,531
Michael A. Heim
6,934,017
10,408,452
1,563,468
7,018,179
Jeffrey J. McParland
4,826,572
7,731,006
1,040,102
4,882,622
Paul W. Chung
4,729,217
7,573,248
1,018,640
4,784,130
Executive Officer Change in Control Severance Program
We adopted the Change in Control Program on and effective as of January 12, 2012. Each of our named executive officers was an eligible participant in the Change in Control Program during the 2016 calendar year.
The Change in Control Program is administered by our 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 or 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.
On December 3, 2015, the Company amended the Change in Control Program to exclude the direct or indirect purchase of the Partnership or the General Partner by the Company or any of its affiliates from the definition of “Change in Control.” As a result, the consummation of the Buy-In Transaction did not constitute a Change in Control event for purposes of the Change in Control Program.
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, 2016.
Name
Qualifying Termination Following Change in Control (1)
Joe Bob Perkins
$ 4,390,952
Matthew J. Meloy
2,676,435
Michael A. Heim
3,474,435
Jeffrey J. McParland
2,904,435
Paul W. Chung
2,844,031
(1)
Includes 3 years’ worth of continued participation in our medical and dental plans, calculated based on the monthly employer-paid portion of the premiums for our medical and dental plans as of December 31, 2016 for each named executive officer and his eligible dependents in the following amounts: (a) Mr. Perkins - $40,952, (b) Mr. Meloy - $54,435, (c) Mr. Heim - $54,435, (d) Mr. McParland- $54,435, and (e) Mr. Chung-$51,031.
Stock Incentive Plan
Each of our named executive officers held outstanding restricted stock awards and restricted stock units under our forms of restricted stock agreement and restricted stock unit agreement, as applicable (the “Stock Agreements”), and the Stock Incentive Plan as of December 31, 2016. 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, the restricted
stock and restricted stock units granted to him under the Stock Agreements, and related dividends then credited to him, will fully vest on the date upon which such Change in Control occurs.
Restricted stock and restricted stock units granted to a named executive officer under the Stock Agreements, and related dividends then credited to him, will also fully vest if the named executive officer’s employment is terminated by reason of death or a “Disability.” If a named executive officer’s employment with us is terminated for any reason other than death or Disability, then his unvested restricted stock and restricted stock units are forfeited to us for no consideration, except that, if a named executive officer retires, his awards will continue to vest on the third anniversary of the date of grant if, from the date of his retirement through the third anniversary 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) the liquidation or dissolution of us or the approval by the limited partners of the Partnership of a plan of complete liquidation of the Partnership; (iii) 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 Warburg Pincus LLC or any other Affiliate; (iv) 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 Warburg Pincus LLC, the General Partner, or any other Affiliate; (v) a transaction resulting in a person other than Targa Resources GP LLC or an Affiliate being the General Partner of the Partnership; or (vi) 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 Buy-In Transaction did not trigger the accelerated vesting of any of our outstanding long-term equity incentive compensation awards under the Stock Incentive 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 in the event there was a Change in Control or their employment was terminated due to death or Disability, each as of December 31, 2016. The amounts reported below assume that the price per share of our common stock was $56.07, which was the closing price per share of our common stock on December 30, 2016 (the last trading day of fiscal 2016). No amounts are reported assuming retirement as of December 31, 2016, 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.
Name
Change in Control
Termination for Death or Disability
Joe Bob Perkins
$10,484,269
(1)
$10,484,269
(1)
Matthew J. Meloy
3,136,278
(2)
3,136,278
(2)
Michael A. Heim
5,454,708
(3)
5,454,708
(3)
Jeffrey J. McParland
3,842,516
(4)
3,842,516
(4)
Paul W. Chung
3,765,487
(5)
3,765,487
(5)
(1)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $270,426 and $46,819, respectively, relate to the restricted stock and related dividend rights granted on January 14, 2014, which vested on January 14, 2017; (b) $555,766 and $69,681, respectively, relate to the restricted stock units and related dividend rights granted on January 15, 2015, which are scheduled to vest January 15, 2018; (c) $5,746,278, and $373,042, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019; (d) $2,148,602 and $104,614, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, which are scheduled to vest February 28, 2019; and (e) $1,135,698 and $33,343, respectively, relate to the restricted stock and related dividend rights awarded in lieu of 2016 salary granted on March 31, 2016 (7,713 shares), June 30, 2016 (4,644 shares), September 30, 2016 (4,214 shares) and December 20, 2016 (3,684 shares).
(2)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $90,553 and $15,678, respectively, relate to the restricted stock and related dividend rights granted on January 14, 2014, which vested on January 14, 2017; (b) $166,472 and $20,872, respectively, relate to the restricted stock units and related dividend rights granted on January 15, 2015, which are scheduled to vest January 15, 2018; (c) $1,979,215 and $128,488, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019; and (d) $700,875 and $34,125, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, which are scheduled to vest February 28, 2019.
(3)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $193,778 and $33,549, respectively, relate to the restricted stock and related dividend rights granted on January 14, 2014, which vested on January 14, 2017; (b) $328,514 and $41,189, respectively, relate to the restricted stock units and related dividend rights granted on January 15, 2015, which are scheduled to vest January 15, 2018; (c) $3,396,833 and $220,518, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019; and (d) $1,182,741 and $57,587, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, which are scheduled to vest February 28, 2019.
(4)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $128,625 and $22,269, respectively, relate to the restricted stock and related dividend rights granted on January 14, 2014, which vested on January 14, 2017; (b) $219,009 and $27,459, respectively, relate to the restricted stock units and related dividend rights granted on January 15, 2015, which are scheduled to vest January 15, 2018; (c) $2,264,555 and $147,012, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019; and (d) $985,598 and $47,988, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, which are scheduled to vest February 28, 2019.
(5)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $125,877 and $21,793, respectively, relate to the restricted stock and related dividend rights granted on January 14, 2014, which vested on January 14, 2017; (b) $214,636 and $26,911, respectively, relate to the restricted stock units and related dividend rights granted on January 15, 2015, which are scheduled to vest January 15, 2018; (c) $2,219,251 and $144,071, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19, 2019; and (d) $965,918 and $47,030, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, which are scheduled to vest February 28, 2019.
Equity Compensation Plan
The Buy-In Transaction did not trigger the accelerated vesting of any outstanding long-term equity incentive compensation awards under the Equity Compensation Plan (formerly, the Partnership’s Long-Term Incentive Plan). Upon completion of the Buy-In Transaction, all outstanding performance unit awards previously granted under the Partnership’s Long-Term Incentive Plan (which was assumed by the Company in connection with the Buy-In Transaction and renamed the Equity Compensation Plan), were converted and restated into comparable awards based on the Company’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the Buy-In Transaction, into an award to acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Company common shares determined by multiplying the number of performance units subject to each award by the exchange ratio in the Buy-In Transaction (0.62), rounded down to the nearest whole share, and eliminating the performance factor that was based on the Partnership’s common units. 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.
As a result, each of our named executive officers held outstanding restricted stock units under our Equity Compensation Plan (which were formerly outstanding performance unit awards previously granted under the Partnership’s Long Term Incentive Plan and converted into comparable awards related to Company stock in connection with the Buy-In Transaction) under the Company’s form of agreement (the “Share Grant Agreement”) and the Equity Compensation Plan as of December 31, 2016.
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, the restricted stock units subject to the Share Grant Agreements, and related dividends or distributions then credited to him, will fully vest on the date upon which such Change in Control occurs.
Generally, restricted stock units and the related dividend or distribution equivalent rights subject to a Share Grant Agreement would be automatically forfeited without payment upon the termination of the named executive officer’s employment with us and our affiliates. However, if a named executive officer’s employment was terminated by reason of his death or “Disability” or was terminated by us other than for “Cause,” or if the executive retired and he 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 end of the vesting period, he would become vested in the restricted stock units that he is otherwise qualified to receive as if the named executive officer had remained continuously employed through the end of the performance period. The named executive officer will also receive a cash payment in the amount of the dividend or distribution equivalent rights that would have accrued through the end of the vesting period.
The following terms generally have the meanings specified below for purposes of the Equity Compensation Plan:
•
Change in Control means (i) any person or group, other than an affiliate, becomes the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Company, (ii) the stockholders of the Company approve a plan of complete liquidation of the Company or
(iii) the sale or other disposition by the Company of all or substantially all of its assets in one or more transactions to any person other than one of the Company’s affiliates.
•
Cause means (i) failure to perform assigned duties and responsibilities, (ii) engaging in conduct which is injurious (monetarily or otherwise) to us or our affiliates, (iii) breach of any corporate policy or code of conduct established by us or our affiliates, or breach of any agreement between the named executive officer and us or our affiliates, or (iv) conviction of a misdemeanor involving moral turpitude or a felony. If the named executive officer is a party to an agreement with us or our affiliates in which this term is defined, then that definition will apply for purposes of the Equity Compensation Plan and the Share Grant Agreement.
•
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 Equity Compensation Plan and related Share Grant Agreements in the event there was a Change in Control or their employment was terminated due to death or Disability or by us without Cause, each as of December 31, 2016. No amounts are reported assuming retirement as of December 31, 2016, since additional conditions must be met following a named executive officer’s retirement in order for any performance share awards to become vested. The amounts reported below assume that the price per the Company’s share of stock was $56.07, which was the closing price per share of stock on December 30, 2016 (the last trading day of fiscal 2016).
Name
Change in Control
Termination for Death or Disability or Without Cause
Joe Bob Perkins.............................................................................................................
$ 2,283,764
(1)
$ 2,420,282
(1)
Matthew J. Meloy..........................................................................................................
720,388
(2)
762,253
(2)
Michael A. Heim...........................................................................................................
1,479,309
(3)
1,563,470
(3)
Jeffrey J. McParland......................................................................................................
984,056
(4)
1,040,106
(4)
Paul W. Chung..............................................................................................................
963,731
(5)
1,018,644
(5)
________________
(1) Of the amount reported under the “Change in Control” column: (a) $850,918 and $180,523, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $1,118,260 and $134,062, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $850,918 and $208,144, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $1,118,260 and $242,957, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015.
(2) Of the amount reported under the “Change in Control” column: (a) $284,948 and $60,440, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $334,906 and $40,150, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $284,948 and $69,688, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $334,906 and $72,763, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015.
(3) Of the amount reported under the “Change in Control” column: (a) $609,705 and $129,350, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $661,009 and $79,245, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $609,705 and $149,140, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $661,009 and $143,613, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015.
(4) Of the amount reported under the “Change in Control” column: (a) $404,713 and $85,860, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $440,710 and $52,828, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $404,713 and $98,997, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $440,710 and $95,738, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015.
(5) Of the amount reported under the “Change in Control” column: (a) $396,078 and $84,029, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $431,851 and $51,772, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $396,078 and $96,885, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 14, 2014; and (b) $431,851 and $93,825, respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015.
Director Compensation
The following table sets forth the compensation earned by the general partner’s non-employee directors for 2016:
Name
Fees Earned or Paid in Cash
Stock Awards (1)
Total Compensation
Charles R. Crisp (2)
$ -
$ -
-
Ershel C. Redd Jr. (2)
-
-
-
Chris Tong (2)
-
-
-
Laura C. Fulton (2)
-
-
-
Waters S. Davis, IV (2)
-
-
-
Rene R. Joyce
15,667
67,650
83,317
Robert B. Evans
30,564
67,650
98,214
Barry R. Pearl (3)
29,931
67,650
97,581
Ruth I. Dreessen (3)
26,598
67,650
94,248
(1)
Amounts represent the aggregate grant date fair value of fully vested Partnership common units awarded to the non-employee directors in 2016, computed in accordance with FASB ASC Topic 718. For a discussion of the assumptions and methodologies used to value the awards reported in this column, see the discussion of common unit awards contained in the Notes to Consolidated Financial Statements at Note 22 included in our Annual Report on Form 10-K for the year ended December 31, 2016. On January 19, 2016, each non-employee director who was serving on the Board of Directors of the general partner on such date received 6,698 fully vested Partnership common units in connection with their 2016 service on the Board of Directors of the general partner. The grant date fair value of each common unit computed in accordance with FASB ASC Topic 718 was $16.450, based on the average of the high and low price of the common units on the date of grant.
(1)
Appointed effective March 1, 2016 in connection with the closing of the Buy-In Transaction. Non-employee directors appointed following the closing of the Buy-In Transaction did not receive any fees for 2016 service.
(1)
Resigned effective March 1, 2016 in connection with the closing of the Buy-In Transaction.
Narrative to Director Compensation Table
The Board of Directors of the general partner did not make any changes to the compensation program for its non-employee directors for 2016. However, as a result of the closing of the Buy-In Transaction in February 2016, for 2016, each of the general partner’s non-employee directors who was serving on the Board on January 19, 2016 received a pro-rated annual cash retainer of $12,667. Similarly, the Chairman of the general partner’s Audit Committee received an additional pro-rated annual retainer of $3,333. Further, until March 1, 2016, all of the general partner’s non-employee directors received $1,500 for each Board and Audit Committee meeting attended. All non-employee directors are reimbursed for out-of-pocket expenses incurred in attending general partner’s Board 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 Messrs. Perkins and Heim are named executive officers for 2016, the Summary Compensation Table reflects the total compensation they received for services performed for the general partner and its affiliates for 2016. Other than as described above in the preceding paragraph, we did not pay any cash fees to any non-employee directors for 2016.
