Targa Resources (TRGP) 10-K risk factor changes: FY2017 vs FY2016

If any of the following risks were [removed: actually] to occur, then our business, financial condition, cash flows and results of operations could be materially adversely affected.

As of December 31, [removed: 2016,] [added: 2017,] we had [removed: $4,002.2] [added: $4,223.0] million outstanding under the Partnership’s senior unsecured notes and $54.6 million of outstanding senior notes of TPL, excluding [removed: $0.5] [added: $0.4] million of unamortized net discounts and premiums.

We also had [removed: $275.0] [added: $350.0] million outstanding under the Partnership’s [removed: accounts receivable securitization facility (the “Securitization Facility”).][added: Securitization Facility.]

In addition, we had (i) [removed: $150.0] [added: $20.0] million of borrowings outstanding, [removed: $13.2] [added: $27.2] million of letters of credit outstanding and [removed: $1,436.8] [added: $1,552.8] million of additional borrowing capacity available under the TRP Revolver, (ii) [removed: $275.0] [added: $435.0] million of [added: borrowings outstanding, and $235.0 million of additional borrowing capacity available under the TRC Revolver.]

For the years ended December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014,] [added: 2015,] our consolidated interest expense, net was [removed: $254.2] [added: $233.7] million, [removed: $231.9] [added: $254.2] million and [removed: $147.1] [added: $231.9] million.

As of December 31, [removed: 2016,] [added: 2017,] the Partnership’s senior unsecured debt was rated “BB-” by S&P.

As of December 31, [removed: 2016,] [added: 2017,] the Partnership’s senior unsecured debt was rated “Ba3” by Moody’s.

This could increase the risks associated with [added: compliance with] our [removed: substantial leverage.][added: financial covenants.]

The TRP [removed: Revolver, TRC] Revolver and TRC [removed: Term Loan] [added: Revolver] allow us to request increases in commitments up to an additional $500 [removed: million, $200] million and $200 million, respectively.

If we incur additional debt, [added: this could increase] the risks associated with [added: compliance with] our [removed: substantial leverage would increase.][added: financial covenants.]

As of December 31, [removed: 2016,] [added: 2017,] our total indebtedness was [removed: $4,916.8] [added: $5,082.6] million, excluding [removed: $1.7] [added: $0.4] million of [removed: unamortized] net [removed: discounts,] [added: premiums and $30.0 million] of [added: net debt issuance costs, of] which [removed: $4,056.8] [added: $4,277.6] million was at fixed interest rates and [removed: $860.0] [added: $805.0] million was at variable interest rates.

A one percentage point increase in the interest rate on our variable interest rate debt would have increased our consolidated annual interest expense by approximately [removed: $8.6] [added: $8.1] million.

We have pledged [removed: substantially all] [added: the assets and equity] of [added: certain of] the Partnership’s [removed: assets] [added: subsidiaries] as collateral under the TRP Revolver and the accounts receivables of Targa Receivables LLC under the Securitization Facility.

Beginning in the third quarter of 2014, crude oil and natural gas prices significantly declined and continued to decline during 2015 and remained depressed in [removed: 2016.][added: 2016 before starting to recover in 2017.]

| | • | [removed: shareholder] [added: stockholder] activism and activities by non-governmental organizations to [added: limit certain sources of funding for the energy sector or] restrict the exploration, development and production of oil and natural [removed: gas so as to minimize GHG emissions;] [added: gas;] and |

For the year ended December 31, [removed: 2016,] [added: 2017,] our percent-of-proceeds arrangements accounted for approximately [removed: 67%] [added: 59.9%] of our gathered natural gas volume.

[removed: Please see] [added: See] “Item 7A.

We evaluate goodwill for impairment at least annually, as of November [removed: 30th,] [added: 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.

During [removed: 2015 and 2016,] [added: 2015,] global oil and natural gas commodity prices, particularly crude oil, significantly decreased as compared to [removed: 2014.][added: 2014, and such prices remained depressed in 2016 with some recovery in 2017.]

This decrease in commodity prices has had, and [removed: is expected to] [added: could] continue to have, a negative impact on the demand for our services and our market capitalization.

A decline in natural gas, NGL and crude oil prices may adversely affect the business, financial condition, results of operations, [added: creditworthiness,] cash flows and prospects of some of our customers.

Because of the natural decline in production in our operating regions and in other regions from which we source NGL supplies, our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude [removed: oil] [added: oil,] which depends on certain factors beyond our control.

In addition, any acquisitions we complete (including the Permian [removed: Acquisition, if it is completed)] [added: Acquisition and our recently announced Grand Prix and GCX joint ventures)] are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to pay dividends to stockholders.

In addition, we may not achieve the expected results of the Permian [removed: Acquisition, if it is completed,] [added: Acquisition] and any adverse conditions or developments related to the Permian [removed: Acquisition, if it is completed,] [added: Acquisition] may have a negative impact on our operations and financial condition.

Any acquisition (including the Permian [removed: Acquisition, if it is completed)] [added: Acquisition)] or growth project [added: (including Grand Prix and GCX)] involves potential risks, including, among other things:

| | • | the diversion of management’s and employees’ attention from other business concerns; [removed: and] |

For instance, if we build a new [added: pipeline,] fractionation facility or gas processing plant, the construction may occur over an extended period of time and we will not receive any material increases in revenues until the project is completed.

Moreover, we may construct [added: pipelines or] facilities to capture anticipated future growth in production in a region in which such growth does not materialize.

Since we are not engaged in the exploration for and development of natural gas and oil reserves, we do not possess reserve expertise and we often do not have access to third-party [added: estimates of potential reserves in an area prior to constructing pipelines or facilities in such area.]

As a result, new [added: pipelines or] facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new [removed: rights-of-way] [added: rights of way] prior to constructing new pipelines.

We may be unable to obtain such [removed: rights-of-way] [added: rights of way] to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities.

Additionally, it may become more expensive for us to obtain new [removed: rights-of-way] [added: rights of way] or to renew existing [removed: rights-of-way.][added: rights of way.]

