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

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes included in Part IV of this Annual Report. Additional sections in this Annual Report should be helpful to the reading of our discussion and analysis and include the following: (i) a description of our business strategy found in “Item 1. Business–Overview”; (ii) a description of recent developments, found in “Item 1. Business–Recent Developments”; and (iii) a description of risk factors affecting us and our business, found in “Item 1A. Risk Factors.” Also, the Partnership files a separate Annual Report on Form 10-K with the SEC.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The amendments in this update supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. We adopted Topic 606 on January 1, 2018 by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption of Topic 606 did not result in an impact to our operating or gross margin. However, the adoption did have an impact on the classification between components of operating margin and gross margin, “Fees from midstream services” and “Product purchases,” as well as the reporting of gross versus net revenues. For more information, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.

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.

We are engaged in the business of:

•gathering, compressing, treating, processing, transporting and selling natural gas;
•storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters;
•gathering, storing, terminaling and selling crude oil; and
•storing, terminaling and selling refined petroleum products.

Factors That Significantly Affect Our Results

Our results of operations are impacted by a number of factors, including changes in commodity prices, the volumes that move through our gathering, processing and logistics assets, contract terms, the impact of hedging activities and the cost to operate and support assets.

Commodity Prices

The following table presents selected average annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periods presented:

Natural Gas $/MMBtu (1)Illustrative Targa NGL $/gal (2)Crude Oil $/Bbl (3)
2018
4th Quarter$3.66$0.69$58.83
3rd Quarter2.910.8869.50
2nd Quarter2.800.7567.90
1st Quarter2.990.7162.89
2018 Average3.090.7664.78
2017
4th Quarter$2.93$0.74$55.39
3rd Quarter2.990.6348.19
2nd Quarter3.190.5548.29
1st Quarter3.310.6151.86
2017 Average3.110.6350.93
2016
4th Quarter$2.98$0.53$47.73
3rd Quarter2.810.4544.94
2nd Quarter1.950.4645.59
1st Quarter2.090.3633.45
2016 Average2.460.4542.93
(1)Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.
(2)“Illustrative Targa NGL” pricing is weighted using average quarterly prices from Mont Belvieu Non-TET monthly commercial index and represents the following composition for the periods noted:

2018: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline

2017: 38% ethane, 34% propane, 13% normal butane, 5% isobutane and 10% natural gasoline

2016: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline

(3)Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX.

Volumes

In our gathering and processing operations, plant inlet volumes, crude oil volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a regional basis and more broadly by the impact of prices for crude oil, natural gas and NGLs on exploration and production activity in the areas of our operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to our Downstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available pipeline capacity to transport NGLs to our fractionators and our competitive and contractual position relative to other fractionators.

Contract Terms, Contract Mix and the Impact of Commodity Prices

With the potential for volatility of commodity prices, the contract mix of our Gathering and Processing segment, other than fee-based contracts in certain gathering and processing business units and gathering and processing services, can have a significant impact on our profitability, especially those contracts that create direct exposure to changes in energy prices by paying us for gathering and processing services with a portion of proceeds from the commodities handled (“equity volumes”).

Contract terms in the Gathering and Processing segment are based upon a variety of factors, including natural gas and crude quality, geographic location, competitive dynamics and the pricing environment at the time the contract is executed, and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to crude, natural gas and NGL prices may change as a result of producer preferences, competition and changes in production as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common and other market factors.

The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. Fractionation services are supported by fee-based contracts whose rates and terms are driven by NGL supply and fractionation capacity. Export services are supported by fee-based contracts whose rates and terms are driven by global LPG demand fundamentals. The Logistics and Marketing segment includes primarily fee-based contracts.