Director Long-term Equity Incentives. The general partner granted equity-based awards in January 2016 to each of the general partner’s non-employee directors who was serving on the Board on January 19, 2016 under the Partnership’s Long-Term Incentive Plan. Each of these directors received an award of 6,698 Partnership common units, which reflected the general partner’s intent to provide them with a target value of approximately $100,000 in annual long-term incentive awards, which maintained the same target value as 2015. The awards are intended to align the long-term interests of the general partner’s directors with those of our unitholders. We did not grant any other equity-based awards to non-employee directors in 2016.
Item 12.
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 Targa common stock as of February 10, 2017 (unless otherwise indicated) held by:
•
each person who beneficially owns 5% or more of the then outstanding shares of common stock;
•
all of the directors of our general partner;
•
each named executive officer of our general partner; and
•
all directors and executive officers of our general partner as a group.
On February 17, 2016, TRC completed the TRC/TRP Merger, pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. As a result of the TRC/TRP Merger, TRC owns all of our
outstanding common units. As of February 10, 2017, none of the directors or executive officers of our general partner owned any Preferred Units or any shares of Series A Preferred Stock of TRC.
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 193,949,450 shares of Targa’s common stock outstanding on February 10, 2017.
_________
* Less than 1%.
(1)
Unless otherwise indicated, the address for all beneficial owners in this table is 1000 Louisiana, Suite 4300, Houston, Texas 77002.
(2) As reported on Schedule 13G/A as of December 31, 2016 and filed with the SEC on February 10, 2017, the business address for The Vanguard Group is 100 Vanguard Blvd., Malvern, PA 19355.
(3)
Shares of common stock beneficially owned by Mr. Joyce include: (i) 223,759 shares issued to The Rene Joyce 2010 Grantor Retained Annuity Trust, of which Mr. Joyce and his wife are co-trustees and have shared voting and investment power; and (ii) 561,292 shares issued to The Kay Joyce 2010 Family Trust, of which Mr. Joyce’s wife is trustee and has sole voting and investment power.
(4)
Shares of common stock beneficially owned by Mr. Perkins include: (i) 207,370 shares issued to the Perkins Blue House Investments Limited Partnership (“PBHILP”) and (ii) 93 shares held by Mr. Perkins’ wife. Mr. Perkins is the sole member of JBP GP, L.L.C., one of the general partners of the PBHILP.
(5)
Shares of common stock beneficially owned by Mr. Heim include: (i) 124,878 shares issued to The Michael Heim 2009 Family Trust, of which Mr. Heim and his son are co-trustees and have shared voting and investment power; (ii) 81,672 shares issued to The Patricia Heim 2009 Grantor Retained Annuity Trust, of which Mr. Heim and his wife are co-trustees and have shared voting and investment power; (iii) 57,973 shares issued to the Pat Heim 2012 Family Trust, of which Mr. Heim’s wife and son serve as co-trustees and have shared voting and investment power; (iv) 38,400 shares issued to the Heim 2012 Children’s Trust, of which Mr. Heim serves as trustee; and (v) 19,472 shares held by Mr. Heim’s wife.
(6)
Shares of common stock beneficially owned by Mr. McParland include 215,848 shares issued to the Sarah McParland Family Trust, of which Mr. McParland's spouse serves as trustee.
(7)
Shares of common stock beneficially owned by Mr. Whalen include (i) 345,999 shares issued to the Whalen Family Investments Limited Partnership and (ii) 98,000 issued to the Whalen Family Investments Limited Partnership 2.
(8)
Shares of common stock beneficially owned by Mr. Chung include (i) 189,904 shares issued to the Paul Chung 2008 Family Trust, of which Mr. Chung serves as trustee, (ii) 189,904 shares issued to the Helen Chung 2007 Family Trust, of which Mr. Chung's spouse and Mr. Chung's sister-in-law serve as co-trustees.
(9)
Shares of common stock beneficially owned by Mr. Tong include 1,310 shares held by Mr. Tong’s wife.
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth certain information as of December 31, 2016 regarding Targa’s long-term incentive plans, under which Targa’s common stock is authorized for issuance to employees, consultants and directors of TRC, our general partner and their affiliates. Targa’s sole equity compensation plan, under which it will make equity grants in the future, is Targa’s long-term incentive plan, which was approved by its stockholders prior to Targa’s initial public offering.
Plan category
Number of securities to be issued upon exercise of outstanding options, warrants and rights
Weighted average exercise price of outstanding options, warrants and rights
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(a)
(b)
(c)
Equity compensation plans approved by security holders (1)
-
-
1,825,639
Equity compensation plans not approved by security holders(2)
-
-
32,960
Total
-
-
1,858,599
____________
(1)
Generally, awards of restricted stock and restricted stock units to our officers and employees under the Stock Incentive Plan are subject to vesting over time as determined by the Compensation Committee of Targa and, prior to vesting, are subject to forfeiture. Stock incentive plan awards may vest in other circumstances, as approved by the Compensation Committee of Targa and reflected in an award agreement. Restricted stock and restricted stock units are issued, subject to vesting, on the date of grant. The Compensation Committee of Targa may provide that dividends on restricted stock or restricted stick units are subject to vesting and forfeiture provisions, in which cash such dividends would be held, without interest, until they vest or are forfeited.
(2)
These represent awards available for issuance under Targa Resources Corp. Equity Compensation Plan, which was assumed by Targa as part (2) of the TRC/TRP Merger. The termination date for this plan was February 7, 2017.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
As a result of the TRC/TRP Merger, which was completed on February 17, 2016, Targa owns all of our outstanding common units. In addition, Targa owns a 2% general partner interest in us. Our total outstanding common units as of February 10, 2017 totaled 275,168,410. In addition, Targa owns a 2% general partner interest in us, which is held through a 100% ownership interest in our general partner.
Distributions and Payments to Targa and its Affiliates
The following table summarizes the distributions and payments made and to be made by us to Targa and its affiliates in connection with our ongoing operation and any liquidation of us. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Partnership Agreement
Our Partnership Agreement with Targa governs the reimbursement of Targa and its affiliates for costs incurred on our behalf,
competition and indemnification matters. The Partnership Agreement provides that Targa and its affiliates are reimbursed for all direct and indirect expenses, as well as expenses otherwise allocable to us in connection with the operation of our business, incurred on our behalf.
Reimbursement of Operating and General and Administrative Expense
Under the terms of our Partnership Agreement, we reimburse Targa for all direct and indirect expenses, as well as expenses otherwise allocable to us in connection with the operation of our business, incurred on our behalf, which includes certain operating and direct expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for our benefit. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. We reimburse Targa for the direct expenses to provide these services as well as other direct expenses it incurs on our behalf, such as compensation of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits. Other than Targa’s direct costs of being a public reporting company, substantially all of Targa’s general and administrative costs have been and will continue to be allocated to us, so long as Targa’s only cash-generating assets consist of its interest in us.
Competition
Targa is not restricted under our Partnership Agreement from competing with us. Targa may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
Indemnification Agreements
Indemnification Agreements with Directors and Officers
We and our general partner have entered into Indemnification Agreements (each, an “Indemnification Agreement”) with individual who was an independent director of Targa Resources GP LLC (each, an “Indemnitee”) prior to the TRC/TRP Merger. Each Indemnification Agreement provides that each of us and Targa Resources GP LLC will indemnify and hold harmless each Indemnitee against Expenses (as defined in the Indemnification Agreement) to the fullest extent permitted or authorized by law, including the Delaware Revised Uniform Limited Partnership Act and the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee. If such indemnification is unavailable as a result of a court decision and if we or Targa Resources GP LLC are jointly liable in the proceeding with the Indemnitee, we and Targa Resources GP LLC will contribute funds to the Indemnitee for his Expenses (as defined in the Indemnification Agreement) in proportion to relative benefit and fault of us or Targa Resources GP LLC on the one hand and Indemnitee on the other in the transaction giving rise to the proceeding.
Each Indemnification Agreement also provides that we and Targa Resources GP LLC will indemnify and hold harmless the Indemnitee against Expenses incurred for actions taken as a director or officer of us or Targa Resources GP LLC or for serving at the request of us or Targa Resources GP LLC as a director or officer or another position at another corporation or enterprise, as the case may be, but only if no final and non-appealable judgment has been entered by a court determining that, in respect of the matter for which the Indemnitee is seeking indemnification, the Indemnitee acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal proceeding, the Indemnitee acted with knowledge that the Indemnitee’s conduct was unlawful. Each Indemnification Agreement also provides that we and Targa Resources GP LLC must advance payment of certain Expenses to the Indemnitee, including fees of counsel, subject to receipt of an undertaking from the Indemnitee to return such advance if it is ultimately determined that the Indemnitee is not entitled to indemnification.
Targa Resources Corp., the holder of all of our common units, has entered into Indemnification Agreements (each, a “Parent Indemnification Agreement”) with each director and officer of Targa (each, a “Parent Indemnitee”). Each Parent Indemnification Agreement provides that Targa Resources Corp. will indemnify and hold harmless each Parent Indemnitee for Expenses (as defined in the Parent Indemnification Agreements) to the fullest extent permitted or authorized by law, including the Delaware General Corporation Law, in effect on the date of the agreement or as it may be amended to provide more advantageous rights to the Parent Indemnitee. If such indemnification is unavailable as a result of a court decision and if Targa Resources Corp. and the Indemnitee are jointly liable in the proceeding, Targa Resources Corp. will contribute funds to the Parent Indemnitee for his expenses in proportion to relative benefit and fault of Targa Resources Corp. and Parent Indemnitee in the transaction giving rise to the proceeding.
Each Indemnification Agreement also provides that Targa Resources Corp. will indemnify the Parent Indemnitee for monetary damages for actions taken as a director or officer of Targa Resources Corp. or for serving at Targa’s request as a director or officer or
another position at another corporation or enterprise, as the case may be but only if (i) the Parent Indemnitee acted in good faith and, in the case of conduct in his official capacity, in a manner he reasonably believed to be in the best interests of Targa Resources Corp. and, in all other cases, not opposed to the best interests of Targa Resources Corp. and (ii) in the case of a criminal proceeding, the Parent Indemnitee must have had no reasonable cause to believe that his conduct was unlawful. Each Parent Indemnification Agreement also provides that Targa Resources Corp. must advance payment of certain Expenses to the Parent Indemnitee, including fees of counsel, subject to receipt of an undertaking from the Parent Indemnitee to return such advance if it is it is ultimately determined that the Parent Indemnitee is not entitled to indemnification.
Transactions with Related Persons
Relationship with Sajet Resources LLC
In December 2010 prior to our IPO, Sajet Resources LLC (“Sajet”), was spun-off from Targa. Rene Joyce and James Whalen, 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. Sajet owns certain technology rights, real property and ownership interests in Allied CNG Ventures LLC. We provide general and administrative services to Sajet and are reimbursed for these amounts at our actual cost. Services provided to Sajet totaled $0.5 million in 2016.
Relationship with Tesla Resources LLC
In September 2012, Tesla Resources LLC (“Tesla”) was spun-off from Sajet. Tesla has ownership interests in Floridian Natural Gas Storage Company LLC (“Floridian”). Rene Joyce and James Whalen, directors of Targa, are also directors of Tesla and managers of Floridian. Joe Bob Perkins, James Whalen, Michael Heim, Jeffrey McParland, Paul Chung and Matthew Meloy, executive officers of Targa, are also executive officers of Tesla. We provide general and administrative services to Tesla and Floridian and are reimbursed for these amounts at our actual cost. Services provided to Tesla and Floridian totaled $0.1 million in 2016.
Relationship with Total Safety US Inc.
Joe Bob Perkins, Chief Executive Officer and a director of Targa and of our general partner, is also a member of the Board of Managers of W3 Holdings, LLC, parent company of Total Safety US Inc. (“Total Safety”) which provides us safety services and equipment, including detection and monitoring systems. During 2016, we made payments of $0.1 million to Total Safety.
Relationship with Magellan Asset Services LP
Barry Pearl, one of our former directors of our general partner, is also a director of Magellan Midstream Partners, L.P., parent company of Magellan Asset Services LP (“Magellan”). During 2016, we transacted sales of $29.1 million with Magellan.
Relationship with Kansas Gas Service
Robert Evans, a director of Targa and our general partner, is also a director of ONE Gas, Inc. (“ONE”). We have commercial arrangements with Kansas Gas Service (“Kansas Gas”), a division of ONE. During 2016, we transacted sales of $18.0 million with Kansas Gas.
Relationship with Newark E&P Operating, LLC
Waters Davis IV, one of the directors of Targa and of our general partner, was a director of Newark E&P Operating, LLC (“Newark E&P”) until October 1, 2016. During 2016, Targa purchased $8.6 million of natural gas from Newark E&P.
Relationships with Sequent Energy Management, LP, EOG Resources Inc., NICOR Energy and IntercontinentalExchange, Inc.
Charles R. Crisp, a director of Targa and of our general partner, is also a director of Southern Company Gas, a subsidiary of The Southern Company, parent company of Sequent Energy Management, LP (“Sequent”) and Northern Illinois Gas Company d/b/a NICOR Energy (“NICOR”). The Partnership purchases and sells natural gas and NGL products from and to Sequent and sells natural gas products to NICOR. Mr. Crisp also serves as a director of EOG Resources Inc. (“EOG”) from whom the Partnership purchases natural gas and NGL products. The Partnership billed EOG Resources Marketing Inc. (“EOG Marketing”), a subsidiary of EOG, for certain well connections to our gathering systems and associated equipment. Mr. Crisp is also a director of IntercontinentalExchange Group Inc., parent company of ICE US OTC Commodity Markets LLC (“ICE”) from whom the Partnership purchases brokerage services. The following table shows the Partnership’s transactions with each of these entities during 2016.
