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

Overview

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

On February 17, 2016, TRC completed its acquisition of all of the outstanding common units of the Partnership pursuant to the TRC/TRP Merger Agreement. We issued 104,525,775 shares of common stock in exchange for all of the outstanding common units of the Partnership that we previously did not own. As a result of the completion of the TRC/TRP Merger, the TRP common units are no longer publicly traded. The Preferred Units remain outstanding as preferred limited partner interests in TRP and continue to trade on the NYSE under the symbol “NGLS PRA.”

As we continue to control the Partnership, the change in our ownership interest as a result of the TRC/TRP Merger was accounted for as an equity transaction and no gain or loss was recognized in our Consolidated Statements of Operations related to the Buy-in Transaction. The equity interests in TRP (which are consolidated in our financial statements) that were owned by the public prior to February 17, 2016 are reflected within “noncontrolling interests” in our Consolidated Balance Sheets for periods prior to the merger date. The earnings recorded by TRP that were attributed to its common units held by the public prior to February 17, 2016 are reflected within “Net income attributable to noncontrolling interests” in our Consolidated Statements of Operations for periods prior to the merger date.

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 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 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

On February 17, 2016, we completed the TRC/TRP Merger, and issued 104,525,775 shares of our common stock to unitholders of the common units of the Partnership in exchange for all of the 168,590,009 outstanding common units of the Partnership that we did not previously own.

In March 2016, through a private placement, we issued 965,100 Preferred Shares with detachable warrants for $1,030 per share and received gross proceeds of $994.1 million.

In 2016, 19,983,843 warrants were exercised by their holders and net settled by us for 11,336,856 shares of common stock. As of December 31, 2016, 99,888 warrants remain outstanding.

During the year ended December 31, 2016, we repurchased a portion of the outstanding senior notes of the Partnership 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 or the Partnership may retire or

purchase various series of the Partnership’s outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

In May 2016, we entered into the May 2016 EDA, pursuant to which we may sell, at our option, up to an aggregate of $500 million of our common stock. The common stock available for sale under the May 2016 EDA was registered pursuant to a registration statement on Form S-3 filed on May 23, 2016. During the year ended December 31, 2016, we issued 11,074,266 shares of common stock under the May 2016 EDA, receiving net proceeds of $494.0 million.

In October 2016, the Partnership 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 concurrent tender offers for other series of senior notes and to fund redemption payments for certain note balances remaining after completion of the tender offers.

Concurrently with the October 2016 Offering, the Partnership commenced Tender Offers to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of the Tender Notes. The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that were 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, totaling $1,138.3 million of principal 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, the Partnership 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 the Partnership’s 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 the Partnership’s 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, the Partnership executed supplemental indentures relating to all of its outstanding series of Senior Notes to designate TPL and certain of its subsidiaries as guarantors of the Senior Notes.

In December 2016, the Partnership amended its 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.

In December 2016, we entered into the December 2016 EDA, pursuant to which we may sell, at our option, up to an aggregate of $750.0 million of our common stock. The common stock available for sale under the December 2016 EDA was registered pursuant to a registration statement on Form S-3 filed on May 23, 2016. During 2016, we issued 1,487,100 shares of common stock under the December 2016 EDA, receiving net proceeds of $78.7 million. As of December 31, 2016, we have $670.5 million remaining under the December 2016 EDA. In connection with the December 2016 EDA we terminated the May 2016 EDA.

On January 26, 2017, we 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. We intend to use the net proceeds from this public offering to fund a portion of the $565 million initial purchase price of the Permian Acquisition.

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:

	Natural Gas $/MMBtu (1)				Illustrative Targa NGL $/gal (2)				Crude Oil $/Bbl (3)
2016
4th Quarter	$	2.98			$	0.53			$	47.73
3rd Quarter		2.81				0.45				44.94
2nd Quarter		1.95				0.46				45.59
1st Quarter		2.09				0.36				33.45
2016 Average		2.46				0.45				42.93
2015
4th Quarter	$	2.27			$	0.40			$	42.17
3rd Quarter		2.77				0.39				46.44
2nd Quarter		2.65				0.44				57.96
1st Quarter		2.99				0.46				48.57
2015 Average		2.67				0.42				48.79
2014
4th Quarter	$	4.04			$	0.63			$	73.12
3rd Quarter		4.07				0.84				97.21
2nd Quarter		4.68				0.88				102.98
1st Quarter		4.95				0.98				98.62
2014 Average		4.43				0.83				92.99

(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. Quantitative and Qualitative Disclosures About Market Risk— Commodity Price Risk.”

Operating Expenses

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

General and Administrative Expenses

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

General Trends and Outlook

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

Demand for Our Services

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related activity levels from our customers. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. In our Gathering and Processing areas of operation, producers have reduced and may continue to reduce their drilling activity to varying degrees, which may lead to lower oil, condensate, NGL and natural gas volume growth in the near term and reduced demand for our services. Producer activity generates demand in our Downstream Business for fractionation and other fee-based services, which may decrease in the near term. As prices have declined, demand for our international export, storage and terminaling services has remained relatively constant, as demand for these services is based on a number of domestic and international factors.

Commodity Prices

There has been and we believe there will continue to be significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. In addition, the volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems. Notably, 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 in the first half of 2016, but have since experienced some recovery. See “Item 1A. Risk Factors – Our cash flow is affected by supply and demand for natural gas and NGL products and by natural gas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.”

Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, and where the spread between NGL prices and natural gas prices widens primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing and the supply of and market demand for natural gas, NGLs and condensate. Pricing and supply are beyond our control and have been volatile. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. Due to the recent volatility in commodity prices, we are uncertain of what pricing and market demand for oil, condensate, NGLs and natural gas will be throughout 2017, and, as a result, demand for the services that we provide may decrease. Across our operations and particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. The significant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Volatile Capital Markets

We continuously consider and enter into discussions regarding potential acquisitions and growth projects, and identify appropriate private and public capital sources for funding potential acquisitions and growth projects. Any limitations on our access to capital may impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets may be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders. These factors may impair our ability to execute our acquisition and growth strategy.

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.

Increased Regulation

Additional regulation in various areas has the potential to materially impact our operations and financial condition. For example, increased regulation of hydraulic fracturing used by producers and increased GHG emission regulations may cause reductions in supplies of natural gas, NGLs, and crude oil from producers. Please read “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” and “The adoption and implementation of climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the products and services we provide” under Item 1A of this Form 10-K. Similarly, the forthcoming rules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less predictability in our results of operations.

How We Evaluate Our Operations

The following discussion of how we evaluate our operations reflects the impact of the February 17, 2016 closing of the TRC/TRP Merger. Our non-GAAP financial measures have been revised accordingly and prior year non-GAAP measures have been provided for comparative purposes.

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

Our profitability is also impacted by fee-based revenues. Our growth strategy, based on expansion of existing facilities as well as third-party acquisitions of businesses and assets, has increased the percentage of our revenues that are fee-based. Fixed fees for services such as fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities.

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

Throughput Volumes, Facility Efficiencies and Fuel Consumption

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

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

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

Operating Expenses

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

Capital Expenditures

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

Gross Margin

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

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

Logistics and Marketing segment gross margin consists primarily of

	•	service fee revenues (including the pass-through of energy costs included in fee rates),

	•	system product gains and losses, and

	•	NGL and natural gas sales less NGL and natural gas purchases, transportation costs and the net inventory change.