Impact of Our Commodity Price Hedging Activities

We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures, and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We intend to continue managing our exposure to commodity prices in the future by entering into derivative transactions. We actively manage the Downstream Business product inventory and other working capital levels to reduce exposure to changing prices. For additional information regarding our hedging activities, see “Item 7A. 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. The fuel and power costs are pass-through elements in many of our logistics contracts, which mitigates their impact on our results. Continued expansion of existing assets will also give rise to additional operating expenses, which will affect our results. The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company, and an indirect wholly-owned subsidiary of ours.

General and Administrative Expenses

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

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, competition and increased regulation. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

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. Producers generally focus their drilling activity on certain basins depending on commodity price fundamentals. As a result, our asset systems are predominately located in some of the most economic basins in the United States. Accordingly, increased producer activity will drive demand for our midstream services and may result in incremental infrastructure growth capital expenditures. Demand in our Downstream Business for fractionation and other fee-based services is largely correlated with producer activity levels. Demand for our international export, storage and terminaling services has remained relatively constant during recent commodity price volatility, as demand for these services is based on a number of domestic and international factors.

Commodity Prices

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. In addition, the volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems. Global oil and natural gas commodity prices, particularly crude oil, have declined substantially as compared to mid-2014 and remain volatile. See “Item 1A. Risk Factors – Our cash flow is affected by supply and demand for natural gas and NGL products and by natural gas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.”

Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, and where the spread between NGL prices and natural gas prices widens primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing and the supply of and market demand for natural gas, NGLs and condensate. Pricing and supply are beyond our control and have been volatile. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. Due to the volatility in commodity prices, we are uncertain of what pricing and market demand for oil, condensate, NGLs and natural gas will be throughout 2019, and, as a result, demand for the services that we provide may decrease. Across our operations and particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. The significant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Volatile Capital Markets and Competition

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 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 “Laws and regulations regarding hydraulic fracturing could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets” and “The adoption and implementation of climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the products and services we provide” under Item 1A of this Annual Report. Similarly, the forthcoming rules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less predictability in our results of operations.

How We Evaluate Our Operations

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

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

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

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, connected by third-party transportation and in the future through Grand Prix, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

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

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

Operating Expenses

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

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

Adjusted EBITDA

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

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

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

Distributable Cash Flow

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

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

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

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

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.