These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
Relationships with Martin Gas Sales and Southwest Energy LP
Ershel C. Redd, a director of Targa and of our general partner, has an immediate family member who is an officer of Martin Gas Sales, which is a subsidiary of Martin Midstream Partners LP (“Martin”) and an immediate family member who is an officer and part owner of Southwest Energy LP (“Southwest Energy”), from and to whom the Partnership purchases and sells natural gas and NGL products. The following table shows the Partnership’s transactions with each of these entities during 2016.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Targa) on the one hand and our partnership and our limited partners, on the other hand. The directors and officers of Targa Resources GP LLC have fiduciary duties to manage Targa and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.
Whenever a conflict arises between our general partner and its affiliates on the one hand and us or any other partner on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:
•
approved by the conflicts committee, although our general partner is not obligated to seek such approval;
•
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determine in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership.
Review, Approval or Ratification of Transactions with Related Persons
If a conflict or potential conflict of interest arises between our general partner and its affiliates (including Targa) on the one hand and our partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as
described under “−Conflicts of Interest.”
Pursuant to Targa’s Code of Conduct, our officers and directors are required to abandon or forfeit any activity or interest that creates a conflict of interest between them and Targa or any of its subsidiaries, unless the conflict is pre-approved by the Board of Directors.
Director Independence
The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee. Our general partner has a standing Audit Committee that consists of three directors: Messrs. Tong and Redd and Ms. Fulton. The board of directors of our general partner has affirmatively determined that Messrs. Tong and Redd and Ms. Fulton are independent as described in the rules of the NYSE and the Exchange Act for purposes of serving on the board of directors and the Audit Committee.
To be independent under the NYSE rules, a company’s board of directors must affirmatively determine that the director has no material relationship with the company (directly as a partner, stockholder or officer of an organization that has a relationship with the company). The board of directors of our general partner has made no such determination with respect to Messrs. Joyce, Perkins, Whalen and Heim because the NYSE rules do not require us to have a majority of independent directors. As such, Messrs. Joyce, Perkins, Whalen and Heim are not independent under NYSE rules applicable to service on compensation and nominating/governance committees.
Item 14.
Item 14. Principal Accounting Fees and Services.
We have engaged PricewaterhouseCoopers LLP as our principal accountant. The following table summarizes fees we were billed by PricewaterhouseCoopers LLP (or included in Targa’s general and administrative expense allocation to us) for independent auditing, tax and related services for each of the last two fiscal years:
_______________
(1)
Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the integrated audit of our annual financial statements and internal control over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this Annual Report.
(2)
Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews of our financial statements and are not reported under audit fees.
(3)
Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance.
(4)
All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above.
All services provided by our independent principal accountant are subject to pre-approval by the audit committee of our general partner. The audit committee of our general partner is informed of each engagement of the independent principal accountant to provide services under the policy. The audit committee of our general partner has approved the use of PricewaterhouseCoopers LLP as our independent principal accountant.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a)(1) Financial Statements
Our Consolidated Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Consolidated Financial Statements” on Page in this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
Number
Description
2.1***
Purchase and Sale Agreement, dated September 18, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 21, 2007 (File No. 001-33303)).
2.2
Amendment to Purchase and Sale Agreement, dated October 1, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)).
2.3
Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (File No. 001-33303)).
2.4
Purchase and Sale Agreement, dated March 31, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC and Targa Midstream Holdings LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 1, 2010 (File No. 001-33303)).
2.5
Purchase and Sale Agreement, dated August 6, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 9, 2010 (File No. 001-33303)).
2.6
Purchase and Sale Agreement, dated September 13, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 17, 2010 (File No. 001-33303)).
2.7***
Membership Interest Purchase and Sale Agreement, dated November 14, 2012, by and among Targa Resources Partners LP, Saddle Butte Pipeline LLC, Saddle Butte Fort Berthold Gathering, LLC and Saddle Butte Assets, LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 15, 2012 (File No. 001-33303)).
2.8***
Agreement and Plan of Merger, by and among Targa Resources Corp., Trident GP Merger Sub LLC, Atlas Energy, L.P. and Atlas Energy GP, LLC, dated October 13, 2014 (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 17, 2014 (File No. 001-33303)).
2.9***
Agreement and Plan of Merger, by and among Targa Resources Corp., Targa Resources Partners LP, Targa Resources GP LLC, Trident MLP Merger Sub LLC, Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Atlas Pipeline Partners GP, LLC, dated October 13, 2014 (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 17, 2014 (File No. 001-33303)).
2.10***
Agreement and Plan of Merger, dated as of November 2, 2015, by and among Targa Resources Corp., Spartan Merger Sub LLC, Targa Resources Partners LP and Targa Resources GP LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 6, 2015 (File No. 001-33303)).
2.11***
Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Delaware Midstream, LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).
2.12***
Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Energy, LLC (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).
2.13***
Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and Outrigger Midland Midstream, LLC (incorporated by reference to Exhibit 2.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 23, 2017 (File No. 001-33303)).
3.1
Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
3.2
Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
Number
Description
3.3
Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP, effective December 1, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 21, 2016 (File No. 001-33303)).
3.4
Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
4.1
Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
4.2
Indenture dated February 2, 2011 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).
4.3
Registration Rights Agreement dated February 2, 2011 among the Issuers, the Guarantors, Deutsche Bank Securities Inc., as representative of the several initial purchasers, and the Dealer Managers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 3, 2011 (File No. 001-33303)).
4.4
Supplemental Indenture dated April 8, 2011 to Indenture dated February 2, 2011, among Targa Terminals LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2011 (File No. 001-33303)).
4.5
Supplemental Indenture dated October 28, 2011 to Indenture dated February 2, 2011, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 7, 2011 (File No. 001-33303)).
4.6
Supplemental Indenture dated April 20, 2012 to Indenture dated February 2, 2011, among Targa Cogen LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 6, 2012 (File No. 001-33303)).
4.7
Supplemental Indenture dated February 14, 2013 to Indenture dated February 2, 2011, among Targa Badlands LLC, Targa Assets LLC and Targa Fort Berthold Gathering LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.66 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 19, 2013 (File No. 001-33303)).
4.8
Supplemental Indenture dated October 11, 2016 to Indenture dated February 2, 2011, among the Guaranteeing Subsidiaries, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33303)).
4.9
Indenture dated as of January 31, 2012 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 31, 2012 (File No. 001-33303)).
4.10
Registration Rights Agreement dated as of January 31, 2012 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 31, 2012 (File No. 001-33303)).
4.11
Supplemental Indenture dated April 20, 2012 to Indenture dated January 31, 2012, among Targa Cogen LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 6, 2012 (File No. 001-33303)).
Number
Description
4.12
Supplemental Indenture dated February 14, 2013 to Indenture dated January 31, 2012, among Targa Badlands LLC, Targa Assets LLC and Targa Fort Berthold Gathering LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.70 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 19, 2013 (File No. 001-33303)).
4.13
Supplemental Indenture dated October 11, 2016 to Indenture dated January 31, 2012, among the Guaranteeing Subsidiaries, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33303)).
4.14
Indenture dated as of October 25, 2012 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation and the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 26, 2012 (File No. 001-33303)).
4.15
Registration Rights Agreement dated as of October 25, 2012 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC, Barclays Capital Inc. and RBS Securities Inc., as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 26, 2012 (File No. 001-33303)).
4.16
Supplemental Indenture dated February 14, 2013 to Indenture dated October 25, 2012, among Targa Badlands LLC, Targa Assets LLC and Targa Fort Berthold Gathering LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.73 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 19, 2013 (File No. 001-33303)).
4.17
Supplemental Indenture dated October 11, 2016 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiaries, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33303)).
4.18
Registration Rights Agreement dated as of December 10, 2012 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC, Barclays Capital Inc. and RBS Securities Inc., as representatives of the several initial purchasers. (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 10, 2012 (File No. 001-33303)).
4.19
Indenture dated as of May 14, 2013 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 14, 2013 (File No. 001-33303)).
4.20
Registration Rights Agreement dated as of May 14, 2013 among the Issuers, the Guarantors and Wells Fargo Securities, LLC, Barclays Capital Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC, as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 14, 2012 (File No. 001-33303)).
4.21
Supplemental Indenture dated October 11, 2016 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiaries, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33303)).
4.22
Indenture dated as of October 28, 2014 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 29, 2014 (File No. 001-33303)).
4.23
Registration Rights Agreement dated as of October 28, 2014 by and among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBS Securities Inc., Wells Fargo Securities, LLC, Goldman, Sachs & Co. and UBS Securities LLC, as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 29, 2014 (File No. 001-33303)).
Number
Description
4.24
Supplemental Indenture dated October 11, 2016 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiaries, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33303)).
4.25
Indenture dated as of January 30, 2015 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on 8-K filed January 30, 2014 (File No. 001-33303)).
4.26
Registration Rights Agreement dated as of January 30, 2015 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and RBS Securities Inc., as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on 8-K filed January 30, 2014 (File No. 001-33303)).
4.27
Supplemental Indenture dated October 11, 2016 to Indenture dated January 30, 2015, among the Guaranteeing Subsidiaries, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33303)).
4.28
Third Supplemental Indenture, dated as of April 24, 2015, by and among Targa Pipeline Partners LP, Targa Pipeline Finance Corporation, the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 12, 2015 (File No. 001-33303)).
4.29
Indenture, dated as of May 11, 2015, among Targa Resources Partners LP, Targa Resources Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 12, 2015 (File No. 001-33303)).
4.30
Registration Rights Agreement, dated as of May 11, 2015, among Targa Resources Partners LP, Targa Resources Finance Corporation, the Guarantors named therein and Barclays Capital Inc., as dealer manager (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 12, 2015 (File No. 001-33303)).
4.31
Supplemental Indenture dated October 11, 2016 to Indenture dated May 11, 2015, among the Guaranteeing Subsidiaries, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33303)).
4.32
Indenture, dated as of September 14, 2015, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 15, 2015 (File No. 001-33303)).
4.33
Registration Rights Agreement, dated as of September 14, 2015, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and Merrill Lynch,Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 15, 2015 (File No. 001-33303)).
4.34
Supplemental Indenture dated October 11, 2016 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiaries, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33303)).
4.35
Indenture dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-33303)).
4.36
Registration Rights Agreement dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and Wells Fargo Securities, LLC, as representative of the several initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-33303)).
Number
Description
4.37
Registration Rights Agreement dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and Wells Fargo Securities, LLC, as representative of the several initial purchasers party thereto (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-33303)).
4.38
Supplemental Indenture dated October 11, 2016 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiaries, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.13 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33303)).
4.39
Specimen Unit Certificate for the Series A Preferred Units (attached as Exhibit B to the Second Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP and incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 15, 2015 (File No. 001-33303)).
10.1
Second Amendment and Restatement Agreement dated as of October 7, 2016, by and among Targa Resources Partners LP, Bank of America, N.A., and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 11, 2016 (File No. 001-33303)).
10.2
Contribution, Conveyance and Assumption Agreement, dated February 14, 2007, by and among Targa Resources Partners LP, Targa Resources Operating LP, Targa Resources GP LLC, Targa Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa Regulated Holdings LLC, Targa North Texas GP LLC and Targa North Texas LP (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
10.3
Contribution, Conveyance and Assumption Agreement, dated October 24, 2007, by and among Targa Resources Partners LP, Targa Resources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa LA LLC, Targa LA PS LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)).
10.4
Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)).
10.5
Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC, Targa Midstream Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa Resources Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
10.6
Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 26, 2010 (File No. 001-33303)).
10.7
Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 4, 2010 (File No. 001-33303)).
10.8
Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)).
10.9
First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
10.10
Purchase Agreement dated as of October 23, 2014 by and among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBS Securities Inc., Wells Fargo Securities, LLC, Goldman, Sachs & Co. and UBS Securities LLC, as representatives of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 29, 2014 (File No. 001-33303)).
Number
Description
10.11
Purchase Agreement dated as of January 15, 2015 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., RBS Securities Inc., Morgan Stanley & Co. LLC and J.P. Morgan Securities LLC, as representatives of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on 8-K filed January 30, 2015 (File No. 001-33303)).
10.12
Purchase Agreement dated as of September 9, 2015 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on 8-K filed September 15, 2015 (File No. 001-33303)).
10.13
Purchase Agreement dated as of September 22, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and Wells Fargo Securities, LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 28, 2016 (File No. 001-33303)).
10.14
Receivables Purchase Agreement, dated January 10, 2013, by and among Targa Receivables LLC, the Partnership, as initial Servicer, the various conduit purchasers from time to time party thereto, the various committed purchasers from time to time party thereto, the various purchaser agents from time to time party thereto, the various LC participants from time to time party thereto and PNC Bank, National Association as Administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 14, 2013 (File No. 001-33303)).
10.15
Purchase and Sale Agreement, dated January 10, 2013, between the originators from time to time party thereto as Originators and Targa Receivables LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 14, 2013 (File No. 001-33303)).
10.16
Second Amendment to Receivables Purchase Agreement, dated December 13, 2013, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 17, 2013 (File No. 001-33303)).
10.17
Fourth Amendment to Receivables Purchase Agreement, dated December 11, 2015, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 15, 2015 (File No. 001-33303)).
10.18
Fifth Amendment to Receivables Purchase Agreement, dated December 9, 2016, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 5, 2017 (File No. 001-33303)).
10.19+
Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 1, 2007 (File No. 333-138747)).