If the cost of renewing or obtaining new [removed: rights-of-way] [added: rights of way] increases, our cash flows could be adversely affected.

Demand for propane is significantly impacted by weather conditions and therefore [removed: seasonal,] [added: seasonal] and requires increases in inventory to meet seasonal demand.

Any significant change in accounting standards or disclosure requirements could have a material effect on our [removed: business,] results of operations, financial condition and ability to comply with our debt obligations.

We have entered into derivative transactions related to only a portion of our equity [removed: volumes.][added: volumes and future commodity purchases and sales.]

[removed: In addition, market] [added: Market] and economic conditions may adversely affect our hedge counterparties’ ability to meet their obligations.

[removed: Given] volatility in the financial and commodity markets, we may experience defaults by our hedge [removed: counterparties in the future.][added: counterparties.]

If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and processing facilities become partially or fully unavailable to transport natural [removed: gas] [added: gas, NGLs] and [removed: NGLs,] [added: crude oil,] our revenues could be adversely affected.

Beginning in the third quarter of 2014, crude oil and natural gas prices significantly declined and continued to decline during 2015 and remained depressed in 2016 before starting to recover in 2017.

| | • | challenges associated with joint venture relationships and minority investments, including dependence on joint venture partners, controlling shareholders or management who may have business interests, strategies or goals that are inconsistent with ours; and |

Given

In addition, our exchange traded futures are subject to margin requirements, which creates variability in our cash flows as commodity prices fluctuate.

See “Item 7A.

Additionally, following a recent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment.

Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights of way may soon lapse or terminate serves as an additional impediment for pipeline operators.

We cannot guarantee that we will always be able to renew existing rights of way or obtain new rights of way without experiencing significant costs.

We may operate a portion of our business with one or more joint venture partners where we own a minority interest and/or are not the operator, which may restrict our operational and corporate flexibility.

Actions taken by the other partner or third-party operator may materially impact our financial position and results of operations, and we may not realize the benefits we expect to realize from a joint venture.

As is common in the midstream industry, we may operate one or more of our properties with one or more joint venture partners where we own a minority interest and/or contract with a third-party to control operations.

These relationships could require us to share operational and other control, such that we may no longer have the flexibility to control completely the development of these properties.

If we do not timely meet our financial commitments in such circumstances, our rights to participate may be adversely affected.

If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator does not operate in accordance with our expectations, our costs of operations could be increased.

We could also incur liability as a result of actions taken by a joint venture partner or third-party operator.

Disputes between us and the other party may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.

During 2017, we had minimal direct losses as a result of Hurricane Harvey.

The final rule also requires all pipelines in or affecting a high consequence area to be capable of accommodating in-line inspection tools within the next 20 years.

In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure.

The timing for implementation of this rule has been delayed and remains uncertain at this time due to the change in U.S. Presidential administrations.

In a second example, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines, including, among other things, the imposition of increased integrity management requirements.

PHMSA has not yet finalized the March 2016 proposed rulemaking.

See “Item 1.

Business –Regulation of Operations—Environmental and Operational Health and Safety Matters” for additional information regarding regulatory developments with respect to environmental regulations.

However, the EPA proposed rulemaking in June 2017 to stay certain requirements of Subpart OOOOa for a period of two years and revisit implementation of Subpart OOOOa in its entirety.

The EPA has not yet published a final rule but, as a result of these developments, future implementation of the 2016 Subpart OOOOa standards is uncertain.

Because of the long-term trend toward increasing regulation, however, future federal GHG regulations of the oil and natural gas industry remain a possibility.

However, in August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement.

The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020.

The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our products and services.

One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities.

Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities.

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time.

In another example, effective April 2017, PHMSA adopted a final rule increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $209,002 per violation per day and up to $2,090,022 for a related series of violations.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The safety enhancement requirements and other provisions of the 2016 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs or operational delays that could have a material adverse effect on our results of operation or financial position.

In 2018, Targa NGL will complete another pipeline for exports at Targa’s Galena Park dock.

Additionally, we expect to begin operating portions of the Grand Prix pipeline in 2018, which would transport mixed NGLs from the Permian Basin, including points in New Mexico and Texas, to intermediate points in Texas, and beginning in 2019, to Mont Belvieu, Texas.

borrowings outstanding, and $395.0 million of additional borrowing capacity available under the TRC revolving credit facility (the “TRC Revolver”) and (iii) $160.0 million of borrowings outstanding under the TRC Term Loan.

The duration and magnitude of the recent decline in oil, gas and NGLs prices cannot be predicted.

Based on the results of our annual evaluations in 2016 and 2015, we recorded goodwill impairments of $207.0 million for the year ended December 31, 2016 and $290.0 million for the year ended December 31, 2015, which are included in goodwill impairment in our Consolidated Statements of Operations.

The carrying value of goodwill as of December 31, 2016 has been reduced to $210.0 million.

estimates of potential reserves in an area prior to constructing facilities in such area.

As further described below in “Internal Control Over Financial Reporting,” as of December 31, 2016, we have identified a material weakness in our internal control over financial reporting.

If the total reserves

to be necessary as a result of the pipeline integrity testing.

The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines.

However, the date of implementation of this final rule by publication in the Federal Register is uncertain given the recent change in Presidential Administrations.

transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market.

In November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from facilities and operators in the oil and natural gas industry.

The EPA has indicated that it intended to use the information from this request to develop Existing Source Performance Standards (ESPS) for the oil and gas industry.

For example, in October 2015, PHMSA proposed new more stringent regulations for hazardous liquid pipelines, including extending certain integrity management assessment and repair requirements to pipelines not currently subject to integrity management regulations and requiring that all pipelines have a means of detecting leaks.

In another example, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their MAOP; and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards.

Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements and also require consideration of seismicity in evaluating threats to pipelines.

dealer counterparties to collect margin from us for our hedging transactions.

All shippers on these pipelines are our subsidiaries.