201820172016
(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin:
Net income (loss) attributable to TRC$1.6$54.0$(187.3)
Net income (loss) attributable to noncontrolling interests58.850.228.2
Net income (loss)60.4104.2(159.1)
Depreciation and amortization expense815.9809.5757.7
General and administrative expense256.9203.4187.2
Impairment of property, plant and equipment—378.0—
Impairment of goodwill210.0—207.0
Interest expense, net185.8233.7254.2
Income tax expense (benefit)5.5(397.1)(100.6)
(Gain) loss on sale or disposition of assets(0.1)15.96.1
(Gain) loss from financing activities2.016.848.2
Other, net(12.6)(78.5)13.6
Operating margin1,523.81,285.91,214.3
Operating expenses722.0622.9553.7
Gross margin$2,245.8$1,908.8$1,768.0
201820172016
(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA and Distributable Cash Flow
Net income (loss) attributable to TRC$1.6$54.0$(187.3)
Impact of TRC/TRP Merger on NCI——(3.8)
Income attributable to TRP preferred limited partners11.311.311.3
Interest expense, net (1)185.8233.7254.2
Income tax expense (benefit)5.5(397.1)(100.6)
Depreciation and amortization expense815.9809.5757.7
Impairment of property, plant and equipment—378.0—
Impairment of goodwill210.0—207.0
(Gain) loss on sale or disposition of business and assets(0.1)15.96.1
(Gain) loss from financing activities (2)2.016.848.2
Equity (earnings) loss(7.3)17.014.3
Distributions from unconsolidated affiliates and preferred partner interests, net31.518.017.5
Change in contingent considerations(8.8)(99.6)(0.4)
Compensation on equity grants56.342.329.7
Transaction costs related to business acquisitions—5.6—
Splitter Agreement (3)75.243.010.8
Risk management activities (4)8.510.025.2
Noncontrolling interests adjustments (5)(21.1)(18.6)(25.0)
TRC Adjusted EBITDA$1,366.3$1,139.8$1,064.9
Distributions to TRP preferred limited partners(11.3)(11.3)(11.3)
Cash received from payments under Splitter Agreement (3)43.043.043.0
Splitter Agreement (3)(75.2)(43.0)(10.8)
Interest expense on debt obligations (6)(252.5)(224.3)(263.8)
Cash tax benefit (7)—46.720.9
Maintenance capital expenditures(135.0)(100.7)(85.7)
Noncontrolling interests adjustments of maintenance capital expenditures7.11.65.2
Distributable Cash Flow$942.4$851.8$762.4
(1)Includes the change in estimated redemption value of the mandatorily redeemable preferred interests.
(2)Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments.
(3)In Distributable Cash Flow, the Splitter Agreement adjustment represents the amounts necessary to reflect the annual cash payment in the period received less the amount recognized in Adjusted EBITDA. In Adjusted EBITDA for 2016 and 2017, the Splitter Agreement adjustment represents the recognition of the annual cash payment received under the Splitter Agreement over the four quarters following receipt. As a result of Vitol’s election to terminate the Splitter Agreement in December 2018, the full amount of the 2018 annual cash payment was recognized in Adjusted EBITDA in the fourth quarter of 2018.
(4)Risk management activities related to derivative instruments including the cash impact of hedges acquired in the 2015 mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. The cash impact of the acquired hedges ended in December 2017.
(5)Noncontrolling interest portion of depreciation and amortization expense.
(6)Excludes amortization of interest expense.
(7)Includes an adjustment, reflecting the benefit from net operating loss carryback to 2015 and 2014, which was recognized over the periods between the third quarter 2016 recognition of the receivable and the anticipated receipt date of the refund. The refund, previously expected to be received on or before the fourth quarter of 2017, was received in the second quarter of 2017. The remaining $20.9 million unamortized balance of the tax refund was therefore included in Distributable Cash Flow in the second quarter of 2017. Also includes a refund of Texas margin tax paid in previous periods and received in 2017.

Consolidated Results of Operations

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

Year Ended December 31,
2018201720162018 vs. 20172017 vs. 2016
(In millions, except operating statistics and price amounts)
Revenues
Sales of commodities$9,278.7$7,751.1$5,626.8$1,527.620%$2,124.338%
Fees from midstream services1,205.31,063.81,064.1141.513%(0.3)—
Total revenues10,484.08,814.96,690.91,669.119%2,124.032%
Product purchases8,238.26,906.14,922.91,332.119%1,983.240%
Gross margin (1)2,245.81,908.81,768.0337.018%140.88%
Operating expenses722.0622.9553.799.116%69.212%
Operating margin (1)1,523.81,285.91,214.3237.919%71.66%
Depreciation and amortization expense815.9809.5757.76.41%51.87%
General and administrative expense256.9203.4187.253.526%16.29%
Impairment of property, plant and equipment—378.0—(378.0)(100%)378.0—
Impairment of goodwill210.0—207.0210.0—(207.0)(100%)
Other operating (income) expense3.517.46.6(13.9)(80%)10.8164%
Income (loss) from operations237.5(122.4)55.8359.9294%(178.2)NM
Interest expense, net(185.8)(233.7)(254.2)47.920%20.58%
Equity earnings (loss)7.3(17.0)(14.3)24.3143%(2.7)(19%)
Gain (loss) from financing activities(2.0)(16.8)(48.2)14.888%31.465%
Change in contingent considerations8.899.60.4(90.8)(91%)99.2NM
Other income (expense), net0.1(2.6)0.82.7104%(3.4)NM
Income tax (expense) benefit(5.5)397.1100.6(402.6)(101%)296.5295%
Net income (loss)60.4104.2(159.1)(43.8)(42%)263.3165%
Less: Net income (loss) attributable to noncontrolling interests58.850.228.28.617%22.078%
Net income (loss) attributable to Targa Resources Corp.1.654.0(187.3)(52.4)(97%)241.3129%
Dividends on Series A Preferred Stock91.791.772.6——19.126%
Deemed dividends on Series A Preferred Stock29.225.718.23.514%7.541%
Net income (loss) attributable to common shareholders$(119.3)$(63.4)$(278.1)$(55.9)(88%)$214.777%
Financial data:
Adjusted EBITDA (1)$1,366.3$1,139.8$1,064.9$226.520%$74.97%
Distributable cash flow (1)942.4851.8762.490.611%89.412%
Capital expenditures (2)3,327.71,506.5592.11,821.2121%914.4154%
Business acquisition (3)—987.1—(987.1)(100%)987.1—
(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)Capital expenditures, net of contributions from noncontrolling interest, were $2,740.7 million, $1,441.5 million and $524.8 million for the years ended December 31, 2018, 2017 and 2016.
(3)Includes the $416.3 million acquisition date fair value of the potential earn-out payments.
NMDue to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