The gross margin impacts of cash flow hedge settlements are reported in Other.

Operating Margin

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

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

	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) available to TRC before: interest; income taxes; depreciation and amortization; impairment of goodwill; gains or losses on debt repurchases, redemptions, amendments, exchanges and early debt extinguishments and asset disposals; risk management activities related to derivative instruments including the cash impact of hedges acquired in the merger with APL (the “APL merger”); non-cash compensation on equity grants; transaction costs related to business acquisitions; the Splitter Agreement adjustment; net income attributable to TRP preferred limited partners; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.

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

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

Distributable Cash Flow

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

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

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

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

Our Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated, with 2015 and 2014 amounts presented for comparative purposes.

		2016					2015					2014
	(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin:
Net income (loss) attributable to TRC		$		(187.3	)		$		58.3			$		102.3
Net income (loss) attributable to noncontrolling interests				28.2					(209.7	)				320.7
Net income (loss)				(159.1	)				(151.4	)				423.0
Depreciation and amortization expenses				757.7					677.1					351.0
General and administrative expenses				187.2					161.7					148.0
Goodwill impairment				207.0					290.0					—
Interest expense, net				254.2					231.9					147.1
Income tax expense (benefit)				(100.6	)				39.6					68.0
(Gain) loss on sale or disposition of assets				6.1					(8.0	)				(4.8	)
(Gain) loss from financing activities				48.2					10.1					12.4
Other, net				13.6					30.0					(8.2	)
Operating margin				1,214.3					1,281.0					1,136.5
Operating expenses				553.7					540.0					487.3
Gross margin		$		1,768.0			$		1,821.0			$		1,623.8

	2016					2015					2014
	(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA and Distributable Cash Flow
Net income (loss) attributable to TRC	$		(187.3	)		$		58.3			$		102.3
Impact of TRC/TRP Merger on NCI			(3.8	)				(180.1	)				283.3
Income attributable to TRP preferred limited partners			11.3					2.4					—
Interest expense, net			254.2					231.9					147.1
Income tax expense (benefit)			(100.6	)				39.6					68.0
Depreciation and amortization expenses			757.7					677.1					351.0
Goodwill impairment			207.0					290.0					—
(Gain) loss on sale or disposition of assets			6.1					(8.0	)				(4.8	)
(Gain) loss from financing activities			48.2					10.1					12.4
(Earnings) loss from unconsolidated affiliates (1)			14.3					2.5					(18.0	)
Distributions from unconsolidated affiliates and preferred partner interests, net (1)			17.5					21.1					18.0
Change in contingent consideration			(0.4	)				(1.2	)				—
Compensation on equity grants			29.7					25.0					14.3
Transaction costs related to business acquisitions (1)			—					27.3					—
Splitter Agreement (2)			10.8					—					—
Risk management activities			25.2					64.8					4.7
Other			—					0.6					—
Noncontrolling interests adjustments (3)			(25.0	)				(69.7	)				(14.0	)
TRC Adjusted EBITDA	$		1,064.9			$		1,191.7			$		964.3
Distributions to TRP preferred limited partners			(11.3	)				(2.4	)				—
Cash received from payments under Splitter Agreement (2)			43.0					—					—
Splitter Agreement (2)			(10.8	)				—					—
Interest expenses on debt obligations (4)			(263.8	)				(253.3	)				(135.5	)
Cash tax (expense) benefit (5)			20.9					(15.0	)				(72.4	)
Maintenance capital expenditures			(85.7	)				(97.9	)				(79.1	)
Noncontrolling interests adjustments of maintenance capex			5.2					7.2				7.8
Distributable Cash Flow	$		762.4			$		830.3			$		685.1

(1)	The definition of Adjusted EBITDA was revised in 2015 to exclude earnings from unconsolidated investments net of distribution and transactions costs related to business acquisitions.

(2)	In Adjusted EBITDA, the amount reflects the annual cash payment received for the Splitter Agreement recognized over the four quarters following receipt. In distributable cash flow, the amounts reflect the annual cash payment in the period received less the amount recognized in Adjusted EBITDA.

(3)	Noncontrolling interest portion of depreciation and amortization expenses.

(4)	Excludes amortization of interest expense.

(5)	Includes an adjustment, reflecting the benefit from net operating loss carryback to 2015 and 2014, which is recognized over a period of six quarters beginning in Q3 2016.

Consolidated Results of Operations

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

		Year Ended December 31,
		2016					2015					2014						2016 vs. 2015									2015 vs. 2014
	(in millions, except operating statistics and price amounts)
Revenues
Sales of commodities	$		5,626.8			$		5,465.4			$		7,595.2				$		161.4				3	%		$		(2,129.8	)			(28	%)
Fees from midstream services			1,064.1					1,193.2					1,021.3						(129.1	)			(11	%)				171.9				17	%
Total revenues			6,690.9					6,658.6					8,616.5						32.3				%					(1,957.9	)			(23	%)
Product purchases			4,922.9					4,837.6					6,992.7						85.3				2	%				(2,155.1	)			(31	%)
Gross margin (1)			1,768.0					1,821.0					1,623.8						(53.0	)			(3	%)				197.2				12	%
Operating expenses			553.7					540.0					487.3						13.7				3	%				52.7				11	%
Operating margin (1)			1,214.3					1,281.0					1,136.5						(66.7	)			(5	%)				144.5				13	%
Depreciation and amortization expenses			757.7					677.1					351.0						80.6				12	%				326.1				93	%
General and administrative expenses			187.2					161.7					148.0						25.5				16	%				13.7				9	%
Goodwill impairment			207.0					290.0					—						(83.0	)			(29	%)				290.0				—
Other operating (income) expense			6.6					(7.1	)				(3.0	)					13.7				193	%				(4.1	)			137	%
Income from operations			55.8					159.3					640.5						(103.5	)			(65	%)				(481.2	)			(75	%)
Interest expense, net			(254.2	)				(231.9	)				(147.1	)					(22.3	)			10	%				(84.8	)			58	%
Equity earnings (loss)			(14.3	)				(2.5	)				18.0						(11.8	)		NM						(20.5	)			(114	%)
Gain (loss) from financing activities			(48.2	)				(10.1	)				(12.4	)					(38.1	)		NM						2.3				19	%
Other income (expense)			1.2					(26.6	)				(8.0	)					27.8				105	%				(18.6	)			233	%
Income tax (expense) benefit			100.6					(39.6	)				(68.0	)					140.2			NM						28.4				42	%
Net income (loss)			(159.1	)				(151.4	)				423.0						(7.7	)			5	%				(574.4	)			(136	%)
Less: Net income (loss) attributable to noncontrolling interests			28.2					(209.7	)				320.7						237.9				113	%				(530.4	)			(165	%)
Net income (loss) attributable to Targa Resources Corp.			(187.3	)				58.3					102.3						(245.6	)		NM						(44.0	)			(43	%)
Dividends on Series A preferred stock			72.6					—					—						72.6				—					—				—
Deemed dividends on Series A preferred stock			18.2					—					—						18.2				—					—				—
Net income (loss) attributable to common shareholders	$		(278.1	)		$		58.3			$		102.3				$		(336.4	)		NM				$		(44.0	)			(43	%)
Financial and operating data:
Financial data:
Adjusted EBITDA (1)	$		1,064.9			$		1,191.7			$		964.3				$		(126.8	)			(11	%)		$		227.4				24	%
Distributable cash flow (1)			762.4					830.3					685.1						(67.9	)			(8	%)				145.2				21	%
Capital expenditures			592.1					777.2					747.8						(185.1	)			(24	%)				29.4				4	%
Business acquisitions			—					5,024.2					—						(5,024.2	)			(100	%)				5,024.2				—
Operating statistics:
Crude oil gathered, MBbl/d			105.2					106.3					93.5						(1.1	)			(1	%)				12.8				14	%
Plant natural gas inlet, MMcf/d (2) (3) (4)			3,411.9					3,241.3					2,109.5						170.6				5	%				1,131.8				54	%
Gross NGL production, MBbl/d (4)			305.4					265.5					153.0						39.9				15	%				112.5				74	%
Export volumes, MBbl/d (5)			181.4					183.0					176.9						(1.6	)			(1	%)				6.1				3	%
Natural gas sales, BBtu/d (3) (4) (6)			1,962.9					1,770.7					902.3						192.2				11	%				868.4				96	%
NGL sales, MBbl/d (4) (6)			526.1					517.0					419.5						9.1				2	%				97.5				23	%
Condensate sales, MBbl/d (4)			10.1					9.3					4.4						0.8				9	%				4.9				111	%