As of December 31, 2016, we have 184,720,525 outstanding shares of common stock.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our [removed: historical] [added: consolidated] financial statements and [added: the] notes included in Part IV of this Annual Report.

| | • | gathering, [removed: storing and] [added: storing,] terminaling [added: and selling] crude oil; and |

[removed: Beginning] [added: Notably, beginning] in the [removed: fourth] [added: third] quarter of 2014, [added: crude] oil, natural gas and NGL prices declined significantly primarily due to global supply and demand imbalances.

Logistics and Marketing [removed: Segment Expansion][added: segment gross margin consists primarily of :]

[added: | Source of] Financing [removed: Activities][added: Activities, net | (In millions) | | | | | | | | | | |]

[removed: In] [added: During] 2016, 19,983,843 [removed: warrants] [added: Warrants] were exercised [removed: by their holders] and net settled [removed: by us] for 11,336,856 shares of common stock.

On January 26, 2017, we completed a public offering of 9,200,000 shares of [added: our] common stock (including [added: the shares sold pursuant to the] underwriters’ overallotment option) at a price [added: to the public] of $57.65, providing net proceeds of [removed: $524.1] [added: $524.2] million.

We [removed: intend to use] [added: used] the net proceeds from this public offering to fund [removed: a] [added: the cash] portion of the [removed: $565 million initial] [added: Permian Acquisition] purchase price [removed: of the Permian Acquisition.][added: due upon closing and for general corporate purposes.]

Our results of operations are [removed: substantially] impacted by [added: 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.

[removed: 2014: 44%] [added: 2017: 38%] ethane, [removed: 30%] [added: 34%] propane, [removed: 10%] [added: 13%] normal butane, 5% isobutane and [removed: 11%] [added: 10%] natural gasoline

In our gathering and processing operations, plant inlet volumes, crude oil volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a regional basis and more broadly by the impact of prices for [added: crude] oil, natural gas and NGLs on exploration and production activity in the areas of our operations.

[removed: Because of] [added: With] the potential for [removed: significant] volatility of [removed: natural gas and NGL] [added: 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 [removed: material] [added: 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”).

[added: 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 current demand for fractionation services has [removed: grown] [added: grown,] resulting in increases in fractionation [added: fees, reservation] fees and contract term.

The Logistics and Marketing segment includes [removed: both] [added: primarily] fee-based [removed: and percent-of-proceeds] contracts.

We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes and future commodity purchases and sales through [removed: 2019] [added: 2020] by entering into financially settled derivative transactions.

We actively manage the Downstream Business product inventory and other working capital levels to reduce exposure to changing [removed: NGL] prices.

We perform centralized corporate functions [removed: for the Partnership,] such as legal, accounting, treasury, insurance, risk management, health, safety, environmental, information technology, human resources, credit, payroll, internal audit, [removed: taxes] [added: taxes,] engineering and marketing.

[removed: Producer activity generates demand] [added: Demand] in our Downstream Business for fractionation and other fee-based [removed: services, which may decrease in the near term.][added: services is largely correlated with producer activity levels.]

[removed: As prices have declined, demand] [added: Demand] for our international export, storage and terminaling services has remained relatively [removed: constant,] [added: constant during recent commodity price volatility,] as demand for these services is based on a number of domestic and international factors.

There has been and we believe there will continue to be [removed: significant] volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices.

Due to the recent volatility in commodity prices, we are uncertain of what pricing and market demand for oil, condensate, NGLs and natural gas will be throughout [removed: 2017,] [added: 2018,] and, as a result, demand for the services that we provide may decrease.

Current economic conditions and competition for asset purchases and development opportunities could limit our ability to fully execute our [removed: acquisition and] growth strategy.

Please read “Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets” and “The adoption and implementation of climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the products and services we provide” under Item 1A of this [removed: Form 10-K.][added: Annual Report.]

The profitability of our business segments is a function of the difference between: (i) the revenues we receive from [added: 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.

Our profitability is also impacted by fee-based [removed: revenues.][added: contracts.]

Our [removed: growth strategy, based on] [added: growing fee-related capital expenditures for pipelines,] expansion of [removed: existing facilities] [added: our downstream facilities,] as well as third-party acquisitions of businesses and assets, [removed: has increased] [added: will continue to increase] the [removed: percentage] [added: number] of our [removed: revenues] [added: contracts] that are fee-based.

These expenses, other than fuel and power, [removed: generally] remain relatively stable and independent of the volumes through our systems, but fluctuate depending on the scope of the activities performed during a specific period.

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

| | • | service [removed: fee revenues] [added: fees] (including the pass-through of energy costs included in fee rates), |

The gross margin impacts of [removed: cash flow] [added: our equity volumes] hedge settlements are reported in Other.

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 [removed: our] [added: its] decision-making processes.

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 [removed: our] [added: its] decision-making processes.

We define distributable cash flow as Adjusted EBITDA less distributions to TRP preferred limited partners, the Splitter Agreement [removed: adjustments,] [added: adjustment,] cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs).

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

| | | [removed: 2016] [added: 2017] | | | | | [removed: 2015] [added: 2016] | | | | | [removed: 2014] [added: 2015] | | | |

| Net income (loss) attributable to TRC | | $ | | [removed: (187.3] [added: 54.0] | [removed: )] | | $ | | [removed: 58.3] [added: (187.3] | [added: )] | | $ | | [removed: 102.3] [added: 58.3] | |

| Net income (loss) attributable to noncontrolling interests | | | | [removed: 28.2] [added: 50.2] | | | | | [removed: (209.7] [added: 28.2] | [removed: )] | | | | [removed: 320.7] [added: (209.7] | [added: )] |

| Net income (loss) | | | | [removed: (159.1] [added: 104.2] | [removed: )] | | | | [removed: (151.4] [added: (159.1] | ) | | | | [removed: 423.0] [added: (151.4] | [added: )] |

| Depreciation and amortization [removed: expenses] [added: expense] | | | | [removed: 757.7] [added: 809.5] | | | | | [removed: 677.1] [added: 757.7] | | | | | [removed: 351.0] [added: 644.5] | |

Additional sections in this report which should be helpful to the reading of our discussion and analysis 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.

| 4th Quarter | $ | 2.93 | | | $ | 0.74 | | | $ | 55.39 | |

| 3rd Quarter | | 2.99 | | | | 0.63 | | | | 48.19 | |

| 2nd Quarter | | 3.19 | | | | 0.55 | | | | 48.29 | |

| 1st Quarter | | 3.31 | | | | 0.61 | | | | 51.86 | |

| 2017 Average | | 3.11 | | | | 0.63 | | | | 50.93 | |

Export services are supported by fee-based contracts whose rates and terms are driven by global LPG demand fundamentals.