2018 Compared to 2017

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2017 Compared to 2016

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

Gathering and ProcessingLogistics and MarketingOtherCorporate and EliminationsConsolidated Operating Margin
(In millions)
2018$968.4$592.5$(37.1)$—$1,523.8
2017783.8511.8(9.6)(0.1)1,285.9
2016577.1574.462.9(0.1)1,214.3

Gathering and Processing Segment

Year Ended December 31,
2018201720162018 vs. 20172017 vs. 2016
Gross margin$1,406.7$1,145.5$903.6$261.223%$241.927%
Operating expenses438.3361.7326.576.621%35.211%
Operating margin$968.4$783.8$577.1$184.624%$206.736%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)1,141.2893.5747.4247.728%146.120%
Permian Delaware (4)443.9381.8321.062.116%60.819%
Total Permian1,585.11,275.31,068.4309.8206.9
SouthTX389.6273.2216.4116.443%56.826%
North Texas244.1268.1317.3(24.0)(9%)(49.2)(16%)
SouthOK555.7494.0462.161.712%31.97%
WestOK351.6377.7444.9(26.1)(7%)(67.2)(15%)
Total Central1,541.01,413.01,440.7128.0(27.7)
Badlands (5)85.156.552.128.651%4.48%
Total Field3,211.22,744.82,561.2466.4183.6
Coastal726.2728.8838.4(2.6)—(109.6)(13%)
Total3,937.43,473.63,399.6463.813%74.02%
NGL production, MBbl/d (3)
Permian Midland (4)153.4118.394.535.130%23.825%
Permian Delaware (4)53.543.136.410.424%6.718%
Total Permian206.9161.4130.945.530.5
SouthTX51.130.423.820.768%6.628%
North Texas28.130.235.8(2.1)(7%)(5.6)(16%)
SouthOK54.742.839.411.928%3.49%
WestOK20.521.927.1(1.4)(6%)(5.2)(19%)
Total Central154.4125.3126.129.1(0.8)
Badlands10.87.97.32.937%0.68%
Total Field372.1294.6264.377.530.3
Coastal43.638.641.25.013%(2.6)(6%)
Total415.7333.2305.582.525%27.79%
Crude oil gathered, Badlands, MBbl/d146.8113.6105.233.229%8.48%
Crude oil gathered, Permian, MBbl/d (4)64.929.8—35.1118%29.8—
Natural gas sales, BBtu/d (3)1,867.91,665.41,623.6202.512%41.83%
NGL sales, MBbl/d317.6254.8241.362.825%13.56%
Condensate sales, MBbl/d12.611.89.90.87%1.919%
Average realized prices (6):
Natural gas, $/MMBtu1.982.652.14(0.67)(25%)0.5124%
NGL, $/gal0.630.550.360.0815%0.1953%
Condensate, $/Bbl55.9945.5236.2010.4723%9.3226%
(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.
(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, other than Badlands.
(3)Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.
(4)Includes operations from the Permian Acquisition for the period effective March 1, 2017. New Midland volumes are included within Permian Midland and New Delaware volumes are included within Permian Delaware. For the volume statistics presented, the numerator is the total volume sold during the period of our ownership while the denominator is the number of calendar days during the year.
(5)Badlands natural gas inlet represents the total wellhead gathered volume.
(6)Average realized prices exclude the impact of hedging activities presented in Other.