(1)	Gross margin, operating margin, adjusted EBITDA, and distributable cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.”

(2)	Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than in Badlands, where it represents total wellhead gathered volume.

(3)	Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(4)	These volume statistics are presented with the numerator as the total volume sold during the year and the denominator as the number of calendar days during the year.

(5)	Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.

(6)	Includes the impact of intersegment eliminations.

NM	Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

2016 Compared to 2015

The increase in commodity sales was primarily due to the favorable impact of the inclusion of two additional months of TPL’s operations during 2016 ($270.1 million), partially offset by lower commodity prices ($53.7 million) and the impact of hedge settlements ($42.5 million). Additionally, fee-based and other revenues decreased primarily due to lower fractionation and export fees, partially offset by the impact of an additional two months of TPL’s fee revenue in 2016 ($40.9 million).

The increase in product purchases was primarily due to the inclusion of two additional months of operations from TPL in 2016 ($137.5 million), partially offset by the impact of the lower commodity prices.

The lower operating margin and gross margin in 2016 reflects decreased segment margin results for Logistics and Marketing, partially offset by increased Gathering and Processing segment margins. Operating expenses increased slightly compared to 2015 due to the inclusion of TPL’s operations for an additional two months in 2016, offset by a continued focused cost reduction effort throughout our operating areas. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

The increase in depreciation and amortization expenses reflects an additional two months of TPL operations in 2016, growth investments from other system expansions including CBF Train 5, the Buffalo Plant, compressor stations and pipelines, and higher planned amortization of the Badlands intangible assets. Partially offsetting these factors was an additional $32.6 million charge to depreciation in 2015 to reflect an impairment of certain gas processing facilities and associated gathering systems due to market conditions and processing spreads in Louisiana.

General and administrative expenses, which include TPL operations for an additional two months in 2016, increased primarily due to higher compensation and benefits, partially offset by lower property insurance premiums.

We recognized impairments of goodwill totaling $207.0 million during 2016, as compared with the $290.0 million provisional impairment of goodwill recorded during the fourth quarter of 2015. Goodwill impairment recorded in 2016 includes $24.0 million recorded in the first quarter to finalize the 2015 provisional charge, as well as an additional $183.0 million associated with our annual impairment evaluation in the fourth quarter of 2016. These impairment charges relate to goodwill acquired in the 2015 Atlas mergers.

Other operating (income) expense in 2016 includes the loss on decommissioning two storage wells at our Hattiesburg facility and an acid gas injection well at our Versado facility, whereas in 2015 we reported a net gain on sales of assets.

Net interest expense increased primarily due to lower non-cash interest income related to the mandatorily redeemable preferred interests liability that is revalued quarterly at the estimated redemption value as of the reporting date. The estimated redemption value of the mandatorily redeemable preferred interests decreased in 2016 by a lesser amount than in 2015. Other factors included lower capitalized interest due to decreased capital expenditures in 2016, partially offset by the impact of lower average outstanding borrowings during 2016.

The decrease in equity earnings (loss) was due to lower operating results from GCF and the inclusion of an additional two months of equity losses from the T2 Joint Ventures in 2016.

During 2016, we recorded a $48.2 million loss from financing activities that included the tender of $1,138.3 million of Partnership Senior Notes, the repurchase of $559.2 million of Partnership Senior Notes in open market purchases, and the redemption of $146.2 million of Partnership Senior Notes. In 2015, we incurred a net loss from financing activities of $10.1 million from the partial repayments of the TRC senior secured term loan and the repurchase of Partnership Senior Notes.

Other income (expense) in 2015 was primarily attributable to non-recurring transaction costs related to the Atlas mergers.

The change in income tax (expense) benefit was primarily due to the decrease in income (loss) before income taxes and the impact of the TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016. Income attributable to noncontrolling interests is not subject to income taxes in our financial statements. Therefore, during most of 2016, we recorded income taxes on the majority of the pre-tax loss generated by TRP due to absence of the large noncontrolling interest in TRP.

Despite similar amounts of net losses in 2016 and 2015, net income (loss) attributable to noncontrolling interests was significantly lower for 2016 due to the February 2016 TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016. The impact of the TRP non-controlling common interest buy-in was most pronounced during the fourth quarter of both years which included significant losses as a result of our annual goodwill impairment evaluations. The noncontrolling interest bore approximately 89% of the fourth quarter impairment loss in 2015 and 0% in 2016. This reduction was partially offset by the impact of a full year of distributions in 2016 for the TRP's Preferred Units issued in October 2015.

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

2015 Compared to 2014

Revenues from commodity sales declined as the effect of significantly lower commodity prices ($6,318.1 million) exceeded the favorable impacts of inclusion of ten months of operations of TPL ($1,261.7 million), other volume increases ($2,934.0 million), and favorable hedge settlements ($84.2 million). Fee-based and other revenues increased due to the inclusion of TPL’s fee revenue ($177.1 million), which were partially offset by lower export fees.

Offsetting lower commodity revenues was a commensurate reduction in product purchases due to significantly lower commodity costs ($3,235.3 million). 2015 also included product purchases related to TPL’s operations ($1,106.1 million).

The higher operating margin and gross margin in 2015 was attributable to inclusion of TPL operations, increased throughput related to other system expansions in our Gathering and Processing segment, recognition of a renegotiated commercial contract and increased terminaling and storage fees, partially offset by lower fractionation and export margin in our Logistics and Marketing segment. Higher operating expenses were due to the inclusion of TPL’s operations ($101.6 million), which more than offset the cost savings generated throughout our other operating areas ($30.0 million). See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

The increase in depreciation and amortization expenses reflects the impact of TPL, the planned increased amortization of the Badlands intangible assets and growth investments placed in service after 2014, including the international export expansion project, continuing development at Badlands and other system expansions. During 2015, we recorded an additional $32.6 million charge to depreciation to reflect an impairment of certain gas processing facilities and associated gathering systems in the Gathering and Processing segment as a result of reduced forecasted processing volumes due to current market conditions and processing spreads in Louisiana.