The fuel and power costs are pass-through elements in many of our logistics contracts, which mitigates their impact on our results.

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.

Crude oil, natural gas and NGL prices continued to decline in 2015 and remained depressed in 2016 before starting to recover in 2017.

Nevertheless, a change in unit fees due to market dynamics does affect profitability.

We define Adjusted EBITDA as net income (loss) available 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.

| Impairment of property, plant and equipment | | | 378.0 | | | | | — | | | | | 32.6 | |

______________

| (1) | Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments. |

| (3) | Risk management activities related to derivative instruments including the cash impact of hedges acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015. |

| (6) | 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 year ended December 31, 2017 also includes a refund of Texas margin tax paid in previous periods and received in 2017. |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| Depreciation and amortization expense | | | 809.5 | | | | | 757.7 | | | | | 644.5 | | | | | | 51.8 | | | | 7 | % | | | | | 113.2 | | | | 18 | % |

| Impairment of property, plant and equipment | | | 378.0 | | | | | — | | | | | 32.6 | | | | | | 378.0 | | | | — | | | | | | (32.6 | ) | | | (100 | %) |

| Change in contingent considerations | | | 99.6 | | | | | 0.4 | | | | | 1.2 | | | | | | 99.2 | | | NM | | | | | | | (0.8 | ) | | | (67 | %) |

| Other income (expense), net | | | (2.6 | ) | | | | 0.8 | | | | | (27.8 | ) | | | | | (3.4 | ) | | NM | | | | | | | 28.6 | | | | 103 | % |

| Crude oil gathered, Permian, MBbl/d (4) | | | 29.8 | | | | | — | | | | | — | | | | | | 29.8 | | | | — | | | | | | — | | | | — | |

| (2) | Includes the acquisition date fair value of the potential earn-out payments of $416.3 million that would occur in 2018 and 2019. |

| (4) | Includes operations from the Permian Acquisition for the period effective March 1, 2017. 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. |

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.

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, partially offset by lower professional services and insurance premiums.

The impairment of property, plant and equipment in 2017 reflects a third quarter 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.

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

On February 17, 2016, TRC completed its acquisition of all of the outstanding common units of the Partnership pursuant to the TRC/TRP Merger Agreement.

We issued 104,525,775 shares of common stock in exchange for all of the outstanding common units of the Partnership that we previously did not own.

As a result of the completion of the TRC/TRP Merger, the TRP common units are no longer publicly traded.

The Preferred Units remain outstanding as preferred limited partner interests in TRP and continue to trade on the NYSE under the symbol “NGLS PRA.”

As we continue to control the Partnership, the change in our ownership interest as a result of the TRC/TRP Merger was accounted for as an equity transaction and no gain or loss was recognized in our Consolidated Statements of Operations related to the Buy-in Transaction.

The equity interests in TRP (which are consolidated in our financial statements) that were owned by the public prior to February 17, 2016 are reflected within “noncontrolling interests” in our Consolidated Balance Sheets for periods prior to the merger date.

The earnings recorded by TRP that were attributed to its common units held by the public prior to February 17, 2016 are reflected within “Net income attributable to noncontrolling interests” in our Consolidated Statements of Operations for periods prior to the merger date.

Our Operations

| --- | --- | --- |

To provide these services, we operate in two primary segments (previously referred to as divisions): (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

Concurrent with the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure.

The Gathering and Processing division was previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing.

The Logistics and Marketing division was previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution.

The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted.

Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team.

Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling.

The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses.

The Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing operations and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington.

Other contains the results (including any hedge ineffectiveness) of our commodity derivative activities that are included in operating margin.

Volatility of Commodity Prices

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves.

Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels.

Prices of oil, natural gas and NGLs have been volatile, and we expect this volatility to continue.

Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related reduced activity levels from our customers.

Oil, natural gas and NGL prices continued to decline in 2015 and the first half of 2016, but have since experienced some recovery.

2016 Developments

Cedar Bayou Fractionator Train 5

In June 2016, we commissioned an additional fractionator, Train 5, at our 88%-owned CBF in Mont Belvieu, Texas.

This expansion added 100 MBbl/d of fractionation capacity at CBF, and is fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel.

The gross cost of Train 5 was approximately $331 million (our net cost was approximately $299 million).

Channelview Splitter

On December 27, 2015, we and Noble entered into the Splitter Agreement under which we will build the Channelview Splitter, which will have the capability to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components.

The Channelview Splitter is expected to be completed by early 2018, and has an estimated total cost of approximately $140 million.

As contemplated by the December 2014 Agreement, the Splitter Agreement completes and terminates the December 2014 Agreement, while retaining our economic benefits from that previous agreement.

The first annual payment due under the Splitter Agreement was received in October 2016 and is reflected as deferred revenue as a component of other long-term liabilities on our Consolidated Balance Sheet.

Gathering and Processing Segment Expansion

Eagle Ford Shale Natural Gas Gathering and Processing Joint Ventures

In October 2015, we announced that we had entered into the Carnero Joint Ventures with Sanchez to construct the Raptor Plant and approximately 45 miles of associated pipelines.

Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of [removed: operation.][added: operations.]

In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas equity volumes, NGL equity volumes and condensate equity volumes and future commodity purchases and sales through [removed: 2019.][added: 2020.]

[removed: The current market] [added: Market] conditions may also impact our ability to enter into future commodity derivative contracts.

The prices of natural [removed: gas and] [added: gas,] NGLs [added: and crude oil] are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control.