2018 Compared to 2017

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

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

2017 Compared to 2016

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

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

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, 2018
Operating statistics:
Plant natural gas inlet, MMcf/d (1), (2)Gross Volume (3)Ownership %Net Volume (3)Actual Reported
Permian Midland1,438.5Varies (4)1,141.21,141.2
Permian Delaware443.9100%443.9443.9
Total Permian1,882.41,585.11,585.1
SouthTX389.6Varies (5)283.9389.6
North Texas244.1100%244.1244.1
SouthOK555.7Varies (6)432.8555.7
WestOK351.6100%351.6351.6
Total Central1,541.01,312.41,541.0
Badlands (7)85.1100%85.185.1
Total Field3,508.52,982.63,211.2
NGL production, MBbl/d (2)
Permian Midland194.1Varies (4)153.4153.4
Permian Delaware53.5100%53.553.5
Total Permian247.6206.9206.9
SouthTX51.1Varies (5)35.951.1
North Texas28.1100%28.128.1
SouthOK54.7Varies (6)42.854.7
WestOK20.5100%20.520.5
Total Central154.4127.3154.4
Badlands10.8100%10.810.8
Total Field412.8345.0372.1
(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, other than Badlands.
(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)Permian Midland includes operations in WestTX, of which we own 73%, and other plants which are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.
(5)SouthTX includes the Raptor Plant and Silver Oak II Plant, both of which we own a 50% interest through the Carnero Joint Venture. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.
(6)SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants which are owned 100% by us. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.
(7)Badlands natural gas inlet represents the total wellhead gathered volume.
Year Ended December 31, 2017
Operating statistics:
Plant natural gas inlet, MMcf/d (1), (2)Gross Volume (3)Ownership %Net Volume (3)Actual Reported
Permian Midland (4)1,110.8Varies (5)893.5893.5
Permian Delaware (4)381.8100%381.8381.8
Total Permian1,492.61,275.31,275.3
SouthTX273.2Varies (6)213.5273.2
North Texas268.1100%268.1268.1
SouthOK494.0Varies (7)397.9494.0
WestOK377.7100%377.7377.7
Total Central1,413.01,257.21,413.0
Badlands (8)56.5100%56.556.5
Total Field2,962.12,589.02,744.8
NGL production, MBbl/d (2)
Permian Midland (4)148.2Varies (5)118.3118.3
Permian Delaware (4)43.1100%43.143.1
Total Permian191.3161.4161.4
SouthTX30.4Varies (6)23.430.4
North Texas30.2100%30.230.2
SouthOK42.8Varies (7)34.942.8
WestOK21.9100%21.921.9
Total Central125.3110.4125.3
Badlands7.9100%7.97.9
Total Field324.5279.7294.6
(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, other than Badlands.
(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 operations from the Permian Acquisition for the period effective March 1, 2017. New Midland volumes are included within Permian Midland and New Delaware volumes are included within Permian Delaware.
(5)Permian Midland includes operations in WestTX, of which we own 73%, and other plants which are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.
(6)SouthTX includes the Raptor Plant, which began operations in the second quarter of 2017, of which we own a 50% interest through the Carnero Joint Venture. SouthTX also includes the Silver Oak II Plant, of which we owned a 90% interest from October 2015 through May 2017, and after which we owned a 100% interest until it was contributed to the Carnero Joint Venture in May 2018. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.
(7)SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants which are owned 100% by us. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.
(8)Badlands natural gas inlet represents the total wellhead gathered volume.
Year Ended December 31, 2016
Operating statistics:
Plant natural gas inlet, MMcf/d (1), (2)Gross Volume (3)Ownership %Net Volume (3)Actual Reported
Permian Midland (4)929.8Varies (5)747.4747.4
Permian Delaware321.0Varies (6)253.8321.0
Total Permian1,250.81,001.21,068.4
SouthTX216.4Varies (7)205.6216.4
North Texas317.3100%317.3317.3
SouthOK462.1Varies (8)382.0462.1
WestOK444.9100%444.9444.9
Total Central1,440.71,349.81,440.7
Badlands (9)52.1100%52.152.1
Total Field2,743.62,403.12,561.2
Gross NGL production, MBbl/d (2)
Permian Midland (4)117.9Varies (5)94.594.5
Permian Delaware36.4Varies (6)36.436.4
Total Permian154.3130.9130.9
SouthTX23.8Varies (7)22.823.8
North Texas35.8100%35.835.8
SouthOK39.4Varies (8)32.639.4
WestOK27.1100%27.127.1
Total Central126.1118.3126.1
Badlands7.3100%7.37.3
Total Field287.7256.5264.3
(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, other than Badlands.
(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 the Buffalo Plant that commenced commercial operations in April 2016.
(5)Permian Midland includes operations in WestTX, of which we own 73%, and other plants which are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.
(6)Permian Delaware includes Versado, which is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials, and other plants which are owned 100% by us. We held a 63% interest in Versado until October 31, 2016, when we acquired the remaining 37% interest.
(7)SouthTX includes the Silver Oak II Plant, of which we owned a 90% interest from October 2015 through May 2017, and after which we owned a 100% interest until it was contributed to the Carnero Joint Venture in May 2018. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.
(8)SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants which are owned 100% by us. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.
(9)Badlands natural gas inlet represents the total wellhead gathered volume.