Higher general and administrative expense was due to the inclusion of TPL general and administrative costs ($32.1 million), which was partially offset by other general and administrative reductions ($18.1 million), primarily from lower compensation and related costs.

The increase in other operating gains during 2015 was primarily related to higher gains on sales of assets.

During 2015, we recognized a provisional loss of $290.0 million associated with the provisional impairment of goodwill in our Gathering and Processing segment.

The increase in net interest expense primarily reflects higher borrowings attributable to the Atlas mergers and lower capitalized interest associated with major capital projects compared to 2014. These factors were partially offset by the change in the non-cash redemption value ($30.6 million) of mandatorily redeemable preferred interests in the WestTX and WestOK joint ventures acquired in the Atlas mergers.

During 2015, the loss on financing activities was due primarily to the repayment of $270.0 million of the TRC Term Loan, which resulted in a write-off of $5.7 million of unamortized discounts and $7.2 million of debt issuance costs associated with this repayment. These charges were partially offset by the Partnership’s $3.6 million gain on repurchases of debt, partially offset by $0.7 million of expenses incurred for our exchange offer for certain TPL senior notes. In 2014, the loss on financing activities was due to the Partnership’s redemption of its 7⅞% senior notes.

Net income attributable to noncontrolling interests decreased due to lower earnings in 2015 at our joint ventures: Cedar Bayou Fractionators, VESCO, and Versado. The inclusion of noncontrolling interest from TPL’s Centrahoma joint venture, which included its portion of the SouthOK goodwill impairment, also decreased the net income attributable to noncontrolling interests.

Our effective tax rate has not changed period over period. The decrease in 2015 current income tax expense was primarily due to the reduction of taxable income as a result of increased depreciation and amortization deductions from the Atlas mergers, including the tax amortization of the Special GP interest. The increase in deferred taxes was primarily attributable to book/tax differences in depreciation and amortization of Atlas fixed assets.

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

	Gathering and Processing					Logistics and Marketing					Other					TRC Non-Partnership					Consolidated Operating Margin
	(In millions)
2016	$		577.1			$		574.4			$		62.9			$		(0.1	)		$		1,214.3
2015			515.1					681.7					84.2					-					1,281.0
2014			449.9					694.7					(8.0	)				(0.1	)				1,136.5

Gathering and Processing Segment

	Year Ended December 31,
	2016					2015					2014						2016 vs. 2015								2015 vs. 2014
Gross margin	$		903.6			$		830.1			$		686.9			$		73.5				9	%		$		143.2				21	%
Operating expenses			326.5					315.0					237.0					11.5				4	%				78.0				33	%
Operating margin	$		577.1			$		515.1			$		449.9			$		62.0				12	%		$		65.2				14	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
SAOU (4)			259.1					234.0					193.1					25.1				11	%				40.9				21	%
WestTX (5)			500.7					374.0					—					126.7				34	%				374.0				—
Sand Hills (4)			139.5					163.0					165.1					(23.5	)			(14	%)				(2.1	)			(1	%)
Versado			181.5					183.2					169.6					(1.7	)			(1	%)				13.6				8	%
Total Permian			1,080.8					954.2					527.8					126.6									426.4
SouthTX (5)			216.4					120.0					—					96.4				80	%				120.0				—
North Texas			317.3					347.6					354.5					(30.3	)			(9	%)				(6.9	)			(2	%)
SouthOK (5)			462.1					401.5					—					60.6				15	%				401.5				—
WestOK (5)			444.9					471.7					—					(26.8	)			(6	%)				471.7				—
Total Central			1,440.7					1,340.8					354.5					99.9									986.3
Badlands (6)			52.1					49.2					38.9					2.9				6	%				10.3				26	%
Total Field			2,573.6					2,344.2					921.2					229.4									1,423.0
Coastal			838.4					897.0					1,188.4					(58.6	)			(7	%)				(291.4	)			(25	%)
Total			3,412.0					3,241.2					2,109.6					170.8				5	%				1,131.6				54	%
Gross NGL production, MBbl/d (3)
SAOU (4)			31.8					27.3					25.2					4.5				16	%				2.1				8	%
WestTX (5)			62.7					43.4					—					19.3				44	%				43.4				—
Sand Hills (4)			14.7					17.4					18.0					(2.7	)			(16	%)				(0.6	)			(3	%)
Versado			21.7					23.4					21.4					(1.7	)			(7	%)				2.0				9	%
Total Permian			130.9					111.5					64.6					19.4									46.9
SouthTX (5)			23.8					13.8					—					10.0				72	%				13.8				—
North Texas			35.8					39.6					37.8					(3.8	)			(10	%)				1.8				5	%
SouthOK (5)			39.4					28.1					—					11.3				40	%				28.1				—
WestOK (5)			27.1					23.8					—					3.3				14	%				23.8				—
Total Central			126.1					105.3					37.8					20.8									67.5
Badlands			7.3					6.8					3.5					0.5				7	%				3.3				94	%
Total Field			264.3					223.6					105.9					40.7									117.7
Coastal			41.2					41.8					47.1					(0.6	)			(1	%)				(5.3	)			(11	%)
Total			305.5					265.4					153.0					40.1				15	%				112.4				73	%
Crude oil gathered, MBbl/d			105.2					106.3					93.5					(1.1	)			(1	%)				12.8				14	%
Natural gas sales, BBtu/d (3)			1,623.6					1,577.9					727.0					45.7				3	%				850.9				117	%
NGL sales, MBbl/d			241.3					208.3					120.9					33.0				16	%				87.4				72	%
Condensate sales, MBbl/d			9.9					9.1					4.3					0.8				9	%				4.8				112	%
Average realized prices (7):
Natural gas, $/MMBtu			2.14					2.38					4.19					(0.24	)			(10	%)				(1.81	)			(43	%)
NGL, $/gal			0.36					0.35					0.75					0.01				3	%				(0.40	)			(53	%)
Condensate, $/Bbl			36.20					41.86					83.55					(5.66	)			(14	%)				(41.69	)			(50	%)

(1)	Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year, including the volumes related to plants acquired in the APL merger.

(2)	Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(3)	Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(4)	Includes wellhead gathered volumes moved from Sand Hills via pipeline to SAOU for processing.

(5)	Operations acquired as part of the APL merger effective February 27, 2015.

(6)	Badlands natural gas inlet represents the total wellhead gathered volume.

(7)	Average realized prices exclude the impact of hedging activities presented in Other.

2016 Compared to 2015

The increase in gross margin was primarily due to the inclusion of the TPL volumes for all of 2016 and an increase in NGL prices partially offset by lower natural gas and condensate prices and lower inlet volumes in WestOK and on certain of our other systems. The plant inlet volume increase in SAOU was more than offset by reduced producer activity and volumes at Sand Hills (which also had operational issues), Versado and North Texas. Badlands natural gas volumes increased due to system expansions while crude oil volumes were essentially flat. Coastal plant inlet volumes decreased due to current market conditions and the decline of off-system volumes partially offset by additional higher GPM volumes.

Excluding the impact of including operating expenses for TPL for an additional two months in 2016 and system expansions, operating expenses for most areas were lower due to a continued focused cost reduction effort.