In an effort to reduce the variability of our cash flows, as of December 31, [removed: 2016,] [added: 2017,] we have hedged the commodity price associated with a portion of our expected (i) natural [removed: gas equity volumes in our Gathering and Processing operations, (ii) NGL] [added: gas, NGL,] and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements and [removed: (iii)] [added: (ii)] future commodity purchases and sales in our Logistics and Marketing segment by entering into derivative instruments.

Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in [removed: natural gas and NGL] [added: commodity] prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing the Partnership’s senior secured indebtedness that ranks equal in right of payment with liens granted in favor of the Partnership’s senior secured lenders.

Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in [removed: natural gas and NGL] [added: commodity] prices.

During the years ended December 31, [removed: 2016, 2015] [added: 2017, 2016] and [removed: 2014,] [added: 2015,] our operating revenues increased (decreased) by [removed: $40.1] [added: $(49.7)] million, [removed: $74.0] [added: $40.1] million, and [removed: $(9.6)] [added: $74.0] million, respectively, as a result of transactions accounted for as derivatives.

Our risk management position has moved from a net [removed: asset] [added: liability] position of [removed: $119.5] [added: $53.3] million at December 31, [removed: 2015] [added: 2016] to a net liability position of [removed: $53.3] [added: $38.2] million at December 31, [removed: 2016.][added: 2017.]

As of December 31, [removed: 2016,] [added: 2017,] we had the following derivative instruments that will settle during the years [removed: ending] [added: shown] below:

| | | | | | | | | [removed: 2017] [added: 2018] | | | | [removed: 2018] [added: 2019] | | | | [removed: 2019] [added: 2020] | | | | (In millions) | | |

| Swap | [removed: IF-PB] [added: NC4-OPIS-MB] | | [removed: 2.51] [added: 0.7718] | | | | | | \- | | | | [removed: 10,900] [added: 900] | | | | \- | | | | (1.2 | ) |

| | | | | | | | | | [removed: 10,900] [added: 45,900] | | | | [removed: 10,900] [added: 35,000] | | | | \- | | | | | |

| Swap | C2-OPIS-MB | | 0.2959 | | | | | | \- | | | | [removed: \-] [added: 4,030] | | | | [removed: 1,210] | | | | [removed: (0.8] [added: (0.9] | ) |

| Swap | [removed: C3-OPIS-MB] [added: C2-OPIS-MB] | | [removed: 0.6649] [added: 0.2839] | | | | | | [removed: 3,908] [added: 4,688] | | | | \- | | | | \- | | | [added: $] | [removed: (0.9] [added: 0.9] | [removed: )] |

| Swap | IC4-OPIS-MB | | [removed: 0.8037] [added: 0.7814] | | | | | | [removed: 370] [added: \-] | | | | [removed: \-] [added: 320] | | | | \- | | | | (0.4 | ) |

| Total | | | | | | | | | [removed: 800] [added: 300] | | | | 300 | | | | \- | | | | | |

| Collar | C5-OPIS-MB | | 1.230 | | | 1.385 | | | [removed: \-] [added: 32] | | | | [removed: 32] [added: \-] | | | | \- | | | | [removed: 0.0] [added: (0.0] | [added: )] |

| Future | [removed: C2-OPIS-MB] [added: IC4-OPIS-MB] | | [removed: 0.3021] [added: 0.7825] | | | | | | [removed: \-] [added: 55] | | | | [removed: 959] [added: \-] | | | | \- | | | | (0.3 | ) |

| Future | [removed: NC4-OPIS-MB] [added: C2-OPIS-MB] | | [removed: 0.9700] [added: 0.3138] | | | | | | [removed: (68] [added: \-] | [removed: )] | | | [removed: \-] [added: 329] | | | | \- | | | | [removed: (0.0] [added: 0.0] | [removed: )] |

| Option | C2-OPIS-MB | | 0.2963 | | | | | | [removed: \-] [added: 1,644] | | | | [removed: 1,644] [added: \-] | | | | \- | | | | [removed: 0.6] [added: 1.4] | |

| Collar | WTI-NYMEX | | 49.76 | | | 58.50 | | | [removed: \-] [added: 691] | | | | [removed: 691] [added: \-] | | | | \- | | | | [removed: (0.5] [added: (0.9] | ) |

| Collar | WTI-NYMEX | | 48.00 | | | 56.25 | | | \- | | | | [removed: \-] [added: 590] | | | | [removed: 590] [added: \-] | | | | [removed: (0.7] [added: (0.6] | ) |

| | | | | | | | | | [removed: 1,380] [added: 691] | | | | [removed: 691] [added: 590] | | | | [removed: 590] [added: \-] | | | | | |

As of December 31, [removed: 2016,] [added: 2017,] we do not have any interest rate hedges.

To the extent that interest rates increase, interest expense for the TRC Revolver, [added: the] TRP Revolver and the Securitization Facility will also increase.

As of December 31, [removed: 2016,] [added: 2017,] the Partnership had [removed: $425.0] [added: $370.0] million in outstanding variable rate borrowings under the TRP Revolver and [added: the] Securitization Facility, and we had outstanding variable rate borrowings of [removed: $275.0] [added: $435.0] million under the TRC [removed: Revolver and $160.0 million under our term loan facility.][added: Revolver.]

A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact the Partnership’s annual interest expense by [removed: $4.3] [added: $3.7] million and our consolidated annual interest expense by [removed: $8.6] [added: $8.1] million.

These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by [removed: $21.9] [added: $61.1] million as of December 31, [removed: 2016.][added: 2017.]

The range of losses attributable to our individual counterparties would be between [removed: $1.3] [added: $0.6] million and [removed: $3.8] [added: $22.0] million, depending on the counterparty in default.

We have an established policy and various procedures to manage our credit exposure risk, including [added: performing] initial and subsequent credit risk analyses, [added: setting maximum] credit limits and terms and [added: requiring] credit enhancements when necessary.