Logistics and Marketing Segment

Year Ended December 31,
2018201720162018 vs. 20172017 vs. 2016
(In millions)
Gross margin$876.8$773.4$801.8$103.413%$(28.4)(4%)
Operating expenses284.3261.6227.422.79%34.215%
Operating margin$592.5$511.8$574.4$80.716%$(62.6)(11%)
Operating statistics MBbl/d (1):
Fractionation volumes (2)(3)426.7354.2309.372.520%44.915%
LSNG treating volumes (2)32.132.224.9(0.1)—7.329%
Benzene treating volumes (2)(4)3.321.622.1(18.3)(85%)(0.5)(2%)
Export volumes (5)203.4184.1181.419.310%2.71%
NGL sales537.9490.0477.547.910%12.53%
Average realized prices:
NGL realized price, $/gal$0.77$0.69$0.49$0.0812%$0.2041%
(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)The benzene saturation unit of the LSNG Hydrotreater was idled in 2018.
(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.

2018 Compared to 2017

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

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

2017 Compared to 2016

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

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

Other

Year Ended December 31,
2018201720162018 vs. 20172017 vs. 2016
(In millions)
Gross margin$(37.1)$(9.6)$62.9$(27.5)$(72.5)
Operating margin$(37.1)$(9.6)$62.9$(27.5)$(72.5)

Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow.

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

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

201820172016
(In millions, except volumetric data and price amounts)
Volume SettledPrice Spread (1)Gain (Loss)Volume SettledPrice Spread (1)Gain (Loss)Volume SettledPrice Spread (1)Gain (Loss)
Natural gas (BBtu)63.5$0.82$51.961.1$0.22$13.544.7$0.79$35.2
NGL (MMgal)367.4(0.16)(58.4)262.9(0.10)(26.0)31.90.216.8
Crude oil (MBbl)2.0(11.26)(22.7)1.34.095.31.117.1419.5
Non-hedge accounting (2)(7.9)(2.2)2.3
Ineffectiveness (3)-(0.2)(0.9)
$(37.1)$(9.6)$62.9
(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)Effective upon the adoption of ASU 2017-12 on January 1, 2018, we are no longer required to recognize ineffectiveness through operating margin. Prior to our adoption of ASU 2017-12, ineffectiveness primarily related to certain crude hedging contracts and certain acquired hedges of TPL that did not qualify for hedge accounting.