2015 Compared to 2014

The increase in gross margin was primarily due to the inclusion of the TPL volumes along with other volume increases partially offset by significantly lower commodity prices. The increases in plant inlet volumes at SAOU, Sand Hills (see footnote (4) above) and Versado were driven by system expansions and by increased producer activity which increased available supply across our areas of operation partially offset by reduced producer activity and volumes in North Texas. 2015 benefited from a full year operations of the Longhorn plant in North Texas, the High Plains plant in SAOU and the Little Missouri 3 plant in Badlands. Badlands crude oil and natural gas volumes increased significantly due to plant and system expansion and increased producer activity. Coastal plant inlet volumes decreased primarily due to current market conditions and the decline of off-system volumes partially offset by additional higher average GPM volumes.

Excluding the addition of operating expenses for TPL, operating expenses for other areas were significantly lower, even with system expansions, primarily due to focused cost reduction efforts.

Gross Operating Statistics Compared to Actual Reported

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

		Year Ended December 31, 2016
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)		Gross Volume (3)				Ownership %				Net Volume (3)				Actual Reported
SAOU (4)			259.1				100	%			259.1				259.1
WestTX (5)(6)			687.8				73	%			500.7				500.7
Sand Hills (4)			139.5				100	%			139.5				139.5
Versado (7)			181.5				100	%			181.5				181.5
Total Permian			1,267.9								1,080.8				1,080.8
SouthTX			216.4			Varies (8)					205.6				216.4
North Texas			317.3				100	%			317.3				317.3
SouthOK			462.1			Varies (9)					382.0				462.1
WestOK			444.9				100	%			444.9				444.9
Total Central			1,440.7								1,349.8				1,440.7
Badlands (10)			52.1				100	%			52.1				52.1
Total Field			2,760.7								2,482.7				2,573.6
Gross NGL production, MBbl/d (2)
SAOU (4)			31.8				100	%			31.8				31.8
WestTX (5)(6)			86.1				73	%			62.7				62.7
Sand Hills (4)			14.7				100	%			14.7				14.7
Versado (7)			21.7				100	%			21.7				21.7
Total Permian			154.3								130.9				130.9
SouthTX			23.8			Varies (8)					22.8				23.8
North Texas			35.8				100	%			35.8				35.8
SouthOK			39.4			Varies (9)					32.6				39.4
WestOK			27.1				100	%			27.1				27.1
Total Central			126.1								118.3				126.1
Badlands			7.3				100	%			7.3				7.3
Total Field			287.7								256.5				264.3

(1)	Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(2)	Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes.

(3)	For these volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year.

(4)	Includes wellhead gathered volumes moved from Sand Hills to SAOU for processing.

(5)	Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(6)	Includes the Buffalo Plant that commenced commercial operations in April 2016.

(7)	Versado is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. We held a 63% interest in Versado until October 31, 2016, when we acquired the remaining 37% interest.

(8)	SouthTX includes the Silver Oak II plant, of which TPL has owned a 90% interest since January 2016, and prior to which TPL owned a 100% interest. Silver Oak II is owned by a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(9)	SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(10)	Badlands natural gas inlet represents the total wellhead gathered volume.

		Year Ended December 31, 2015
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)		Gross Volume (3)				Ownership %				Net Volume (3)				Pro Forma (4)				Timing Adjustment (5)				Actual Reported
SAOU			234.0				100	%			234.0				234.0				-				234.0
WestTX (6)(7)			612.8				73	%			446.1				446.1				(72.1	)			374.0
Sand Hills			163.0				100	%			163.0				163.0				-				163.0
Versado (8)			183.2				63	%			115.4				183.2				-				183.2
SouthTX (6)			143.1				100	%			143.1				143.1				(23.1	)			120.0
North Texas			347.6				100	%			347.6				347.6				-				347.6
SouthOK (6)			478.9			Varies (9)					398.6				478.9				(77.4	)			401.5
WestOK (6)			562.6				100	%			562.6				562.6				(90.9	)			471.7
Badlands (10)			49.2				100	%			49.2				49.2				-				49.2
Total Field			2,774.4								2,459.6				2,607.7				(263.5	)			2,344.2
Gross NGL production, MBbl/d (2)
SAOU			27.3				100	%			27.3				27.3				-				27.3
WestTX (6)(7)			71.1				73	%			51.8				51.8				(8.4	)			43.4
Sand Hills			17.4				100	%			17.4				17.4				-				17.4
Versado			23.4				63	%			14.7				23.4				-				23.4
SouthTX (6)			16.5				100	%			16.5				16.5				(2.7	)			13.8
North Texas			39.6				100	%			39.6				39.6				-				39.6
SouthOK (6)			33.5			Varies (9)					29.1				33.5				(5.4	)			28.1
WestOK (6)			28.4				100	%			28.4				28.4				(4.6	)			23.8
Badlands			6.8				100	%			6.8				6.8				-				6.8
Total Field			264.0								231.6				244.7				(21.1	)			223.6

(1)	Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(2)	Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes.

(3)	For these volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year, other than for the volumes related to the APL merger, for which the denominator is 306 days.

(4)	Pro forma statistics represents volumes per day while owned by us.

(5)	Timing adjustment made to the pro forma statistics to adjust for the actual reported statistics based on the full period.

(6)	Operations acquired as part of the APL merger effective February 27, 2015.

(7)	Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(8)	Versado is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. We held a 63% interest in Versado until October 31, 2016, when we acquired the remaining 37% interest.

(9)	SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(10)	Badlands natural gas inlet represents the total wellhead gathered volume.

Logistics and Marketing Segment

		Year Ended December 31,
		2016					2015					2014					2016 vs. 2015									2015 vs. 2014
	(in millions)
Gross margin		$		801.8			$		907.5			$		945.6			$		(105.7	)			(12	%)		$		(38.1	)			(4	%)
Operating expenses				227.4					225.8					250.9					1.6				1	%				(25.1	)			(10	%)
Operating margin		$		574.4			$		681.7			$		694.7			$		(107.3	)			(16	%)		$		(13.0	)			(2	%)
Operating statistics MBbl/d (1):
Fractionation volumes (2)(3)				309.3					342.7					350.0					(33.4	)			(10	%)				(7.3	)			(2	%)
LSNG treating volumes (2)				24.9					22.4					23.4					2.5				11	%				(1.0	)			(4	%)
Benzene treating volumes (2)				22.1					22.4					23.4					(0.3	)			(1	%)				(1.0	)			(4	%)
Export volumes, MBbl/d (4)				181.4					183.0					176.9					(1.6	)			(1	%)				6.1				3	%
NGL sales, MBbl/d				477.5					422.1					413.5					55.4				13	%				8.6				2	%
Average realized prices:
NGL realized price, $/gal		$		0.49			$		0.46			$	0.94				$		0.03				7	%		$		(0.48	)			(51	%)

(1)	Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year.

(2)	Fractionation and treating contracts include pricing terms composed of base fees and fuel and power components which vary with the cost of energy. As such, the Logistics and Marketing segment results include effects of variable energy costs that impact both gross margin and operating expenses.

(3)	Fractionation volumes reflect those volumes delivered and settled under fractionation contracts.

(4)	Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.

2016 Compared to 2015

Logistics and Marketing gross margin decreased primarily due to lower LPG export margin and the realization in 2015 of contract renegotiation fees related to our crude oil and condensate splitter project. Gross margin also decreased due to lower fractionation margin and lower terminaling and storage throughput, partially offset by higher NGL marketing gains. LPG export margin decreased due to lower fees. Fractionation margin decreased primarily due to lower supply volume and lower system product gains, partially offset by higher fees. Fractionation margin was partially impacted by the variable effects of fuel and power which are largely reflected in operating expenses (see footnote (2) above).