10.20+
First Amendment to the Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.21+
Form of Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by reference to Exhibit 10.93 of Targa Investment’s Inc.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
10.22+
Targa Resources Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 1, 2007 (File No. 333-138747)).
10.23+
Amendment to Targa Resources Partners LP Long-Term Incentive Plan dated December 18, 2008 (incorporated by reference to Exhibit 10.10 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)).
10.24+
Form of Restricted Unit Grant Agreement - 2010 (incorporated by reference to Exhibit 10.15 to Targa Resources Partners LP’s Annual Report on Form 10-K filed March 4, 2010 (File No. 001-33303)).
Number
Description
10.25+
Targa Resources Partners LP Performance Unit Grant Agreement (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.26+
Targa Resources Partners LP Performance Unit Grant Agreement under the Targa Resources Corp. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.27+
Targa Resources Partners LP Amendment to Outstanding Performance Units (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.28+
Targa Resources Corp. Amendment to Targa Resources Partners LP Outstanding Performance Units (incorporated by reference to Exhibit 10.5 to Targa Resources Partners LP's Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)).
10.29+
Targa Resources Corp. 2015 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 20, 2015 (File No. 001-33303)).
10.30+
Targa Resources Corp. 2016 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 22, 2016 (File No. 001-33303)).
10.31+
Targa Resources Corp. 2017 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 25, 2017 (File No. 001-33303)).
10.32+
Targa Resources Executive Officer Change In Control Severance Program (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 19, 2012 ((File No. 001-33303)).
10.33+
First Amendment to the Targa Resources Executive Officer Change in Control Severance Program, dated December 3, 2015 (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 8, 2015 ((File No. 001-33303)).
10.34+
Form of Indemnification Agreement between Targa Resources Investments Inc. and each of the directors and officers thereof (incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 8, 2010 (File No. 333-169277)).
10.35+
Targa Resources Partners LP Indemnification Agreement for Robert B. Evans dated February 14, 2007 (incorporated by reference to Exhibit 10.11 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
10.36+
Targa Resources Partners LP Indemnification Agreement for Barry R. Pearl dated February 14, 2007 (incorporated by reference to Exhibit 10.12 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
10.37+
Indemnification Agreement by and between Targa Resources Corp. and Laura C. Fulton, dated February 26, 2013 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 1, 2013 (File No. 001-34991)).
10.38+
Indemnification Agreement by and between Targa Resources Corp. and Waters S. Davis, IV, dated July 23, 2015 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed July 24, 2015 (File No. 001-34991)).
10.39+
Indemnification Agreement by and between Targa Resources Corp. and D. Scott Pryor, dated November 12, 2015 (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-33303)).
10.40+
Indemnification Agreement by and between Targa Resources Corp. and Patrick J. McDonie, dated November 12, 2015 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-33303)).
10.41+
Indemnification Agreement by and between Targa Resources Corp. and Dan C. Middlebrooks, dated November 12, 2015 (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-33303)).
Number
Description
10.42+
Indemnification Agreement by and between Targa Resources Corp. and Clark White, dated November 12, 2015 (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-33303)).
10.43
Gas Gathering and Purchase Agreement by and between Burlington Resources Oil & Gas Company LP, Burlington Resources Trading Inc. and Targa Midstream Services Limited Partnership (portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) (incorporated by reference to Exhibit 10.5 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 8, 2007 (File No. 333-138747)).
21.1*
List of Subsidiaries of Targa Resources Partners LP.
23.1*
Consent of Independent Registered Public Accounting Firm.
31.1*
Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*
Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1***
First Amendment to Membership Interest Purchase and Sale Agreement, dated December 20, 2012, by and among the Partnership, Saddle Butte Pipeline LLC, Saddle Butte Fort Berthold Gathering, LLC and Saddle Butte Assets, LLC (incorporated by reference to Exhibit 99.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 4, 2013 (File No. 001-33303)).
101.INS*
XBRL Instance Document
101.SCH*
XBRL Taxonomy Extension Schema Document
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
XBRL Taxonomy Extension Label Linkbase Document
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase Document
* Filed herewith
**Furnished herewith
*** Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted exhibit or Schedule to the SEC upon request
+ Management contract or compensatory plan or arrangement
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 17, 2017.
Signature
Title (Position with Targa Resources GP LLC)
/s/ Joe Bob Perkins
Chief Executive Officer and Director
Joe Bob Perkins
(Principal Executive Officer)
/s/ Matthew J. Meloy
Executive Vice President and Chief Financial Officer
Mathew J. Meloy
(Principal Financial Officer)
/s/ John R. Sparger
Senior Vice President and Chief Accounting Officer
John R. Sparger
(Principal Accounting Officer)
/s/ James W. Whalen
Executive Chairman of the Board and Director
James W. Whalen
/s/ Michael A. Heim
Vice Chairman of the Board and Director
Michael A. Heim
/s/ Charles R.Crisp __
Director
Charles R. Crips
/s/ Waters S. Davis, IV
Director
Waters S. Davis, IV
/s/ Robert B. Evans_
Director
Robert B. Evans
/s/ Laura C. Fulton__
Director
Laura C. Fulton
/s/ Ershel C. Redd Jr.
Director
Ershel C. Redd Jr.
/s/ Chris Tong______
Director
Chris Tong
/s/ Rene R Joyce____
Director
Rene R. Joyce
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
TARGA RESOURCES PARTNERS LP AUDITED CONSOLIDATED FINANCIAL STATEMENTS
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in 2013 to evaluate the effectiveness of the internal control over financial reporting. Based on that evaluation, management has concluded that the internal control over financial reporting was effective as of December 31, 2016, as discussed in Item 9A.
The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page.
/s/ Joe Bob Perkins
Joe Bob Perkins
Chief Executive Officer
(Principal Executive Officer)
/s/ Matthew J. Meloy
Matthew J. Meloy
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Report of Independent Registered Public Accounting Firm
To the Partners of Targa Resources Partners LP:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of changes in owners’ equity and of cash flows present fairly, in all material respects, the financial position of Targa Resources Partners LP and its subsidiaries (the “Partnership”) as of December 31, 2016 and December 31, 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these 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 these financial statements and on the Partnership’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. 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.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 17, 2017
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
See notes to consolidated financial statements.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
See notes to consolidated financial statements.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY
See notes to consolidated financial statements.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
See notes to consolidated financial statements.
TARGA RESOURCES PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.
Note 1 - Organization and Operations
Our Organization
Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.
On February 17, 2016, TRC completed the previously announced transactions contemplated pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transaction, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.
At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.
Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.”
On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (the “Special GP Interest” as defined in the Third A&R Partnership Agreement) held by 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 (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.
Our Operations
We are engaged in the business of:
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gathering, compressing, treating, processing and selling natural gas;
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storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;
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gathering, storing and terminaling crude oil; and
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storing, terminaling and selling refined petroleum products.
See Note 23 - Segment Information for certain financial information regarding our business segments.
The employees supporting our operations are employed by Targa. Our consolidated financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services.
Note 2 - Basis of Presentation
These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2016 and 2015, and the results of operations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2016, 2015 and 2014.
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.
As described in Note 4 - Business Acquisitions, the February 27, 2015 Atlas mergers involved two separate legal transactions involving different groups of equity holders. For GAAP reporting purposes, these two mergers are viewed as a single integrated transaction. As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. As further described in Note 4 - Business Acquisitions, our partnership agreement (the “Partnership Agreement”) was amended to provide for the issuance of the Special GP Interest in us equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation. On December 1, 2016, the Special GP Interest was eliminated with an amendment to the Partnership Agreement. See Note 14 - Partnership Units and Related Matters.
Change in Reportable Segments
Concurrent with the TRC/TRP Merger in February 2016, management reevaluated our reportable segments. See “Segment Information” included in Note 23 for a presentation of financial results by reportable segment, which have been recast to reflect our change in reporting segments for all periods presented.
Purchase of Versado Membership Interest
On October 31, 2016, we executed a Membership Interest Sale and Purchase Agreement with Chevron U.S.A. Inc. to acquire the remaining 37% membership interest in our consolidated subsidiary Versado Gas Processors, L.L.C. (“Versado”). As we continue to control Versado, the change in our ownership interest was accounted for as an equity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our Consolidated Statements of Operations as a result. See Note 17 - Contingencies.
Revisions of Previously Reported Activity in our Consolidated Statements of Comprehensive Income (Loss)
During the first quarter of 2016 we concluded that activity related to our commodity hedge contracts was not reported properly in our Consolidated Statements of Comprehensive Income (Loss) during 2015. The errors resulted in misstatements of the statement caption “Change in fair value” and equal offsetting misstatements of the caption “Settlements reclassified to revenues.” Related income tax effects were also misstated. The reported beginning and ending balance sheet values of Accumulated Other Comprehensive Income were unaffected.
We concluded that these misstatements were not material to any of the periods affected, as reported “Total Other Comprehensive Income” is unchanged. However, we have revised previous Consolidated Statements of Comprehensive Income (Loss) reported during 2015 to properly reflect changes in fair value and settlements reclassified to revenues. There is no impact on previously reported net income, total comprehensive income, cash flows, financial position or other profitability measures.
The following table displays the impact of these revisions to activity reported in our Consolidated Statements of Comprehensive Income (Loss) during the year ended December 31, 2015.
Note 3 - Significant Accounting Policies
Consolidation Policy
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas 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.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing goodwill and long-lived assets for possible impairment, (4) estimating the useful lives of assets, (5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemable preferred interests. Actual results, therefore, could differ materially from estimated amounts.
Cash and Cash Equivalents
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. Checks outstanding at the end of a period are reclassified to 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).
Comprehensive Income
Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges.
Allowance for Doubtful Accounts
Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.
Inventories
Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or market using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are classified as Property, Plant and Equipment. Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued at cost using the specific identification method.
Product Exchanges
Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities.
Gas Processing Imbalances
Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
Derivative Instruments
We utilize derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. 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 and from interest rate derivative instruments in interest expense.
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 measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the gain or loss related to the change in fair value to earnings in the current period.
We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
For balance sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fair values and any related collateral by counterparty on a gross basis.
Property, Plant and Equipment
Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of our property, plant and equipment purchased from Targa from 2007 to 2010 in drop-down transactions were stated at historical cost in the transactions recorded under common control accounting. 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 (asset group) with the asset’s (asset group’s) 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 increased depreciation expense 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 depreciation expense due to impairment. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations.
Goodwill
Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Goodwill must be assigned 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, to the extent triggering events exist, 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.
The annual goodwill impairment test typically entails performing a two-step goodwill impairment test. However, we are permitted to first assess qualitative factors to determine if the two-step goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or otherwise determine that a two-step goodwill impairment test is required, the first step involves comparing the estimated fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of a reporting unit exceeds its fair value, the second step is required and involves comparing the implied fair value of goodwill to the carrying value of goodwill for that reporting unit. The implied fair value of goodwill is determined by assigning the reporting unit’s fair value to its individual assets and liabilities. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of goodwill, the excess of the carrying value over the implied fair value is recognized as a goodwill impairment loss on our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets.
Intangible Assets
Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with business 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 on a straight-line basis or, where more appropriate, in a manner that closely resembles the expected pattern in which we benefit from services provided to customers.
Asset Retirement Obligations
We record the fair value of estimated asset retirement obligations (“AROs”) associated with tangible long-lived assets. Retirement obligations associated with long-lived assets are recognized for those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction. These obligations, which are estimated based on discounted cash flow estimates, are accreted to full value over time as a period cost. In addition, asset retirement costs are capitalized as part of the related asset’s carrying value and are depreciated over the asset’s respective useful life.
At least annually, we review the projected timing and amount of asset retirement obligations. Changes resulting from revisions to the timing or the amount of the undiscounted cash flows are recognized as an increase or decrease in the carrying amount of the retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, any difference between the recorded amount and the actual settlement cost will be recognized at a gain or loss.
Debt Issuance Costs
Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities are presented as other long-term assets and debt issuance costs
related to other long-term debt are reflected as a deduction from the carrying amount of other long-term debt in the Consolidated Balance Sheets. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs.
Accounts Receivable Securitization Facility
Proceeds from the sale or contribution of certain receivables under the accounts receivable securitization facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities on our Consolidated Statements of Cash Flows.
Environmental Liabilities and Other Loss Contingencies
Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.
Income Taxes
We generally are not subject to federal income taxes. For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners. The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the Consolidated Statements of Operations.
As part of the APL merger, we acquired TPL Arkoma, Inc. a corporate subsidiary subject to federal and state income tax. The Partnership’s corporate subsidiary accounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences.
As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes for our taxable corporate subsidiary. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets.
We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent 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, both positive and negative, 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. We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize deferred tax assets, and therefore no valuation allowance has been established.
The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level. We are also subject to the Texas margin tax, consisting generally of a 0.75% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. See Note 19 for discussion of the Partnership’s federal and state income tax expense (benefits) of its taxable subsidiary as well as the Partnership’s net deferred income tax assets (liabilities).
Noncontrolling Interests
Third-party ownership (other than mandatorily redeemable interests) in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of our Consolidated Balance Sheets. In the Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income, noncontrolling interests reflects the attribution of results to third-party investors.
Mandatorily Redeemable Preferred Interests
Mandatorily redeemable preferred interests are included in other long term liabilities (or assets) 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 become payable (or receivable) in the future when the interests are redeemed. Changes in the redemption value are recorded in interest expense, net on our Consolidated Statements of Operations.