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

Our Liquidity and Capital Resources

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

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

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

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

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

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

Short-term Liquidity

Our short-term liquidity on a consolidated basis as of February 21, 2019, was:

February 21, 2019
(In millions)
TRCTRPConsolidated Total
Cash on hand$17.8$283.2$301.0
Total availability under the TRC Revolver670.0—670.0
Total availability under the TRP Revolver—2,200.02,200.0
Total availability under the Securitization Facility—378.0378.0
687.82,861.23,549.0
Less: Outstanding borrowings under the TRC Revolver(450.0)—(450.0)
Outstanding borrowings under the TRP Revolver—(400.0)(400.0)
Outstanding borrowings under the Securitization Facility—(378.0)(378.0)
Outstanding letters of credit under the TRP Revolver—(71.7)(71.7)
Total liquidity$237.8$2,011.5$2,249.3

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 June 29, 2023.
•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 June 29, 2023.

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

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

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

Long-term Financing

In February 2018, Stonepeak Infrastructure Partners (“Stonepeak”) committed a maximum of approximately $960 million of capital to the three newly-formed DevCo JVs. Concurrent with the sale of the 25% interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin.

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

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

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

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

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

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

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

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

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

In January 2019, the Partnership issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of approximately $1,488.8 million. The net proceeds from the offerings were used to redeem in full the Partnership’s outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date and the remainder is expected to be used for general partnership purposes, which may include repaying borrowings under its credit facilities or other indebtedness, funding growth investments and acquisitions and working capital.

In February 2019, we entered into definitive agreements to sell a 45% interest in Targa Badlands LLC, the entity that holds all of our assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities for $1.6 billion. We will continue to be the operator of Badlands and will hold majority governance rights. We expect to use the net cash proceeds to pay down debt and for general corporate purposes, including funding our growth capital program. The transaction is expected to close in the second quarter of 2019 and is subject to customary regulatory approvals and closing conditions.

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

Compliance with Debt Covenants

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

Cash Flow

Cash Flows from Operating Activities

2018201720162018 vs. 20172017 vs. 2016
(In millions)
$1,144.0$939.5$837.4$204.5$102.1

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

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

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

Cash Flows from Investing Activities

2018201720162018 vs. 20172017 vs. 2016
(In millions)
$(3,146.9)$(1,892.7)$(558.6)$(1,254.2)$(1,334.1)

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

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

Cash Flows from Financing Activities

201820172016
Source of Financing Activities, net(In millions)
Debt, including financing costs$1,590.8$149.4$(1,127.4)
Contributions from noncontrolling interests817.9141.643.3
Equity offerings, net of financing costs683.51,644.41,522.6
Dividends and distributions(919.6)(854.5)(716.5)
Other(74.8)(64.0)(67.5)
Net cash provided by (used in) financing activities$2,097.8$1,016.9$(345.5)

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

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

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

Common Dividends

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

Three Months EndedDate Paid or To Be PaidTotal Common Dividends DeclaredAmount of Common Dividends Paid or To Be PaidAccrued Dividends (1)Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
2018
December 31, 2018February 15, 2019$215.2$211.2$4.0$0.91000
September 30, 2018November 15, 2018212.5208.63.90.91000
June 30, 2018August 15, 2018208.9205.23.70.91000
March 31, 2018May 16, 2018203.1199.73.40.91000
(1)Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Preferred Dividends