Operating expenses were relatively flat. Higher compensation and benefits and higher ad valorem taxes associated with the start-up of CBF Train 5 were largely offset by lower fuel and power, and lower maintenance expense resulting from continued focused cost reductions.

2015 Compared to 2014

Logistics and Marketing gross margin decreased primarily due to lower LPG export and fractionation margins, a lower price environment, lower NGL marketing activities, and the expiration and recognition of a contract settlement in 2014. The lower gross margin was partially offset by the recognition in 2015 of the renegotiated commercial arrangements related to our crude oil and condensate splitter project and increased terminaling and storage throughput.

Fractionation gross margin was lower primarily due to the variable effects of fuel and power, which are largely reflected in lower operating expenses (see footnote (2) above), lower system product gains, and a decrease in supply volume.

Operating expenses decreased primarily due to lower fuel and power expense, and lower terminal expense, partially offset by higher maintenance.

Other

		Year Ended December 31,
		2016				2015				2014				2016 vs. 2015				2015 vs. 2014
		(in millions)
Gross margin		$	62.9			$	84.2			$	(8.0	)		$	(21.3	)		$	92.2
Operating margin		$	62.9			$	84.2			$	(8.0	)		$	(21.3	)		$	92.2

Other contains the results (including any hedge ineffectiveness) of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash flow hedges. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow. We have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering and Processing Operations that result from percent of proceeds/liquids processing arrangements. Because we are essentially forward-selling a portion of our future plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

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

		2016												2015												2014
		(In millions, except volumetric data and price amounts)
		Volume Settled				Price Spread (1)				Gain (Loss)				Volume Settled				Price Spread (1)				Gain (Loss)				Volume Settled				Price Spread (1)				Gain (Loss)
Natural gas (BBtu)			44.7			$	0.79			$	35.2				34.2			$	1.08			$	37.0				21.9			$	(0.27	)		$	(5.9	)
NGL (MMgal)			31.9				0.21				6.8				28.4				0.77				22.0				26.2				0.14				3.6
Crude oil (MBbl)			1.1				17.14				19.5				0.9				31.81				29.3				0.9				(1.07	)			(1.0	)
Non-hedge accounting (2)											2.3												(5.0	)											(4.8	)
Ineffectiveness (3)											(0.9	)											0.9												0.1
										$	62.9											$	84.2											$	(8.0	)

(1)	The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

(2)	Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes.

(3)	Ineffectiveness primarily relates to certain crude hedging contracts and certain acquired hedges of APL that do not qualify for hedge accounting.

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. The remainder of the novated contracts will settle by the end of 2017. 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.

Our Liquidity and Capital Resources

As of December 31, 2016, we had $73.5 million of “Cash and cash equivalents,” on our Consolidated Balance Sheet. We believe our cash position, remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”), and our cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

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

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

Historically, dividends have been funded by the cash distributions we received from the Partnership. In connection with the TRC/TRP Merger, TRC acquired all of the outstanding TRP common units that TRC and its subsidiaries did not already own. As a result, we are entitled to the entirety of distributions made by the Partnership on its equity interests, other than those made to the TRP Preferred Unitholders. The actual amount we declare as dividends continues to depend on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.

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

On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRC Revolver, the TRP Revolver, and the Securitization Facility, and access to debt and equity capital markets.

For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

Short-term Liquidity

Our short-term liquidity on a consolidated basis as of February 10, 2017, was:

		February 10, 2017
		(In millions)
		TRC				TRP				Consolidated Total
Cash on hand		$	223.4			$	169.7			$	393.1
Total availability under the TRC Revolver			670.0				—				670.0
Total availability under the TRP Revolver			—				1,600.0				1,600.0
Total availability under the Securitization Facility			—				275.0				275.0
			893.4				2,044.7				2,938.1
Less: Outstanding borrowings under the TRC Revolver			—				—				—
Outstanding borrowings under the TRP Revolver			—				(180.0	)			(180.0	)
Outstanding borrowings under the Securitization Facility			—				(275.0	)			(275.0	)
Outstanding letters of credit under the TRP Revolver			—				(13.2	)			(13.2	)
Total liquidity		$	893.4			$	1,576.5			$	2,469.9

Other potential capital resources associated with our existing arrangements include:

	•	Our right to request an additional $200 million in commitment increases under the TRC Revolver, subject to the terms therein. The TRC Revolver matures on February 27, 2020.

	•	Our right to request an additional $200 million in commitment increases under the TRC Term Loan, subject to the terms therein. The Term Loan matures on February 27, 2022.

	•	Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein. The TRP Revolver matures on October 7, 2020.

	•	We may elect to pay dividends to Series A Preferred shareholders for any quarter with a paid-in-kind election (“PIK”) through December 31, 2017. Under the PIK election, unpaid dividends would be added to the liquidation preference and a commensurate amount of Series A and Series B Warrants would be issued.

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

Working Capital

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable that are tied to commodity sales and purchases are relatively balanced, with receivables from NGL customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (1) our cash position; (2) liquids inventory levels and valuation, which we closely manage; (3) changes in the fair value of the current portion of derivative contracts; and (4) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth projects.

Our working capital, exclusive of current debt obligations, decreased $150.2 million. The major item contributing to this decrease was a decrease in our net risk management working capital position due to changes in the forward prices of commodities. The remaining working capital decrease reflects lower cash balances and higher commodity purchase accruals offset by higher commodity receivables and an income tax receivable representing the expected carryback of current year net operating losses to recover taxes paid in 2015 and 2014. The increase of $55.7 million in current debt obligations was due to increased receivables available for the Securitization Facility.

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

Long-term Financing

Our long-term financing consists of common stock, common warrants, preferred stock and long-term debt obligations. In 2016, through equity distribution agreements, we issued and sold through our sales agents 12,561,366 shares of common stock and received net proceeds of $572.7 million. As of December 31, 2016, we have $670.5 million remaining under our December 2016 equity distribution agreement.

In March 2016, through a private placement, we issued 965,100 shares of Series A Preferred Stock (the “Series A Preferred”) with detachable warrants for $1,030 per share and received gross proceeds of $994.1 million. The Series A Preferred have a liquidation value of $1,000 per share and bear a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter. We may elect to pay dividends for any quarter with a paid-in-kind election (“PIK”) through December 31, 2017. Under the PIK election, unpaid dividends would be added to the liquidation preference and a commensurate amount of warrants would be issued. The Series A Preferred have no mandatory redemption date, but are redeemable at our election in year six for a 10% premium to the liquidation preference and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred are not redeemed by the end of year twelve, the investors have the right to convert the Series A Preferred into TRC common stock at an exercise price of $20.77. If the investors do not elect to convert their Series A Preferred into TRC common stock, we have a right after year twelve to force conversion, but only if the volume weighted average price of our common stock for the ten preceding trading days is greater than 120% of the conversion price. In 2016, 19,983,843 warrants were exercised by their holders and net settled by us for 11,336,856 shares of common stock. As of December 31, 2016, 99,888 warrants remain outstanding.