Revenue Recognition
Our operating revenues are primarily derived from the following activities:
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sales of natural gas, NGLs, condensate, crude oil and petroleum products;
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services related to compressing, gathering, treating, and processing of natural gas; and
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services related to NGL fractionation, terminaling and storage, transportation and treating.
We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured.
For natural gas processing activities, we receive either fees and/or a percentage of proceeds from commodity sales as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Typically, our percent-of-proceeds contracts also include a fee-based component. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we retain the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids basis or a fee basis, depending on market conditions. Natural gas or NGLs that we purchase are in turn sold and recognized in accordance with the criteria outlined above.
We generally report sales revenues gross in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another are reported as a single transaction on a combined net basis.
We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized as revenue during the periods that services will be provided. Deferred revenue is included in Other long-term liabilities on our Consolidated Balance Sheets.
Unit-Based and Share-Based Compensation
Prior to the TRC/TRP Merger, we awarded unit-based compensation to employees of Targa and to directors and non-management directors of our General Partner in the form of restricted common units and performance units. We withheld units to satisfy employees’ tax withholding obligations on vested awards. The withheld shares were recorded as treasury units at cost. In connection with the TRC/TRP Merger, the unit-based compensation was converted to comparable share-based TRC awards and share-based compensation is now awarded in the form of TRC restricted stock, TRC restricted stock units, and TRC stock options. Compensation expense on awards that qualify as equity arrangements are measured by the fair value of the award as determined at the date of grant. Compensation expense on awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is allocated to us from TRC and recognized in general and administrative expense over the requisite service period of each award.
Recent Accounting Pronouncements
Revenue from Contracts with Customers
In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The update also creates 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 new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the
standard requires a five step process of (1) identifying the contracts with customers, (2) identifying the performance obligations in the contracts, (3) determining the transaction price, (4) allocating the transaction price to the performance obligations, and (5) recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retrospectively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the standard is adopted.
In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations. The amendments in this update improve the operability and understandability of the implementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. These amendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.
In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.
In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition, and also provide additional practical expedients.
In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs.
We expect to adopt this new revenue recognition standard on January 1, 2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We are continuing to evaluate the effect of the standard on our consolidated financial statements, including accounting associated with contracts containing noncash consideration and variable consideration, the effect of ASU 2016-20 on our disclosure requirements, and how the standard would impact our current revenue recognition and disclosure policies upon adoption.
Consolidation
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments were effective for us in 2016 with no impact on our consolidated financial statements.
Presentation of Debt Issuance Costs
In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability (other than line-of-credit or other revolving credit facilities) be presented in the Consolidated Balance Sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts. This update dealt solely with financial statement display matters; recognition and measurement of debt issuance costs were unaffected. We adopted the amendments on January 1, 2016 and have
reclassified unamortized debt issuance costs of $38.3 million on our Consolidated Balance Sheet as of December 31, 2015 from Other long-term assets to Long-term debt to conform to current year presentation. Our Consolidated Balance Sheet as of December 31, 2016 has $30.3 million in unamortized debt issuance costs classified in Long-term debt. Debt issuance costs associated with revolving credit facilities of $15.1 million and $5.9 million as of December 31, 2016 and December 31, 2015, respectively, remain classified in Other long-term assets on our Consolidated Balance Sheets.
Leases
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, 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. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.
Share-Based Compensation
In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this update provide, among other things, that (1) all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit in the income statement with the tax effects of exercised or vested awards treated as discrete items in the reporting period in which they occur and recognition of excess tax benefits regardless of whether the benefit reduces taxes payable in the current period; (2) excess tax benefits should be classified along with other income tax cash flows as an operating activity; (3) an entity can make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur; (4) the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and (5) cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity on the statement of cash flows. We adopted the applicable amendments in the second quarter of 2016; however there was no impact to our consolidated financial statements.
Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. These amendments 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 in this update 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 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. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.
Cash Flow Classification
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). These amendments clarify how entities should classify certain cash receipts and cash payments on 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. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.
Recognition of Intra-Entity Transfers of Assets Other than Inventory
In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The amendments in this update are intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset
transfer until the asset has been sold to an outside party which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates the exception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.
Business Combinations
In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments 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 a screen to determine when a set 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. These amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted for transactions that have not been previously reported. These amendments will be evaluated in conjunction with future acquisitions or disposals. We are in the process of evaluating whether we will early adopt this standard.
Goodwill Impairment
In January 2017, FASB issued ASU 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which eliminates Step 2 from the goodwill impairment test. Step 2 required entities to compute the implied fair value of goodwill if it was determined that the carrying amount of a reporting unit exceeded its fair value. Under the amendments in this update, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should 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. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. These amendments are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to apply these amendments for our annual goodwill impairment test as of November 30, 2017, or earlier if events or changes in circumstances indicate that an interim goodwill impairment test is necessary. Had we applied this new guidance for our November 2016 impairment test date, the full balance of our goodwill would have been impaired.
Note 4 - Business Acquisitions
2015 Acquisition
Atlas Mergers
On February 27, 2015, Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among (i) Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly-owned subsidiary of Targa (“GP Merger Sub”), Atlas Energy L.P., a Delaware limited partnership (“ATLS”) and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, the Partnership’s general partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly-owned subsidiary of the Partnership (“MLP Merger Sub”), ATLS, Atlas Pipeline Partners L.P., a Delaware limited partnership (“APL”) and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”). Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in the APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as a subsidiary of the Partnership. While the Atlas mergers were two separate legal transactions, for GAAP reporting purposes, they are viewed as a single integrated transaction. As such, the financial effects of the ATLS Merger Consideration (as defined below) paid by Targa have been reflected in these financial statements. In connection
with the Atlas mergers, APL changed its name to “Targa Pipeline Partners LP,” which we refer to as TPL, and ATLS changed its name to “Targa Energy LP.”
In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a separation and distribution agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro rata distribution to the ATLS unitholders of AEG common units representing a 100% interest in AEG (collectively, the “Spin-Off” and, together with the Atlas mergers, the “Atlas Transactions”).
On February 27, 2015, the Partnership Agreement was amended to provide for the issuance of the Special GP Interest representing the contribution to the Partnership of the APL GP interest acquired in the ATLS merger totaling $1.6 billion, which is reflected within General partner equity on the Consolidated Balance Sheets. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation. On December 1, 2016, the Special GP Interest was eliminated with an amendment to the Partnership Agreement. See Note 12 - Partnership Units and Related Matters.
We acquired all of the outstanding units of APL for a total purchase price of approximately $5.3 billion (including $1.8 billion of acquired debt and all other assumed liabilities). Of the $1.8 billion of debt acquired and other liabilities assumed, approximately $1.2 billion of the acquired debt was tendered and settled upon the closing of the Atlas mergers via our January 2015 cash tender offers. These tender offers were in connection with, and conditioned upon, the consummation of the merger with APL. The merger with APL, however, was not conditioned on the consummation of the tender offers. On that same date, Targa acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities).
Pursuant to the APL Merger Agreement, our general partner entered into an amendment to our Partnership Agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to TRC, as the holder of the Partnership’s IDRs by (a) $9,375,000 per quarter during the first four quarters following the APL merger, (b) $6,250,000 per quarter for the next four quarters, (c) $2,500,000 per quarter for the next four quarters and (d) $1,250,000 per quarter for the next four quarters, with the amount of such reductions to be distributed pro rata to the holders of our outstanding common units. On December 1, 2016, the IDRs were eliminated with an amendment to the Partnership Agreement. See Note 12 - Partnership Units and Related Matters. 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.
TPL is a provider of natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale in South Texas. The Atlas mergers added TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations. In total, TPL added 2,053 MMcf/d of processing capacity and 12,220 miles of additional pipeline. The operating results of TPL are reported in our Gathering and Processing segment.
The APL merger was a unit-for-unit transaction with an exchange ratio of 0.5846 of our common units (the “APL Unit Consideration”) and $1.26 in cash for each APL common unit (the “APL Cash Consideration” and, with the APL Unit Consideration, the “APL Merger Consideration”), a $128.0 million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees’ APL phantom awards. We issued 58,614,157 of our common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on the NYSE on February 27, 2015). The cash component of the APL merger also included $701.4 million for the mandatory repayment and extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million of payments related to change of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, Targa contributed $52.4 million to us to maintain its 2% general partner interest.
In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APL merger.
The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and, with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). Targa issued 10,126,532 of its common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for
reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date.
ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Targa’s acquisition of ATLS resulted in Targa acquiring these common units (converted to 3,363,935 of our common units) valued at approximately $147.4 million (based on the $43.82 closing market price of our common units on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million.
All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in an Employee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effective time of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became an employee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Each outstanding vested ATLS option held by an employee of APL who became an employee of Targa in connection with the Atlas Transactions (a “Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLS common unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRC Common Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option or phantom unit award (in the case of options, net of the applicable exercise price).
In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled and converted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Each outstanding APL phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the APL Cash Consideration in respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of our common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APL phantom unit award.
The acquired business contributed revenues of $1,459.3 million and a net loss of $30.1 million to us for the period from February 27, 2015 to December 31, 2015, and is reported in our Gathering and Processing segment. Cumulative acquisition-related costs totaled $19.3 million. These expenses are included in other expense in our Consolidated Statements of Operations.
Pro Forma Impact of Atlas Mergers on Consolidated Statement of Operations
The following summarized unaudited pro forma Consolidated Statement of Operations information for the year ended December 31, 2015 assumes that our acquisition of APL and Targa’s acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed the APL merger as of January 1, 2014, or that the results that will be attained in the future. Amounts presented below are in millions:
The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making adjustments to:
•
Reflect the change in amortization expense resulting from the difference between the historical balances of APL’s intangible assets, net, and the fair value of intangible assets acquired.
•
Reflect the change in depreciation expense resulting from the difference between the historical balances of APL’s property, plant and equipment, net, and the fair value of property, plant and equipment acquired.
•
Reflect the change in interest expense resulting from our financing activities directly related to the Atlas mergers as compared to APL’s historical interest expense.
•
Reflect the changes in stock-based compensation expense related to the fair value of the unvested portion of replacement Partnership Long Term Incentive Plan (“LTIP”) awards that were issued in connection with the acquisition to APL phantom unitholders who continue to provide service as Targa employees following the completion of the APL merger.
•
Remove the results of operations attributable to the February 2015 transfer to Atlas Resource Partners, L.P. of 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee.
•
Exclude $19.3 million of acquisition-related costs incurred as of December 31, 2015 from pro forma net income for the year ended December 31, 2015.
•
Reflect the change in APL’s revenues and product purchases to report plant sales of Y-grade at contractual net values to conform to our accounting policy.
The following table summarizes the consideration transferred to acquire ATLS and APL, which are viewed together as a single integrated transaction for GAAP reporting purposes:
(1)
Targa acquired $5.5 million of cash.
(2)
We acquired $35.3 million of cash.
(3)
The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award.
Our final fair value determination related to the Atlas mergers was as follows:
The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer
contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 - Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.
The excess of the fair value of the consideration transferred over the fair value of net assets acquired was approximately $707.0 million which was recorded as goodwill. The determination of goodwill is attributable to the workforce of the acquired business and the expected synergies with us and Targa. Goodwill was attributed to the WestTX, SouthTX and SouthOK reporting units in our Gathering and Processing segment. The goodwill is amortizable over 15 years for tax purposes. See Note 7 - Goodwill.
The fair value of assets acquired included trade receivables of $178.1 million. The gross amount due under contracts was $178.1 million, all of which was expected to be collectible. The fair value of assets acquired included other receivables of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets related to a contractual settlement with a counterparty.
Mandatorily Redeemable Preferred Interests
Other long-term liabilities acquired included $109.3 million related to mandatorily redeemable preferred interests held by our partner in two joint ventures. See Note 11 - Other Long-Term Liabilities.
Contingent Consideration
A liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fair value. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period. The acquisition date fair value of the remaining contingent payment of $4.2 million was recorded within other long term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability are included in earnings.
Replacement Phantom Units
In connection with the Atlas mergers, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three year term.
Each replacement phantom unit will entitle the grantee a common unit of TRP on the vesting date and is an equity-settled award. The replacement phantom units include distribution equivalent rights (“DERs”). When we declare and pay cash distributions, the holders of replacement phantom units are entitled within 60 days to receive cash payment of DERs in an amount equal to the cash distributions the holders would have received if they were the holders of record on the record date of the number of our common units related to the replacement phantom units.
The fair value of the replacement phantom units was based on the closing price of our units at the close of trading on February 27, 2015. The fair value was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award. See Note 22 - Compensation Plans for discussion of the impact of the TRC/TRP Merger on the replacement phantom units.
Subsequent Events
On January 22, 2017, we entered into definitive agreements to purchase 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “Outrigger Delaware”) and Outrigger Midland Operating, LLC (“Outrigger Midland” and together with “Outrigger Delaware”, “Outrigger”) (the “Permian Acquisition”).
We will pay $475 million in cash at closing and $90 million within 90 days of closing. Subject to certain performance-linked measures and other conditions, additional cash of up to $935 million may be received by the owners of Outrigger Delaware and Outrigger Midland in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from existing contracts. We currently expect to close the transaction during the first quarter of 2017, subject to customary regulatory approvals and closing conditions.
Outrigger Delaware’s gas gathering and processing and crude gathering systems are located in Loving, Winkler and Ward counties. 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. Outrigger Delaware’s assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Delaware system.
Outrigger Midland’s gas gathering and processing and crude gathering systems are located in Howard, Martin and Borden counties. 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. Outrigger Midland currently has 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Midland system.