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

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

Capital Requirements

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

201820172016
(In millions)
Capital requirements:
Consideration for business acquisition$—$987.1$—
Contingent consideration (1)—(416.3)—
Cash outlay for business acquisition, net of cash acquired—570.8—
Growth (2)3,192.71,405.7506.4
Maintenance (2)135.0100.885.7
Gross capital expenditures3,327.71,506.5592.1
Transfers of capital expenditures to investment in unconsolidated affiliates16.0——
Transfers from materials and supplies inventory to property, plant and equipment(12.7)(3.6)(2.4)
Change in capital project payables and accruals(216.2)(205.4)(27.6)
Cash outlays for capital projects3,114.81,297.5562.1
Total capital outlays$3,114.8$1,868.3$562.1
(1)See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures of the “Consolidated Financial Statements.” Represents the fair value of contingent consideration at the acquisition date.
(2)Growth capital expenditures, net of contributions from noncontrolling interests, were $2,612.8 million, $1,342.4 million and $444.3 million for the years ended December 31, 2018, 2017 and 2016. Maintenance capital expenditures, net of contributions from noncontrolling interests, were $127.9 million, $99.1 million and $80.5 million for the years ended December 31, 2018, 2017 and 2016.

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

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

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

Off-Balance Sheet Arrangements

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

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

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 ThanMore Than
Contractual ObligationsTotal1 Year1-3 Years3-5 Years5 Years
(in millions)
Long-term debt obligations (1)$5,663.2$—$6.5$2,326.6$3,330.1
Interest on debt obligations (2)1,737.5299.9529.7499.0408.9
Operating leases (3)110.820.938.726.324.9
Land site lease and rights of way (4)122.34.07.38.2102.8
Purchase Obligations (5):
Pipeline capacity and throughput agreements (6)785.0167.2197.7198.5221.6
Commodities (7)240.8151.389.5——
Purchase commitments and service contracts (8)1,390.41,372.97.12.28.2
Other long-term liabilities (9)53.3—14.58.730.1
$10,103.3$2,016.2$891.0$3,069.5$4,126.6
Commodity Volumetric Commitments
Natural gas (MMBtu)19.919.9———
NGLs (MMgal)499.4213.8285.6——
(1)Represents scheduled future maturities of long-term debt obligations for the periods indicated. See Note 10 - Debt Obligations for more information regarding our debt obligations.
(2)Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing December 31, 2018 rates for floating debt. See Note 10 - Debt Obligations for more information regarding our debt obligations.
(3)Includes minimum payments on lease obligations for office space, railcars and tractors. See Note 19 - Commitments for more information regarding our operating leases.
(4)Land site lease and rights of way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates with varying terms, some of which are perpetual. See Note 19 - Commitments for more information regarding our land site lease and rights of way.
(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, 2018.
(8)Includes commitments for capital expenditures, operating expenses and service contracts.
(9)Includes long-term liabilities of which we are certain of the amount and timing, including certain arrangements that resulted in deferred revenue and other liabilities pertaining to accrued dividends. See Note 11 - Other Long-term Liabilities for more information regarding our other long-term liabilities.

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.

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

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

In general, depreciation and amortization is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. Amortization expense attributable to intangible assets is recorded in a manner that closely resembles the expected benefit pattern of the intangible assets, or where such pattern is not readily determinable, on a straight-line basis, over the periods in which we benefit from services provided to customers. At the time assets are placed in service or acquired, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation/amortization amounts prospectively. Examples of such circumstances include:

•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.

Impairment of Long-Lived Assets, including Intangible Assets and Goodwill

We evaluate long-lived assets, including related intangibles, for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of additional impairments.

We evaluate goodwill for impairment at least annually, as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not the fair value of a reporting unit is less than its carrying amount. We early adopted ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, for our annual goodwill impairment test as of November 30, 2017, which requires an impairment up to the amount of goodwill to the extent that the carrying value of the affected reporting unit exceeds its fair value.

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

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

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 portion of our expected natural gas, NGL, and condensate equity volumes, future commodity purchases and sales, and transportation basis risk.

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

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.

Previous: Item 6. Selected Financial Data. · Next: Item 7A. Quantitative and Qualitative Disclosures About Market Risk.