From time to time, we issue long-term debt securities, which we refer to as senior notes. All of our senior notes issued to date, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% plus accrued interest to the redemption date plus a make-whole premium. As of December 31, 2016 and 2015, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $4,641.8 million and $5,780.4 million, respectively.

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

The majority of our consolidated long-term debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRC Revolver, the TRC Term Loan and the TRP Revolver. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of December 31, 2016, we do not have any interest rate hedges.

To date, our and our subsidiaries’ debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt-related transactions in 2016, see Note 10 “Debt Obligations” to our consolidated financial statements. For information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

Compliance with Debt Covenants

As of December 31, 2016, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Cash Flow

Cash Flows from Operating Activities

The Consolidated Statements of Cash Flows included in our historical consolidated financial statements employs the traditional indirect method of presenting cash flows from operating activities. Under the indirect method, net cash provided by operating activities is derived by adjusting our net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct method in which the actual cash receipts and outlays comprising cash flow are presented.

The following table displays our operating cash flows using the direct method as a supplement to the presentation in our consolidated financial statements:

		2016				2015				2014				2016 vs. 2015				2015 vs. 2014
		(In millions)
Cash flows from operating activities:
Cash received from customers		$	6,544.4			$	6,829.1			$	8,769.4			$	(284.7	)		$	(1,940.3	)
Cash received from (paid to) derivative counterparties			55.3				140.9				(4.9	)			(85.6	)			145.8
Cash distributions from equity investments (1)			4.1				13.8				18.0				(9.7	)			(4.2	)
Cash outlays for:
Product purchases			4,796.3				5,034.5				7,268.5				(238.2	)			(2,234.0	)
Operating expenses			568.2				485.3				402.6				82.9				82.7
General and administrative expenses			133.5				175.4				134.5				(41.9	)			40.9
Interest paid, net of amounts capitalized (2)			282.0				223.0				133.8				59.0				89.2
Income taxes paid, net of refunds			(10.6	)			13.8				73.4				(24.4	)			(59.6	)
Other cash (receipts) payments			(3.0	)			17.1				7.9				(20.1	)			9.2
Net cash provided by operating activities		$	837.4			$	1,034.7			$	761.8			$	(197.3	)		$	272.9

(1)	Excludes $4.1 million, $1.2 million and $5.7 million included in investing activities for 2016, 2015 and 2014 related to distributions from GCF and the T2 Joint Ventures that exceeded cumulative equity earnings.

(2)	Net of capitalized interest paid of $8.3 million, $13.2 million and $16.1 million included in investing activities for 2016, 2015 and 2014.

Lower commodity prices were the primary contributor to decreased cash collections and payments for product purchases in 2016 compared to 2015. Derivative settlements remained an overall source of revenue during 2016, but at a lower amount as commodity price spreads between the prices paid to counterparties and the fixed prices we received on those derivative contracts were lower in 2016 in comparison to 2015. The higher interest payments in 2016 were primarily due to the timing of interest payments for new debt instruments entered into in 2015. The senior notes issued in 2015 had only one semi-annual, or no, interest payment made in 2015 as compared to a full year of interest payments made in 2016. Cash payments for general and administrative expenses were lower primarily due to a lower bonus payout and lower insurance premium payments. Other cash payments in 2016 were lower, mainly due to transaction expenses associated with the Atlas mergers in 2015.

Lower commodity prices were the primary contributor to decreased cash collections and payments for product purchases in 2015 compared to 2014. Derivatives were a net inflow in 2015 versus a net outflow in 2014 reflecting lower commodity prices paid to counterparties compared to the fixed price we received on those derivative contracts. Higher cash outlay for general and administrative expenses in 2015 versus 2014 were mainly due to the addition of general and administrative costs for TPL. Other cash payments during 2015 reflect transaction costs related to the Atlas mergers.

Cash Flows from Investing Activities

2016				2015				2014				2016 vs. 2015				2015 vs. 2014
(In millions)
$	(558.6	)		$	(2,399.6	)		$	(751.4	)		$	1,841.0			$	(1,648.2	)

Cash used in investing activities decreased in 2016 compared to 2015, primarily due to the $1,574.4 million outlay for the cash portion of the Atlas merger consideration in 2015. In addition, growth and maintenance capital expenditures decreased $255.1 million during 2016 reflecting the completion of major growth projects and cost control initiatives.

Net cash used in investing activities increased in 2015 compared to 2014 primarily due to the $1,574.4 million outlays for the cash portion of Atlas merger consideration along with a $55.0 million increase in capital project outlays that reflects higher payments of prior year capital project accruals and higher maintenance capital outlays.

Cash Flows from Financing Activities

	2016				2015				2014
Source of Financing Activities, net	(In millions)
Debt, including financing costs	$	(1,127.4	)		$	1,283.4			$	56.9
Equity offerings, net of financing costs		1,522.6				766.6				407.8
Dividends and distributions		(716.5	)			(682.2	)			(454.4	)
Other		(24.2	)			56.3				(6.4	)
Total	$	(345.5	)		$	1,424.1			$	3.9

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

We realized a net source of cash from financing activities in 2015, primarily due to the cash borrowings and equity offering associated with the Atlas mergers, offset by dividends and distributions. Net borrowings under the Partnership’s debt facilities increased, offset by payment to tender APL’s senior notes; issuance of our term loan and borrowings under our senior secured credit facility and proceeds from common stock offerings, offset by partial repayments of our term loan and our senior secured credit facility.

The 2014 financing activities primarily reflect cash inflows from the Partnership EDA common unit offerings offset by dividends and distributions.

Common Dividends

The following table details the dividends on common stock declared and/or paid by us for 2016:

Three Months Ended		Date Paid or To Be Paid		Total Common Dividends Declared				Amount of Common Dividends Paid or To Be Paid				Accrued Dividends (1)				Dividend Declared per Share of Common Stock
(In millions, except per share amounts)
2016
December 31, 2016		February 15, 2017	$		178.3		$		176.5		$		1.8		$		0.91000
September 30, 2016		November 15, 2016			166.4				164.6				1.8				0.91000
June 30, 2016		August 15, 2016			153.1				151.6				1.5				0.91000
March 31, 2016		May 16, 2016			147.8				146.1				1.7				0.91000

(1)	Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Preferred Dividends

In March 2016, through a private placement, we issued 965,100 shares of Series A Preferred with detachable warrants for $1,030 per share and received gross proceeds of $994.1 million. The Series A Preferred have a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter. The Company may, at the sole election of the Board of Directors, elect to pay dividends for any quarter with a PIK through December 31, 2017. Under the PIK election, unpaid dividends would be added to the liquidation preference and a commensurate amount of warrants would be issued. We have not made an election to PIK through December 31, 2016.

Cash dividends of $49.7 million were paid to holders of the Series A Preferred during 2016. As of December 31, 2016, cash dividends accrued for our Series A Preferred were $22.9 million, which were paid on February 14, 2017.