If an assessment of uncollectible accounts resulted in a 1% reduction of our third-party accounts receivable as of December 31, [removed: 2016,] [added: 2017,] our operating income would decrease by [removed: $6.7] [added: $8.3] million in the year of the assessment.

| Swap | IF-Waha | | 2.6470 | | | | | | 93,600 | | | | \- | | | | \- | | | $ | 17.4 | |

| Swap | IF-Waha | | 2.6327 | | | | | | \- | | | | 65,383 | | | | \- | | | | 14.6 | |

| | | | | | | | | | 93,600 | | | | 65,383 | | | | \- | | | | | |

| Swap | IF-PB | | 2.4802 | | | | | | 45,900 | | | | \- | | | | \- | | | | 7.0 | |

| Swap | IF-PB | | 2.3700 | | | | | | \- | | | | 35,000 | | | | \- | | | | 5.1 | |

| Swap | IF-PEPL | | 2.5960 | | | | | | 31,370 | | | | \- | | | | \- | | | | 3.3 | |

| Swap | IF-PEPL | | 2.5333 | | | | | | \- | | | | 31,370 | | | | \- | | | | 2.8 | |

| | | | | | | | | | 31,370 | | | | 31,370 | | | | \- | | | | | |

| Collar | IF-Waha | | 3.2500 | | | 4.2000 | | | 1,849 | | | | \- | | | | \- | | | | 0.6 | |

| Collar | IF-PB | | 3.0000 | | | 3.6500 | | | 7,637 | | | | \- | | | | \- | | | | 2.5 | |

| Gathering & Processing total | | | | | | | | | 180,356 | | | | 131,753 | | | | \- | | | $ | 53.3 | |

| Swap | NG-NYMEX | | 3.1579 | | | | | | (173 | ) | | | \- | | | | \- | | | $ | (0.0 | ) |

| Swap | NG-NYMEX | | 2.8367 | | | | | | \- | | | | (247 | ) | | | \- | | | | (0.0 | ) |

| | | | | | | | | | (173 | ) | | | (247 | ) | | | \- | | | | | |

| Swap | IF-Waha | | 3.0589 | | | | | | (4,227 | ) | | | \- | | | | \- | | | | (1.0 | ) |

| Basis Swap | Various | Various | | | | | | | 99,521 | | | | 12,500 | | | | 10,417 | | | | (2.7 | ) |

| Future | Various | | 3.2787 | | | | | | 466 | | | | \- | | | | \- | | | | 0.1 | |

| Other total | | | | | | | | | 95,587 | | | | 12,253 | | | | 10,417 | | | $ | (3.6 | ) |

| | | | | | | | | | | | | | | | | | | | | $ | 49.7 | |

________________________________________________

| | | | | | | | | 2018 | | | | 2019 | | | | 2020 | | | | (In millions) | | |

| Swap | C2-OPIS-MB | | 0.3005 | | | | | | \- | | | | | | | | 427 | | | | (0.1 | ) |

| Total | | | | | | | | | 4,688 | | | | 4,030 | | | | 427 | | | | | |

| Swap | C3-OPIS-MB | | 0.6950 | | | | | | 8,620 | | | | \- | | | | \- | | | | (20.3 | ) |

| Swap | C3-OPIS-MB | | 0.6060 | | | | | | \- | | | | 3,780 | | | | \- | | | | (8.2 | ) |

| Total | | | | | | | | | 8,620 | | | | 3,780 | | | | \- | | | | | |

| Swap | IC4-OPIS-MB | | 0.8671 | | | | | | 1,050 | | | | \- | | | | \- | | | | (1.7 | ) |

| Total | | | | | | | | | 1,050 | | | | 320 | | | | \- | | | | | |

| Swap | NC4-OPIS-MB | | 0.8608 | | | | | | 2,950 | | | | \- | | | | \- | | | | (4.8 | ) |

| Total | | | | | | | | | 2,950 | | | | 900 | | | | \- | | | | | |

| Swap | C5-OPIS-MB | | 1.1600 | | | | | | 1,990 | | | | \- | | | | \- | | | | (6.5 | ) |

| Swap | C5-OPIS-MB | | 1.0935 | | | | | | \- | | | | 859 | | | | \- | | | | (2.4 | ) |

| Total | | | | | | | | | 1,990 | | | | 859 | | | | \- | | | | | |

| Collar | C3-OPIS-MB | | 0.530 | | | 0.650 | | | 900 | | | | \- | | | | \- | | | | (2.9 | ) |

| Collar | IC4-OPIS-MB | | 0.650 | | | 0.840 | | | 110 | | | | \- | | | | \- | | | | (0.3 | ) |

| Collar | IC4-OPIS-MB | | 0.640 | | | 0.800 | | | \- | | | | 110 | | | | \- | | | | (0.3 | ) |

| Total | | | | | | | | | 110 | | | | 110 | | | | \- | | | | | |

| Collar | NC4-OPIS-MB | | 0.650 | | | 0.800 | | | 300 | | | | \- | | | | \- | | | | (0.9 | ) |

| Collar | NC4-OPIS-MB | | 0.640 | | | 0.760 | | | \- | | | | 300 | | | | \- | | | | (0.7 | ) |

| Gathering & Processing total | | | | | | | | | 20,640 | | | | 10,299 | | | | 427 | | | $ | (50.7 | ) |

| Instrument | | Price | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| Gathering & Processing | | | | | | | | | | | | | | | | | | | | | | |

| Swap | IF-Waha | | 2.93 | | | | | | 87,900 | | | | \- | | | | \- | | | | (15.1 | ) |

| Swap | IF-Waha | | 2.71 | | | | | | \- | | | | 57,900 | | | | \- | | | | (5.2 | ) |

| Swap | IF-Waha | | 2.87 | | | | | | \- | | | | \- | | | | 29,683 | | | | 1.7 | |

| | | | | | | | | | 87,900 | | | | 57,900 | | | | 29,683 | | | | | |

| Swap | IF-PB | | 2.51 | | | | | | 10,900 | | | | \- | | | | \- | | | | (3.3 | ) |

| Swap | IF-PEPL | | 2.6835 | | | | | | 16,000 | | | | \- | | | | \- | | | | (4.0 | ) |

| Swap | IF-PEPL | | 2.6835 | | | | | | \- | | | | 16,000 | | | | \- | | | | (0.8 | ) |

| Swap | IF-PEPL | | 2.6835 | | | | | | \- | | | | \- | | | | 16,000 | | | | 0.8 | |