We anticipate connecting Outrigger Delaware to our existing Sand Hills system and Outrigger Midland to our existing WestTX system during 2017, creating operational and capital synergies.
On January 26, 2017, Targa completed a public offering of 9,200,000 shares of common stock (including underwriters’ overallotment option) at a price of $57.65, providing net proceeds of $524.1 million. Targa intends to use the net proceeds from this public offering to fund a portion of the $565 million initial purchase price of the Permian Acquisition
We expect that the remaining portion of the purchase price and related fees and expenses will be funded with borrowings under our senior secured revolving credit facility or, subject to market conditions, proceeds from the issuance of private or public securities. Prior to funding the Permian Acquisition, or if we do not complete the pending Permian Acquisition, Targa may use the net proceeds from its offering for general corporate purposes, which may include, among other things, repayment of Targa’s indebtedness (including our indebtedness), acquisitions, capital expenditures, additions to working capital and redeeming or repurchasing some of our outstanding notes.
Note 5 - Inventories
Note 6 - Property, Plant and Equipment and Intangible Assets
Property, Plant and Equipment
For each of the years ended December 31, 2016, 2015, and 2014 depreciation expense for property, plant and equipment was $601.5 million, $540.5 million and $285.0 million.
We recorded non-cash pre-tax impairment charges of $32.6 million in 2015 and $3.2 million in 2014 due to the impairment of certain gas processing facilities and gathering systems associated with our Coastal and Big Lake operations. The impairments are a result of reduced forecasted gas processing volumes due to market conditions and processing spreads in Louisiana in the fourth quarter of 2015 and 2014. We measured the impairment of property, plant and equipment using discounted estimated future cash flows representative of a Level 3 fair value measurement. These carrying value adjustments are included in depreciation and amortization expenses on our Consolidated Statements of Operations.
Intangible Assets
Intangible assets consist of customer contracts and customer relationships acquired in the Atlas mergers in 2015 and our Badlands business 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.
The fair values of intangible assets acquired in the Atlas mergers were recorded at a fair value of $1,354.9 million and are being amortized over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation over a 20-year life.
The changes in our intangible assets are as follows:
For each of the years ended December 31, 2016, 2015, and 2014 amortization expense for our intangible assets was $156.1 million, $136.7 million and $61.5 million. The estimated annual amortization expense for intangible assets is approximately $149.4 million, $135.7 million, $124.7 million, $112.5 million and $102.6 million for each of the years 2017 through 2021. As of December 31, 2016 the weighted average amortization period for our intangible assets was approximately 17.6 years.
Note 7 - Goodwill
We recognized goodwill of approximately $707.0 million when we acquired Atlas on February 27, 2015. This goodwill was attributed to the WestTX, SouthTX and SouthOK 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 oil, 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. As of December 31, 2015, we had not completed our November 30, 2015 impairment assessment. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment of $290.0 million during the fourth quarter of 2015. The provisional goodwill impairment reduced the carrying value of goodwill to $417.0 million on our Consolidated Balance Sheets as of December 31, 2015.
During the first quarter of 2016, we finalized our evaluation of goodwill for impairment and recorded additional impairment expense of $24.0 million in our Consolidated Statement of Operations and reduced the carrying value of goodwill to $393.0 million on our Consolidated Balance Sheets as of March 31, 2016. 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 annual evaluation of goodwill for impairment was completed in the fourth quarter of 2016 and we recorded impairment expense of $183.0 million in our Consolidated Statement of Operations and reduced the carrying value of goodwill to $210.0 million on our Consolidated Balance Sheets. The additional impairment of goodwill during the fourth quarter of 2016 was primarily 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.
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 refinement of the valuation methodology reflects (1) the manner in which market participants commonly transact for these types of assets, and (2) the inherent uncertainty involved in forecasting commodity prices beyond the periods for which observable market prices and consensus pricing are available. The future cash flows for our reporting units are based on our estimates, at that time, of future revenues, income from operations and other factors, such as working capital and timing of capital expenditures. We take into account current and expected industry and market conditions, including commodity pricing and volumetric forecasts in the basins in which the reporting units operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital determined from relevant market comparisons.
The fair value measurements utilized for the evaluation of goodwill for impairment are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 - Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.
Changes in the gross amounts of our goodwill are as follows:
Should energy industry conditions deteriorate, there is a possibility that reporting unit fair values could deteriorate further and goodwill may be impaired in a future period. Further, upon our adoption of ASU 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, the accounting guidance for the calculation of impairment charges will change and may result in an impairment in a future period that would otherwise not have been recognized under the current guidance. See Note 3 - Significant Accounting Policies for additional discussion of this recent accounting standard.
Note 8 - Investments in Unconsolidated Affiliates
Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: 75% interest in T2 LaSalle; 50% interest in T2 Eagle Ford; and 50% interest in T2 EF Cogen (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. 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. Our maximum exposure to loss as a result of our involvement with the T2 Joint Ventures includes our equity investment, any additional capital contribution commitments, and our share of any operating expenses incurred by the T2 Joint Ventures.
The following table shows the activity related to our investments in unconsolidated affiliates:
(1)
Includes $4.1 million and $1.2 million in distributions received from GCF and the T2 Joint Ventures in excess of our share of cumulative earnings for the years ended December 31, 2016 and 2015. Includes $5.7 million in distributions from GCF in excess of our share of cumulative earnings for the year ended December 31, 2014. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.
The recorded value of the T2 Joint Ventures is based on fair values at the date of acquisition which results in an excess fair value of $36.2 million over the book value of the joint venture capital accounts as of December 31, 2016. This basis difference is attributable to depreciable tangible assets and is being amortized over the estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 - Business Acquisitions for further information regarding the fair value determinations related to the Atlas mergers.
Note 9 - Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities includes $30.2 million and $34.0 million of liabilities to creditors to whom we have issued checks that remain outstanding as of December 31, 2016 and December 31, 2015.
Note 10 - Debt Obligations
(1)
As of December 31, 2016, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,436.8 million.
(2)
TPL notes are not guaranteed by us.
The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2016, for the next five years, and in total thereafter:
The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2016:
Compliance with Debt Covenants
As of December 31, 2016, we were in compliance with the covenants contained in our various debt agreements.
Debt Obligations
Revolving Credit Facility
In October 2016, we entered into the Second Amendment and Restatement Agreement (the “Restatement”) to effectuate the Third Amended and Restated Credit Agreement (the “TRP Credit Agreement”). The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million.
The TRP Credit Agreement designates TPL and certain of its subsidiaries as Restricted Subsidiaries and provides for certain changes to occur upon the Partnership receiving an investment grade credit rating from Moody’s or S&P, including the release of the security interests in all collateral at the request of the Partnership. As a result of the TRP Credit Agreement, during the fourth quarter of 2016, we recorded a partial write-off of $0.9 million of debt issuance costs associated with the TRP Revolver as a result of a change in syndicate members under the TRP Revolver. The remaining debt issuance costs associated with the TRP Revolver along with debt issuance costs incurred with this amendment will be amortized on a straight-line basis over the life of the TRP Revolver.
In 2015, we used proceeds from borrowings under the TRP Revolver to fund some of the cash components of the APL merger, including $701.4 million for the repayments of the APL Revolver and $28.8 million related to change of control payments.
The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 0.75% to 1.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA). The Eurodollar rate is equal to LIBOR rate plus an applicable margin ranging from 1.75% to 2.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA).
We are required to pay a commitment fee equal to an applicable rate ranging from 0.3% to 0.5% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA) times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable rate ranging from 1.75% to 2.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA).
The TRP Revolver is collateralized by a majority of our assets. Borrowings are guaranteed by our restricted subsidiaries.
The TRP Revolver restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in the TRP Revolver) exists or would result from such distribution. The TRP Revolver requires us to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA of no more than 5.50 to 1.00. The TRP Revolver also requires us to maintain a ratio of consolidated EBITDA to consolidated interest expense of no less than 2.25 to 1.00. In addition, the TRP Revolver contains various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates (in each case, subject to our right to incur indebtedness or grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing).
Accounts Receivable Securitization Facility
The Securitization Facility provides up to $275.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 8, 2017. Under the Securitization Facility, 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 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 subsidiaries or the Partnership. Any excess receivables are eligible to satisfy the claims. As of December 31, 2016, total funding under the Securitization Facility was $275.0 million.
Senior Unsecured Notes
All issues of unsecured senior notes are pari passu with existing and future senior indebtedness, including indebtedness under the TRP Revolver. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by us and our restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver, which is secured by substantially all of our assets and the Securitization Facility, which is secured by accounts receivable pledged under the facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears.
Our senior unsecured notes and associated indenture agreements restrict our ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Corporation (“S&P’) and no Default or Event of Default (each as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Partnership and its subsidiaries will cease to be subject to such covenants.
We may redeem up to 35% of the aggregate principal amount of the notes in the table below at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days of the date of the closing of such equity offering.
We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed.
Senior Notes Issuances
In October 2014, the Partnership and Targa Resources Partners Finance Corporation (collectively, the “Partnership Issuers”) issued $800.0 million in aggregate principal amount of 4⅛% Senior Notes due 2019 (the “4⅛% Notes”). The 4⅛% Notes resulted in approximately $790.8 million of net proceeds, which were used to reduce borrowings under the TRP Revolver and Securitization Facility and for general partnership purposes.
In January 2015, the Partnership Issuers issued $1.1 billion in aggregate principal amount of 5% Senior Notes due 2018 (the “5% Notes”). The 5% Notes resulted in approximately $1,089.8 million of net proceeds after costs, which were used with borrowings under the TRP Revolver to fund the TPL Notes Tender Offers and the Change of Control Offer (each as defined below). The 5% Notes are unsecured senior obligations that have substantially the same terms and covenants as our other senior notes.
In September 2015, the Partnership Issuers issued $600 million in aggregate principal amount of 6¾% Senior Notes due 2024 (the “6¾% Notes”). The 6¾% Notes resulted in approximately $595.0 million of net proceeds after costs, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. The 6¾% Notes are unsecured senior obligations that have substantially the same terms and covenants as our other senior notes.
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”), yielding net proceeds after costs of approximately $496.2 million and $496.2 million respectively. The 2016 Senior Notes have substantially similar terms and 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. See “Debt Repurchases and Extinguishments” for further details of the concurrent tender offers.
Shelf Registrations
April 2013 Shelf
In April 2013, we filed with the SEC a universal shelf registration statement (the “April 2013 Shelf”), which provided us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The April 2013 Shelf expired in April 2016. There was no activity under the April 2013 Shelf during the years ended December 31, 2016, 2015 and 2014.
July 2013 Shelf
In July 2013, we filed with the SEC a universal shelf registration statement that allowed us to issue up to an aggregate of $800.0 million of debt or equity securities (the “July 2013 Shelf”). The July 2013 Shelf expired in August 2016.
April 2015 Shelf
In April 2015, we filed with the SEC a universal shelf registration statement that allows us to issue up to an aggregate of $1.0 billion of debt or equity securities (the “April 2015 Shelf”). The April 2015 Shelf expires in April 2018.
Debt Repurchases & Extinguishments
In November 2014, we redeemed the outstanding 7⅞% Notes at a price of 103.938% plus accrued interest through the redemption date. The redemption resulted in a $12.4 million loss on redemption for the year ended December 31, 2014, consisting of premiums paid of $9.9 million and a non-cash loss to write-off $2.5 million of unamortized debt issuance costs.
In December 2015, we repurchased on the open market a portion of our outstanding Senior Notes as follows:
The December 2015 Senior Note repurchases resulted in a $3.6 million gain on debt repurchases and a write-off of $0.1 million in related debt issuance costs.
During the year ended December 31, 2016, we repurchased on the open market a portion of our outstanding senior notes as follows:
We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Senior Notes Tender Offers
Concurrently with the October 2016 Offering, we commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of our 5% Senior Notes due January 2018 (the “5% Notes”), 6⅝% Senior Notes due October 2020 (the “6⅝% Notes”) and 6⅞% Senior Notes due February 2021 (the “6⅞% Notes” and together with the 5% Notes and 6⅝% Notes, the “Tender Notes”). The total consideration for each series of Tender Notes included a premium
for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date.
The results of the Tender Offers, which closed in October 2016, were:
As a result of the Tender Offers, we recorded during the fourth quarter of 2016 a loss due to debt extinguishment of approximately $59.2 million comprised of the $41.8 million premium paid, the write-off of $5.8 million of debt issuance costs, $15.1 million of debt discounts less $3.5 million of debt premiums.
Note Redemptions
Subsequent to the closing of the Tender Offers in October 2016, we issued notices of full redemption (the “Note Redemptions”) to the trustees and noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition, we issued notice of full redemption to the trustees of the 6⅝% Senior Notes of Targa Pipeline Partners LP due October 2020 (the “6⅝% TPL Notes”). The redemption price for the 6⅝% Notes and the 6⅝% 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.
TPL Senior Notes Tender Offers
In January 2015, we commenced cash tender offers for any and all of the outstanding fixed rate senior secured notes to be acquired in the APL merger (the “TPL Notes Tender Offers”), which totaled $1.55 billion.
The results of the TPL Notes Tender Offers were:
In connection with the TPL Notes Tender Offers, on February 27, 2015, the supplemental indentures governing the 4 3⁄4% Senior Notes due 2021 (the “2021 TPL Notes”) and the 5 7⁄8% Senior Notes due 2023 (the “2023 TPL Notes”) of TPL and Targa Pipeline Finance Corporation (formerly known as Atlas Pipeline Finance Corporation) (together, the “APL Issuers”), became operative. These supplemental indentures eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2021 TPL Notes and the 2023 TPL Notes that were not accepted for payment.