Capital Requirements

Our capital requirements relate to capital expenditures, which are classified as expansion expenditures including business acquisitions and maintenance expenditures. Expansion capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of

businesses or assets. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

		2016				2015				2014
		(In millions)
Capital expenditures:
Consideration for business acquisitions		$	—			$	5,024.2			$	—
Non-cash value of acquisition (1)			—				(3,449.8	)			—
Business acquisitions, net of cash acquired			—				1,574.4				—
Expansion			506.4				679.3				668.7
Maintenance			85.7				97.9				79.1
Gross capital expenditures			592.1				777.2				747.8
Transfers from materials and supplies inventory to property, plant and equipment			(2.4	)			(3.8	)			(4.6	)
Decrease in capital project payables and accruals			(27.6	)			43.8				19.0
Cash outlays for capital projects			562.1				817.2				762.2
Total		$	562.1			$	2,391.6			$	762.2

(1)	Includes the non-cash value of consideration. See Note 4 – Business Acquisitions of the “Consolidated Financial Statements”.

Assuming the closing of the Permian Acquisition occurs in the first quarter of 2017, we currently estimate that we will invest at least $700 million in net growth capital expenditures (exclusive of outlays for business acquisitions) for announced projects in 2017. Given our objective of growth through expansions of existing assets, other internal growth projects, and acquisitions, we anticipate that over time that we will invest significant amounts of capital to grow and acquire assets. Future expansion capital expenditures may vary significantly based on investment opportunities. Our expansion capital expenditures decreased in 2016 as compared to 2015, primarily due to reduced gathering and processing business unit spending activity and lower CBF Train 5 construction costs in 2016. Although CBF Train 5 commenced commercial operations in the second quarter of 2016, only slightly more than 20% of the construction costs were incurred in 2016. Reductions are partially offset by spending on the South Texas Joint Venture with Sanchez Energy and the Channelview Condensate Splitter. Our maintenance capital expenditures decreased for the year ended December 31, 2016 as compared to the year ended December 31, 2015, primarily due to fewer well connects and lengthened maintenance cycle times resulting from decreases in producer activity, as well as a higher percentage of environmental expenditures incurred in 2015 versus 2016.

Off-Balance Sheet Arrangements

As of December 31, 2016, there were $30.9 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

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

Contractual Obligations

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

		Payments Due By Period
							Less Than															More Than
Contractual Obligations		Total					1 Year					1-3 Years					3-5 Years					5 Years
		(in millions)
Long-term debt obligations (1)		$		4,641.8			$		-			$		999.9			$		431.5			$		3,210.4
Interest on debt obligations (2)				1,437.2					236.8					433.8					356.6					410.0
Operating leases (3)				37.9					15.4					16.5					6.0					-
Land site lease and right-of-way (4)				14.2					3.2					5.6					5.4					-
Purchase Obligations (5):
Pipeline capacity and throughput agreements (6)				392.0					74.6					124.5					96.4					96.5
Commodities (7)				60.2					60.2					-					-					-
Purchase commitments and service contracts (8)				170.4					161.1					8.8					0.2					0.3
		$		6,753.7			$		551.3			$		1,589.1			$		896.1			$		3,717.2
Commodity Volumetric Commitments
Natural gas (MMBtu)				13.2					13.2					-					-					-
NGLs (MMgal)				19.8					19.8					-					-					-

(1)	Represents scheduled future maturities of consolidated debt obligations for the periods indicated.

(2)	Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing December 31, 2016 rates for floating debt.

(3)	Includes minimum payments on lease obligations for office space, railcars and tractors.

(4)	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.

(5)	A purchase obligation represents an agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms, including: fixed minimum or variable prices provisions; and the approximate timing of the transaction.

(6)	Consists of pipeline capacity payments for firm transportation and throughput and deficiency agreements.

(7)	Includes natural gas and NGL purchase commitments. Contracts that will be settled at future spot prices are valued using prices as of December 31, 2016.

(8)	Includes commitments for capital expenditures, operating expenses and service contracts.

Critical Accounting Policies and Estimates

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

Property, Plant and Equipment and Intangibles

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

	•	changes in energy prices;

	•	changes in competition;

	•	changes in laws and regulations that limit the estimated economic life of an asset;

	•	changes in technology that render an asset obsolete;

	•	changes in expected salvage values; and

	•	changes in the forecasted life of applicable resources basins.

We evaluate long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. As a result of this evaluation, the carrying value of certain Louisiana gas processing facilities and associated gathering systems in the Gathering and Processing segment was reduced by $32.6 million and $3.2 million during the years ended December 31, 2015 and 2014 as a result of reduced forecasted gas processing volumes due to market conditions and processing spreads. These carrying value adjustments are included in depreciation and amortization expenses on our Consolidated Statements of Operations. There have been no significant changes impacting long-lived assets during the year ended December 31, 2016.

Goodwill

Goodwill results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. 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.

Our evaluations as of November 30, 2016 and 2015 utilized the income approach (a discounted cash flow analysis (“DCF”)) to estimate the fair values of our reporting units. The future cash flows for our reporting units were based on our estimates, at that time, of future revenues, income from operations and other factors, such as timing of capital expenditures. We took into account current and expected industry and market conditions, including commodity pricing and volumetric forecasts in the basins in which the reporting units operate. The discount rates used in our DCF analysis were based on a weighted average cost of capital determined from relevant market comparisons.

Based on the results of our preliminary evaluation as of November 30, 2015, we recorded a provisional goodwill impairment of $290.0 million during the year ended December 31, 2015 and reduced the carrying value of goodwill to $417.0 million as of December 31, 2015. During the first quarter of 2016, we finalized our evaluation and recorded additional impairment expense of $24.0 million and reduced the carrying value of goodwill to $393.0 million. Based on the results of our evaluation as of November 30, 2016, we recorded goodwill impairment of $183.0 million and reduced the carrying value of goodwill to $210.0 million.

Revenue Recognition

Our operating revenues are primarily derived from the following activities:

	•	sales of natural gas, NGLs, condensate and petroleum products;

	•	services related to compressing, gathering, treating, and processing of natural gas;

	•	services related to gathering, storing and terminaling of crude oil; and

	•	services related to NGL fractionation, terminaling and storage, transportation and treating.

We recognize revenues when all 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.

Price Risk Management (Hedging)

Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. In an effort to reduce the volatility of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a significant portion of our expected natural gas, NGL, and condensate equity volumes and future commodity purchases and sales. We are exposed to the credit risk of certain of our counterparties in these derivative financial instruments. Our futures contracts have limited credit risk since they are cleared through an exchange and are settled daily.

Our cash flow is affected by the derivative financial instruments we enter into to the extent these instruments are settled by (i) making or receiving a payment to/from the counterparty or (ii) making or receiving a payment for entering into a contract that exactly offsets the original derivative financial instrument. Typically a derivative financial instrument is settled when the physical transaction that underlies the derivative financial instrument occurs.

One of the primary factors that can affect our operating results each period is the price assumptions used to value our derivative financial instruments, which are reflected at their fair values in the balance sheet. The relationship between the derivative financial instruments 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 derivative financial instrument and on an ongoing basis. Hedge accounting is discontinued prospectively when a derivative financial instrument becomes ineffective. Gains and losses deferred in other comprehensive income (“OCI”) related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the derivative financial instrument are reclassified to earnings immediately.

The estimated fair value of our derivative financial instruments was a net liability of $53.3 million as of December 31, 2016, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year as indicated by the counterparties’ credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which is immaterial for all periods covered by this Annual Report. We have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties.

Business Acquisitions

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

Use of Estimates

When preparing financial statements in accordance with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. 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) valuing mandatorily redeemable preferred interests. Actual results, therefore, could differ materially from estimated amounts.

Recent Accounting Pronouncements

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