| | | | | | | | | | 16,000 | | | | 16,000 | | | | 16,000 | | | | | |

| Swap | NG-NYMEX | | 4.11 | | | | | | 18,082 | | | | \- | | | | \- | | | | 2.8 | |

| Collar | IF-Waha | | 3.00 | | | 3.67 | | | 7,500 | | | | \- | | | | \- | | | | (0.2 | ) |

| Collar | IF-Waha | | 3.25 | | | 4.20 | | | \- | | | | 1,849 | | | | \- | | | | 0.0 | |

| | | | | | | | | | 7,500 | | | | 1,849 | | | | \- | | | | | |

| Collar | IF-PB | | 2.80 | | | 3.50 | | | 15,400 | | | | \- | | | | \- | | | | (0.7 | ) |

| Collar | IF-PB | | 3.00 | | | 3.65 | | | \- | | | | 7,637 | | | | \- | | | | 0.6 | |

| | | | | | | | | | 15,400 | | | | 7,637 | | | | \- | | | | | |

| Basis Swap | EP-PERMIAN | | (0.1444 | ) | | | | | 9,041 | | | | \- | | | | \- | | | | 0.5 | |

| Basis Swap | PEPL | | (0.3308 | ) | | | | | 9,041 | | | | \- | | | | \- | | | | (0.3 | ) |

| Gathering & Processing total | | | | | | | | | 173,864 | | | | 94,286 | | | | 45,683 | | | | (24.4 | ) |

| Swap | NG-NYMEX | | 3.1680 | | | | | | 566 | | | | \- | | | | \- | | | $ | 0.1 | |

| Basis Swap | Various | | (0.1077 | ) | | | | | 54,137 | | | | \- | | | | \- | | | | (0.4 | ) |

| Other total | | | | | | | | | 54,703 | | | | \- | | | | \- | | | $ | (0.3 | ) |

| | | | | | | | | | | | | | | | | | | | | $ | (24.7 | ) |

| Type | Index | $/gal | | | | | | Bbl/d | | | | | | | | | | | | Fair Value | | |

| Swap | C2-OPIS-MB | | 0.2697 | | | | | | 3,407 | | | | \- | | | | \- | | | | (1.2 | ) |

| Swap | C2-OPIS-MB | | 0.2752 | | | | | | \- | | | | 1,868 | | | | \- | | | | (1.1 | ) |

| Total | | | | | | | | | 3,407 | | | | 1,868 | | | | 1,210 | | | | | |

| Swap | C3-OPIS-MB | | 0.5540 | | | | | | \- | | | | 1,750 | | | | \- | | | | (2.9 | ) |

| Swap | C3-OPIS-MB | | 0.5540 | | | | | | \- | | | | \- | | | | 1,750 | | | | (2.5 | ) |

| Total | | | | | | | | | 3,908 | | | | 1,750 | | | | 1,750 | | | | | |

| Swap | IC4-OPIS-MB | | 0.7750 | | | | | | \- | | | | 120 | | | | \- | | | | (0.1 | ) |

| Total | | | | | | | | | 370 | | | | 120 | | | | \- | | | | | |

| Swap | NC4-OPIS-MB | | 0.7944 | | | | | | 800 | | | | \- | | | | \- | | | | (0.7 | ) |

| Swap | NC4-OPIS-MB | | 0.7725 | | | | | | \- | | | | 300 | | | | \- | | | | (0.2 | ) |

| Swap | C5-OPIS-MB | | 1.0976 | | | | | | 1,150 | | | | \- | | | | \- | | | | (2.0 | ) |

| Swap | C5-OPIS-MB | | 1.0400 | | | | | | \- | | | | 650 | | | | \- | | | | (1.7 | ) |

| Swap | C5-OPIS-MB | | 1.1020 | | | | | | \- | | | | \- | | | | 409 | | | | (0.7 | ) |

| | | December 31, [removed: 2016 | | | | December 31,] 2015 | | |

| Cash and cash equivalents | | $ | [removed: 73.5] [added: 137.2] | | | $ | [removed: 140.2] [added: 73.5] | |

| Trade receivables, net of allowances of [removed: $0.9 and] $0.1 [added: and $0.9] million at December 31, [removed: 2016] [added: 2017] and [removed: 2015] [added: December 31, 2016] | | | [removed: 674.6] [added: 827.6] | | | | [removed: 515.8] [added: 674.6] | |

| Inventories | | | [removed: 137.7] [added: 204.5] | | | | [removed: 141.0] [added: 137.7] | |

| Assets from risk management activities | | | [removed: 16.8] [added: 37.9] | | | | [removed: 92.2] [added: 16.8] | |

| Income tax receivable | | | [removed: 67.8] [added: —] | | | | [removed: 13.5] [added: 67.8] | |

| Other current assets | | | [removed: 36.4] [added: 62.7] | | | | [removed: 17.3] [added: 36.4] | |

| Total current assets | | | [removed: 1,006.8] [added: 1,269.9] | | | | [removed: 920.0] [added: 1,006.8] | |

| Property, plant and equipment | | | [removed: 12,518.7] [added: 14,205.4] | | | | [removed: 11,935.1] [added: 12,518.7] | |

| Accumulated depreciation | | | [removed: (2,827.7] [added: (3,775.4] | ) | | | [removed: (2,232.4] [added: (2,827.7] | ) |

| Property, plant and equipment, net | | | [removed: 9,691.0] [added: 10,430.0] | | | | [removed: 9,702.7] [added: 9,691.0] | |

| Intangible assets, net | | | [removed: 1,654.0] [added: 2,165.8] | | | | [removed: 1,810.1] [added: 1,654.0] | |

| Goodwill, net | | | [removed: 210.0] [added: 256.6] | | | | [removed: 417.0] [added: 210.0] | |

| Long-term assets from risk management activities | | | [removed: 5.1] [added: 23.2] | | | | [removed: 34.9] [added: 5.1] | |

| Investments in unconsolidated affiliates | | | [removed: 240.8] [added: 221.6] | | | | [removed: 258.9] [added: 240.8] | |