Not having achieved the minimum tender condition on the 6 5⁄8% Senior Notes due 2020 of the APL Issuers (the “2020 TPL Notes”), we made a change of control offer, referred to as the Change of Control Offer, for any and all of the 2020 TPL Notes in advance of, and conditioned upon, the consummation of the APL merger. In March 2015, holders representing $4.8 million of the outstanding 2020 TPL Notes tendered their notes requiring a payment of $5.0 million, which included the change of control premium and accrued interest.
Payments made under the TPL Notes Tender Offers and Change of Control Offer totaling $1,168.8 million are presented as financing activities in the Consolidated Statements of Cash Flows.
Exchange Offer and Consent Solicitation
On April 13, 2015, the Partnership Issuers commenced an offer to exchange (the “Exchange Offer”) any and all of the outstanding 2020 TPL Notes, for an equal amount of new unsecured 6 5⁄8% Senior Notes due 2020 issued by the Partnership Issuers (the “6 5⁄8% Notes” or the “TRP 6 5⁄8% Notes”). On April 27, 2015, we had received tenders and consents from holders of approximately 96.3% of the total outstanding 2020 TPL Notes. As a result, the minimum tender condition to the Exchange Offer and related consent solicitation was satisfied, and the APL Issuers entered into a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2020 TPL Notes.
In May 2015, upon the closing of the Exchange Offer, the Partnership Issuers issued $342.1 million aggregate principal amount of the TRP 6 5⁄8% Notes to holders of the 2020 TPL Notes which were validly tendered for exchange. The related $5.6 million premium, resulting from acquisition date fair value accounting, will be amortized as an adjustment to interest expense over the remaining term of the TRP 6 5⁄8% Notes. We recognized $0.7 million of costs associated with the Exchange Offer, included as a loss from financing activities on the Consolidated Statements of Operations.
Debt Repurchases Summary
The following table summarizes the debt repurchases and extinguishments that are included in our Consolidated Statements of Operations:
Note 11 - Other Long-term Liabilities
Other long-term liabilities are comprised of the following obligations:
Asset Retirement Obligations
Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows:
Mandatorily Redeemable Preferred Interests
Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.
The joint ventures, collectively, hold $1.9 billion face value in notes receivable from our partner, which are due July 2042. The interest rate payable under the notes receivable is a variable LIBOR-based rate. For the periods ending on December 31, 2016, and December 31, 2015, interest earned on the notes receivable of $10.5 million, and $8.9 million, exclusive of the priority return payable to our partner, is reflected within Interest expense, net on 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, 2016. 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.
The following table shows the changes attributable to mandatorily redeemable preferred interests:
Deferred Revenue
We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided.
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. (“Noble”) entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we will build and operate a 35,000 barrel per day crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 barrels of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be completed by early 2018, and has an estimated total cost of approximately $140 million. The first annual advance payment due under the Splitter Agreement was received in October 2016 and has been recorded as deferred revenue, as the Splitter Agreement requires future performance by Targa. Subsequent annual payments of $43 million (subject to an annual inflation factor) will be received through 2022. The deferred revenue will be recognized over the contractual period that future performance will be provided, currently anticipated to commence with start-up in 2018 and continuing through 2025.
Deferred revenue also includes consideration received in a 2015 amendment to a gas gathering and processing agreement. We measured the estimated fair value of the assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. The consideration paid for the contract amendment will require future performance by Targa which has resulted in the deferred revenue. The deferred revenue related to this amendment is being recognized on a straight-line basis through the end of the agreement’s term in 2030.
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 will be recognized over the periods that future performance will be provided, which extend through 2023.
For the years ended December 31, 2016, 2015 and 2014, we recognized approximately $3.1 million, $2.7 million and $0.1 million of revenue for these transactions.
The following table shows the components of deferred revenue:
The following table shows the changes in deferred revenue:
Note 12 - Partnership Units and Related Matters
Common Units Equity Offerings
In May 2014, we entered into an equity distribution agreement (“EDA”) under our July 2013 Shelf (the “May 2014 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregate of $400 million of our common units.
During the year ended 2014, pursuant to the August 2013 EDA and the May 2014 EDA, we issued a total of 7,175,096 common units representing total net proceeds of $408.4 million, (net of commissions up to 1% of gross proceeds to our sales agent), which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. Targa contributed $8.4 million to us to maintain its 2% general partner interest.
As part of the Atlas merger in February 2015, we issued 58,614,157 common units to former APL unitholders as consideration for the APL merger, of which 3,363,935 common units represented ATLS’s common unit ownership in APL and were issued to Targa. Targa contributed $52.4 million to us to maintain its 2% general partner interest.
In May 2015, we entered into the May 2015 EDA under the April 2015 Shelf pursuant to which we may sell through our sales agents, at our option, up to an aggregate of $1.0 billion of our common units. As of December 31, 2015, we issued 7,377,380 common units under our EDAs, receiving net proceeds of $316.1 million. As of December 31, 2015, approximately $4.2 million of capacity and $835.6 million of capacity remained under the May 2014 and May 2015 EDAs. Targa contributed $6.5 million to us to maintain its 2% general partner interest.
Since January 2016, no units have been issued from any of the EDAs.
TRC/TRP Merger
On February 17, 2016, TRC completed the TRC/TRP Merger, indirectly acquiring all of the outstanding common units not already owned by TRC and its subsidiaries. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.
At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of TRC shares. TRC issued 104,525,775 shares of its common stock to third-party unitholders of our common units in exchange for all of our 168,590,009 outstanding common units that TRC previously did not own. No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.
Pursuant to the TRC/TRP Merger Agreement, our common units were delisted from the NYSE and deregistered under the Exchange Act and our common units are no longer publicly traded. Our 5,000,000 Preferred Units remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE.
Distributions
As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement, as to whether to distribute all available cash for any period.
The following details the distributions declared or paid by the Partnership during 2016, 2015 and 2014:
Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDRs of $9.375 million were reallocated to common unitholders for each of the four quarters of 2015. The IDR Giveback Amendment covered sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015. The IDR Giveback resulted in reallocation of IDR payments to common unitholders of $6.25 million for each of the first three quarters of 2016.
On October 19, 2016, we executed the Third A&R Partnership Agreement, which became effective on December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the IDRs held by 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, we 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.
Contributions
During 2016, Targa made total capital contributions to us of $1,381.0 million. 58,621,036 common units and 1,196,346 general partner units were issued for Targa’s contributions of $1,191.0 million. Subsequent to the effective date of the Third A&R Partnership Agreement, no units will be issued for capital contributions but all capital contributions will continue to be allocated 98% to the limited partner and 2% to the general partner. In December 2016, Targa made a $190.0 million capital contribution to us which was allocated accordingly.
Preferred Units
In October 2015, under the April 2013 Shelf, we completed an offering of 4,400,000 Preferred Units at a price of $25.00 per unit. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 600,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. We used the net proceeds from this offering to reduce borrowings under our senior secured credit facility and for general partnership purposes. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”
Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.
The Preferred Units, with respect to anticipated monthly distributions, rank:
•
senior to our common units and to each other class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior to or pari passu with the Preferred Units as to the payment of distributions;
•
pari passu with any class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior or subordinated to the Preferred Units as to the payment of distributions;
•
junior to all of our existing and future indebtedness (including (i) indebtedness outstanding under the TRP Revolver, (ii) our senior notes and (iii) indebtedness outstanding under the Securitization Facility and other liabilities with respect to assets available to satisfy claims against us; and
•
junior to each other class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is expressly made senior to the Preferred Units as to the payment of distributions.
At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. If we do not (or a third party with our prior written consent does not) exercise this option, then the holders of the Preferred Units (“Preferred Unitholders”) have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement. If we exercise (or a third party with our prior written consent exercises) our redemption rights relating to any Preferred Units, the holders of those Preferred Units will not have the conversion right described above with respect to the Preferred Units called for redemption. Holders of Preferred Units have no voting rights except for certain exceptions set forth in our Partnership Agreement.
As of December 31, 2016, we have 5,000,000 Preferred Units outstanding. We paid $11.3 million and $1.5 million of distributions to the holders of preferred units (“Preferred Unitholders”) during 2016 and 2015. The Preferred Units are reported as noncontrolling interests in our financial statements.
In January and February 2017, the board of directors of our general partner declared a cash distribution of $0.9 million each month for $0.1875 per Preferred Unit. The distributions declared in January were paid on February 15, 2017 and the distributions declared in February will be paid on March 15, 2017.
Note 13 - Derivative Instruments and Hedging Activities
The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Gathering and Processing segment that result from percent-of-proceeds processing arrangements. 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 necessarily 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.
As part of the Atlas mergers, outstanding APL 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 $26.6 million for the year ended December 31, 2016, and $67.9 million for the year ended December 31, 2015, related to these novated contracts. These settlements were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired and had no effect on results of operations.
The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, we recorded ineffectiveness losses of $0.9 million for the year ended December 31, 2015, related to otherwise qualifying APL derivatives, which are primarily natural gas swaps. There were no ineffectiveness losses on these derivatives for the year ended December 31, 2016.
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, 2016, 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 in 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 in our Consolidated Balance Sheets on a net basis is as follows:
Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Some of our hedges are futures contracts executed through a broker that clears the hedges through an exchange. We maintain a margin deposit with the broker in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within other current assets on our Consolidated Balance Sheets and is not offset against the fair values of our derivative instruments.
The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of $53.3 million as of December 31, 2016. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year 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 (“OCI”) 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, 2016, we expect to reclassify commodity hedge related deferred losses of $60.7 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2019, with $39.7 million to be reclassified over the next twelve months.
See Note 14 - Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.
Note 14 - Fair Value Measurements
Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.
Fair Value of Derivative Financial Instruments
Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.
The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at December 31, 2016, a net liability position of $53.3 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 liability of $107.4 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 $14.9 million, ignoring an adjustment for counterparty credit risk.
Fair Value of Other Financial Instruments
Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:
•
The TRP Revolver and the Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and
•
Senior unsecured notes are based on quoted market prices derived from trades of the debt.
We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value. See Note 4 - Business Acquisitions.
Fair Value Hierarchy
We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:
•
Level 1 - observable inputs such as quoted prices in active markets;
•
Level 2 - inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and
•
Level 3 - unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.
The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:
(1)
The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 - Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.
(2)
See Note 4 - Business Acquisitions.
Additional Information Regarding Level 3 Fair Value Measurements Included in 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, 2016, we had 17 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 contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. These probability-based inputs are not observable; therefore, the entire valuation of the contingent consideration is categorized in Level 3. Changes in the fair value of this liability are included in Other Income on the 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:
For the year ended December 31, 2016, we had no transfers of financial instruments out of Level 3 and into Level 2. Historically, transfers relate to long-term over-the-counter swaps for natural gas and NGL products for which observable market prices became available for substantially their full term.
Note 15 - Related Party Transactions - Targa
Relationship with Targa
We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.
Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.
The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.
(1)
Of the cash contributions from Targa related to limited partner ownership, $1,167.2 million was contributed for the issuance of common units and $186.2 million was contributed after the Third A&R Partnership Agreement.
Transactions with Unconsolidated Affiliates
For the years ended December 31, 2016, 2015 and 2014, transactions with GCF included in revenues were $0.4 million, $0.5 million and $0.8 million. For the same periods, transactions with GCF included in costs and expenses were $3.2 million, $5.8 million and $7.6 million. The Partnership is subject to paying a deficiency fee in instances where the Partnership does not deliver its minimum volume requirements as outlined in the Partnership and fractionation agreements with GCF.
We engage in the purchase and sale of residue gas and condensate with the T2 Joint Ventures. Revenue attributable to sales to T2 Eagle Ford and T2 Cogen were $4.6 million and $0.6 million for the year ended December 31, 2016 and $4.4 million and $1.4 million for the year ended December 31, 2015. Cost of sales attributable to T2 Eagle Ford were $2.6 million and $4.0 million for the years ended December 31, 2016 and 2015. Capacity lease fees paid to T2 Eagle Ford and T2 LaSalle and included in operating expenses were $3.2 million and $0.8 million for the year ended December 31, 2016 and $3.0 million and $1.3 million for the year ended December 31, 2015. These fees are billed to us based on our portion of the cost to operate each respective joint venture. As a result of this activity, we had a receivable balance with T2 Eagle Ford of $0.2 million and $0.4 million at December 31, 2016 and 2015 as well as a receivable balance with T2 Cogen of $0.1 million at December 31, 2015.
Note 16 - Commitments (Leases)
Future lease obligations are presented below in aggregate and for each of the next five fiscal years:
(1)
Includes minimum payments on lease obligations for office space, railcars and tractors.
(2)
Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual.
Total expenses incurred under the above lease obligations, including short-term leases of compressors and equipment, were:
(1)
Includes short-term leases for items such as compressors and equipment.
Note 17 - Contingencies
Legal Proceedings
Litigation related to TRC/TRP Merger
On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), TRP GP, the members of the board of TRP GP (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”). This lawsuit was styled Leslie Blumberg et al. v. TRC Resources Corp., et al., Cause No. 2015-75481, in the 234th Judicial District Court of Harris County, Texas (the “State Court Lawsuit”). The State Court Plaintiffs amended the State Court Lawsuit on July 26, 2016.
The State Court Plaintiffs alleged several causes of action challenging the TRC/TRP Merger. Generally, the State Court Plaintiffs alleged that (i) the members of the TRP GP Board breached express and/or implied duties under the Partnership Agreement and (ii) TRC, TRP GP, and Merger Sub aided and abetted in these alleged breaches of duties. The State Court Plaintiffs further alleged, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair, (e) the TRP GP Board had conflicts of interest due to TRC’s control of TRP GP, (f) the TRP GP Conflicts Committee’s financial advisor was conflicted and conducted flawed analyses, and (g) the joint proxy statement/prospectus filed in connection with the TRC/TRP Merger (the “Proxy”) failed to disclose allegedly material information concerning, among other things, (i) the TRC and TRP projections included in the Proxy, and (ii) the analyses conducted by the TRP GP Conflicts Committee’s financial advisor in connection with the TRC/TRP Merger.
Based on these allegations, the State Court Plaintiffs sought damages and attorneys’ fees. On February 26 and 29, 2016, the State Court Defendants filed general denials and asserted affirmative defenses. On August 26, 2016, the State Court Defendants filed Special Exceptions and a Motion for Summary Judgment. On December 5, 2016, the Court granted Defendants’ Motion for Summary Judgment and dismissed the State Court Lawsuit in its entirety with prejudice.
Environmental Proceedings
On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014. The Monument Gas Plant is owned by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A Inc. The Partnership has been in discussions with the New Mexico Environment Department to resolve the alleged violations. The New Mexico Environment Department has offered to settle the matter for $29,223.
We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.
Note 18 - Significant Risks and Uncertainties
Nature of Our Operations in Midstream Energy Industry
We operate in the midstream energy industry. Our business activities include gathering, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products and changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.
Our profitability could be impacted by a decline in the volume of crude oil, natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities, or otherwise, could result in a decline in the volume of crude oil, natural gas, NGLs and condensate handled by our facilities.
A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting
commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.
Our principal market risks are exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, and changes in interest rates.
Commodity Price Risk
A significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes as payment for services. The prices of natural gas and NGLs 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 and future commodity purchases and sales through 2019. 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 of natural gas or NGLs 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 typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. Our commodity hedges may expose us to the risk of financial loss in certain circumstances.
Counterparty Risk - Credit and Concentration
Derivative Counterparty Risk
Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.
We have master netting provisions in the International Swap Dealers Association agreements with all of 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 $21.9 million as of December 31, 2016. The range of losses attributable to our individual counterparties would be between $1.3 million and $3.8 million, depending on the counterparty in default.
Our 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 our 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.
Customer Credit Risk
We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met. Our allowance for doubtful accounts was $0.9 million as of December 31, 2016 and $0.1 million as of December 31, 2015.
Significant Commercial Relationship
During the years ended December 31, 2016, 2015 and 2014, we did not have any commercial relationships that exceeded 10% of consolidated revenues.
During the year ended December 31, 2016, ONEOK Hydrocarbon L.P. and DCP NGL Services LLC each accounted for 11% of our consolidated product purchases. During the year ended December 31, 2015, ONEOK Hydrocarbon L.P. accounted for 12% of our consolidated product purchases. During the year ended December 31, 2014, we did not have any suppliers that exceeded 10% of our
consolidated product purchases.
Interest Rate Risk
We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under the TRP Revolver and Securitization Facility.
Casualty or Other Risks
Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverage which is customary for the nature and scope of our operations. The majority of the insurance costs described above is allocated to us by Targa through the Partnership Agreement described in Note 15 - Related Party Transactions.
Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles may change overtime, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.
If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations. Furthermore, even when a business interruption event is covered, it could affect interperiod results as we would not recognize the contingent gain until realized in a period following the incident.
Note 19 - Other Operating (Income) Expense
Other Operating (Income) Expense is comprised of the following:
Note 20 - Income Tax
Prior to the TRC/TRP Merger, the Partnership was subject to the Texas margin tax, consisting generally of a 0.75% tax on the amounts by which total revenues exceed cost of goods sold, as apportioned to Texas. After the TRC/TRP Merger, TRC is the reporting company for the combined group. The Partnership still has audit responsibility for the pre-Merger years. As part of the APL merger in 2015, we acquired TPL Arkoma, Inc., a corporate subsidiary subject to federal and state income tax. Our corporate subsidiary accounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences.
Our deferred income tax assets and liabilities at December 31, 2016 and 2015, consisted of differences related to the timing of recognition of certain types of costs as follows:
As of December 31, 2016, TPL Arkoma, Inc. had net operating loss carry forwards for federal income tax purposes of approximately $51.3 million, which expire at various dates from 2029 to 2036. Management believes it more likely than not that the deferred tax asset will be fully utilized.
Note 21 - Supplemental Cash Flow Information
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(1)
Interest capitalized on major projects was $8.3 million, $13.2 million and $16.1 million for 2016, 2015 and 2014.
Note 22 - Compensation Plans
TRC Equity Compensation Plan
In 2007, both we and Targa adopted Long-Term Incentive Plans (each, an “LTIP”) for employees, consultants, directors and non-employee directors of us and our affiliates who perform services for Targa or its affiliates. The awards under this plan included performance units, phantom units and director grants. Our LTIP (“TRP LTIP”) provided for, among other things, the grant of both cash-settled and equity-settled performance units. In connection with the TRC/TRP Merger, as of February 17, 2016, Targa assumed, adopted, and amended the TRP LTIP, and changed the name of the plan to the Targa Resources Corp. Equity Compensation Plan (as assumed, adopted and amended, the “TRC Equity Compensation Plan” or the “Plan”), and Targa assumed all our obligations associated with the Plan existing prior to the assumption and adoption by us. The TRC Equity Compensation Plan allows for the grant of options, performance shares, restricted stocks, replacement stocks and other stock-based awards. The termination date for this plan was February 7, 2017.
Performance Units
The performance units granted under the TRP LTIP were linked to the performance of our common units. Performance unit awards granted under either LTIP may also include distribution equivalent rights (“DERs”). The TRP LTIP was administered by the board of directors of the general part 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. DERs 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. DERs 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. The weighted average grant date fair value of TRP LTIP performance units granted in 2015 and 2014, were $34.48 and $57.19.
Phantom Units
In 2015, we granted phantom units under the LTIP to various employees of Targa. These phantom units were denominated with respect to our common units, but not otherwise linked to the performance of our common units. Their vesting periods vary from one year to five years. The DERs of the phantom units were accumulated to be paid in cash at vesting date. In 2015, the Partnership issued 25,162 phantom units with a weighted average grant date fair value of $36.87.
Replacement Phantom Units
In connection with the APL merger in 2015, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees upon close of the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and will vest either 25% per year over the original four-year term or 33% per year over the original three-year term. The DERs of the replacement phantom units are paid in cash within 60 days of the payment of distributions. A total of 629,231 replacement phantom unit were granted in 2015 with the weighted average grant date fair value of $43.82.
Partnership Director Grants
Starting in 2012, the common units granted to our non-management directors vested immediately at the grant date. The weighted average grant date fair values of the director grants granted in 2016, 2015 and 2014 were $10.11, $44.67 and $50.29. The fair values related to the units vested were $0.3 million, $0.5 million and $0.4 million.
Impact of TRC/TRP Merger
The TRC/TRP Merger did not trigger the acceleration of any time-based vesting of any of our outstanding long-term equity incentive compensation awards under the TRP LTIP. All outstanding performance unit awards previously granted under the TRP LTIP were converted and restated into comparable awards based on Targa’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the TRC/TRP Merger, into an award to acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Targa common shares determined by multiplying the number of performance units subject to each award by the exchange ratio in the TRC/TRP Merger (0.62), rounded down to the nearest whole share, and the performance factor was eliminated.
At the time of the TRC/TRP Merger and immediately prior to the assumption and adoption of the Plan, the only outstanding awards under the TRP LTIP were-equity settled performance units and certain phantom units of us. All such outstanding awards were converted into comparable time-based restricted unit awards (RSUs) based on Targa’s common stock. All amounts previously credited as distribution equivalent rights under any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forth in the applicable award agreement, subject to the same time-based vesting schedule previously included in the performance unit award, but without application of any performance factor.
The 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 will be recognized prospectively in general and administrative expense over the remaining service period of each award.
In 2016 Targa issued 331,282 restricted stock units under the Plan 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 Targa’s non executives.
The following table summarizes the restricted stock units for the year ended 2016 under the Plan:
TRC Long Term Incentive Plan
The TRC LTIP is administered by the compensation committee (the “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 Targa must record an accrued expense based on fair value of the stock on the last business day of the quarter.
The following table summarizes the cash-settled restricted stock units for the year ended 2016 under the TRC LTIP (in shares and millions of dollars).
The cash settled for the awards under TRC LTIP were $4.8 million, $7.8 million and $14.7 million for 2016, 2015 and 2014. The remaining weighted average recognition period for the unrecognized compensation cost is approximately 1.3 years.
2010 TRC Stock Incentive Plan
In December 2010, Targa adopted the Targa Resources Corp. 2010 Stock Incentive Plan (“2010 TRC Plan”) for employees, consultants and non-employee directors of the Company. 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 a “Awards”).
Restricted Stock Awards - Total shares of our common stock authorized under this plan are 5,000,000. Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends, and paid in cash when the award vests. The restricted stock awards will be included in the outstanding shares of our common stock upon issuance.
Restricted Stock in Lieu of Salary -During 2016, Targa issued on a quarterly basis, a total of 32,267 shares of restricted stock to two of our executives in lieu of all of their 2016 base salary. These awards vest 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.
Restricted Stock in Lieu of Bonus - During 2016, Targa issued 153,252 shares of restricted stock awards in lieu of cash bonus for its executives at the weighted average grant-date fair value of $26.34. These awards will cliff vest in three years.
Director Grants - The committee awarded Targa’s common stock to its outside directors. In 2016, 2015 and 2014, Targa issued 24,234, 6,429 and 5,165 shares of director grants with the weighted average grant-date fair value of $16.45, $86.49 and $87.45.
Restricted Stock Units Awards - 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 2016, 2015 and 2014, Targa issued 1,129,705, 140,477 and 54,357 shares of RSUs with the weighted average grant-date fair value of $27.87, $83.54 and $112.89.
The following table summarizes the restricted stock and RSUs under the 2010 TRC Plan in shares and in dollars for the year indicated.
Stock compensation expense under Targa’s plans totaled $41.2 million, $22.8 million, and $25.4 million for the years ended December 31, 2016, 2015, and 2014.
As of December 31, 2016, Targa has $44.8 million of unrecognized compensation expenses associated with share-based awards and approximate remaining weighted average vesting periods of 2.3 years related to our various compensation plans.
The fair values of share-based awards vested in 2016, 2015 and 2014 were $19.8, $31.8 million and $20.1 million. Targa recognized $1.1 million and $1.0 million in tax benefits associated with the vesting of the awards in 2015 and 2014.
Pursuant to ASU 2016-09, tax benefits of dividends on share-based payment awards should be recognized as income tax benefits or expenses in the income statement. Targa adopted the applicable amendments in the second quarter of 2016 and recognized a $0.5 million tax deficiency as an income tax expense for the year ended 2016. See Note 2 - Basis of Presentation.
Subsequent Events
On January 14, 2017, 22,017 shares of restricted stock units granted on January 14, 2014 vested and Targa repurchased 6,990 shares at $57.95 per share to satisfy the employee’s minimum statutory tax withholdings on the vested awards.
In January 2017, the Committee made following awards under the 2010 TRC Plan.
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13,818 shares of TRC’s common stock to our outside directors.
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114,301 shares of restricted stock units to executive management and employees for the 2017 compensation cycle that will cliff vest three years from the grant date.
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113,901 shares of performance share units to executive management and employees for the 2017 compensation cycle that will vest on December 31, 2019.
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491,000 shares of our restricted stock units to executive management and employees. The awards will vest 30% in January 2021, 30% in January 2020 and 40% in January 2023.
The performance share units 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 that are based on the notional dividends accumulated during the vesting period.
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 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 performance share units equal the target number awarded multiplied by the TSR performance factor, and vested performance share units will be settled by the issuance of Company common stock. The value of dividend equivalent rights will be paid in cash.
Note 23 - Segment Information
We operate in two primary segments (previously referred to as divisions): (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. Concurrent with the completion of the TRC/TRP Merger in the first quarter of 2016, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of aggregation for our reportable segments. The increase in activity within Field Gathering and Processing due to the Atlas mergers in 2015 coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team. The Gathering and Processing division was previously disaggregated into two reportable segments-(a) Field Gathering and Processing and (b) Coastal Gathering and Processing. The Logistics and Marketing division (also referred to as the Downstream Business) was previously disaggregated into two reportable segments-(a) Logistics Assets and (b) Marketing and Distribution.
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; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs.
Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington.
Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin. and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.
Reportable segment information is shown in the following tables:
(1)
Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.
(1)
Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.
(1)
Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver.
The following table shows our consolidated revenues by product and service for the periods presented:
The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:
Note 24 - Selected Quarterly Financial Data (Unaudited)
Our results of operations by quarter for the years ended December 31, 2016 and 2015 were as follows:
(1)
Includes an additional goodwill impairment of $24.0 million in the first quarter of 2016. See Note 7 - Goodwill.
(2)
Includes a goodwill impairment of $183.0 million in the fourth quarter of 2016. See Note 7 - Goodwill.
(3)
Includes $32.6 million of impairment losses in the fourth quarter of 2015. See Note 6 - Property, Plant and Equipment and Intangible Assets.
(4)
Includes a provisional goodwill impairment of $290.0 million in the fourth quarter of 2015. See Note 7 - Goodwill.