| Other long-term assets | | | [removed: 63.5] [added: 21.5] | | | | [removed: 67.4] [added: 63.5] | |

| Total assets | | $ | [removed: 12,871.2] [added: 14,388.6] | | | $ | [removed: 13,211.0] [added: 12,871.2] | |

| Accounts payable and accrued liabilities | | $ | [removed: 843.5] [added: 1,186.9] | | | $ | [removed: 650.4] [added: 843.5] | |

| Liabilities from risk management activities | | | [removed: 49.1] [added: 79.7] | | | | [removed: 5.2] [added: 49.1] | |

| Accounts receivable securitization [removed: facility] [added: facility, due December 2018] | | [added: $] | [removed: 275.0] [added: 350.0] | | | [added: $] | [removed: 219.3] [added: 275.0] | |

| Total current liabilities | | | [removed: 1,167.6] [added: 1,616.6] | | | | [removed: 874.9] [added: 1,167.6] | |

| Long-term debt | | | [removed: 4,606.0] [added: 4,703.0] | | | | [removed: 5,718.8] [added: 4,606.0] | |

| Long-term liabilities from risk management activities | | | [removed: 26.1] [added: 19.6] | | | | [removed: 2.4] [added: 26.1] | |

| Deferred income taxes, net | | | [removed: 941.2] [added: 479.0] | | | | [removed: 177.8] [added: 941.2] | |

| Other long-term liabilities | | | [removed: 215.1] [added: 597.9] | | | | [removed: 186.9] [added: 215.1] | |

| Series A Preferred 9.5% Stock, $1,000 per share liquidation preference, (1,200,000 shares authorized, issued and outstanding 965,100 shares), net of discount (see Note 12) | | | [removed: 190.8] [added: 216.5] | | | | [removed: —] [added: 190.8] | |

| Common stock ($0.001 par value, 300,000,000 shares authorized) | | | 0.2 | | | | [removed: 0.1] [added: 0.2] | |

| Additional paid-in capital | | | [removed: 5,506.2] [added: 6,302.8] | | | | [removed: 1,457.4] [added: 5,506.2] | |

| Retained earnings (deficit) | | | [removed: (187.3] [added: (77.2] | ) | | | [removed: 26.9] [added: (187.3] | [added: )] |

| Accumulated other comprehensive income (loss) | | | [removed: (38.3] [added: (29.9] | ) | | | [removed: 5.7] [added: (38.3] | [added: )] |

| Treasury stock, at cost [removed: (513,880] [added: (585,640] shares as of December 31, [removed: 2016] [added: 2017] and [removed: 426,307] [added: 513,880] as of December 31, [removed: 2015)] [added: 2016)] | | | [removed: (32.2] [added: (35.6] | ) | | | [removed: (28.7] [added: (32.2] | ) |

| Total Targa Resources Corp. stockholders' equity | | | [removed: 5,248.6] [added: 6,160.3] | | | | [removed: 1,461.4] [added: 5,248.6] | |

| Noncontrolling interests in subsidiaries | | | [removed: 475.8] [added: 595.7] | | | | [removed: 4,788.8] [added: 475.8] | |

| Total owners' equity | | | [removed: 5,724.4] [added: 6,756.0] | | | | [removed: 6,250.2] [added: 5,724.4] | |

| Total liabilities, Series A Preferred Stock and owners' equity | | $ | [removed: 12,871.2] [added: 14,388.6] | | | $ | [removed: 13,211.0] [added: 12,871.2] | |

| | | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | |

| [removed: Revenues] [added: Revenues:] | | | | | | | | | | | | |

| Sales of commodities | | $ | [removed: 5,626.8] [added: 7,751.1] | | | $ | [removed: 5,465.4] [added: 5,626.8] | | | $ | [removed: 7,595.2] [added: 5,465.4] | |

| Fees from midstream services | | | [removed: 1,064.1] [added: 1,063.8] | | | | [removed: 1,193.2] [added: 1,064.1] | | | | [removed: 1,021.3] [added: 1,193.2] | |

| Total revenues | | | [removed: 6,690.9] [added: 8,814.9] | | | | [removed: 6,658.6] [added: 6,690.9] | | | | [removed: 8,616.5] [added: 6,658.6] | |

| | | December 31, 2017 | | | | December 31, 2016 | | |

| Current debt obligations | | | 350.0 | | | | 275.0 | |

| December 31, 2017 218,152,620 217,566,980 | | | | | | | | |

| Impairment of property, plant and equipment | | | 378.0 | | | | — | | | | 32.6 | |

| Change in contingent considerations | | | 99.6 | | | | 0.4 | | | | 1.2 | |

| Other, net | | | (2.6 | ) | | | 0.8 | | | | (27.8 | ) |

| Dividends per common share declared for the period | | $ | 3.64 | | | $ | 3.64 | | | $ | 3.39 | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | | | | | | | | | | Retained | | | | | Accumulated | | | | | | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | | | | | Additional | | | | | Earnings | | | | | Other | | | | Treasury | | | | | | | | | | | | | | | Total | | | | Series A | | |

| | | Common Stock | | | | | | | | | | Paid in | | | | | (Accumulated | | | | | Comprehensive | | | | Shares | | | | | | | | | | Noncontrolling | | | | | Owner's | | | | Preferred | | |

| | | Shares | | | | | Amount | | | | | Capital | | | | | Deficit) | | | | | Income (Loss) | | | | Shares | | | | | Amount | | | | | Interests | | | | | Equity | | | | Stock | | |

| | | (In millions, except shares in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Balance, December 31, 2016 | | | 184,721 | | | | $ | 0.2 | | | | $ | 5,506.2 | | | | $ | (187.3 | ) | | | $ | (38.3 | ) | | | 514 | | | | $ | (32.2 | ) | | | $ | 475.8 | | | | $ | 5,724.4 | | | $ | 190.8 | |

| Impact of accounting standard adoption (see Note 3) | | | — | | | | | — | | | | | — | | | | | 56.1 | | | | | — | | | | — | | | | | — | | | | | — | | | | | 56.1 | | | | — | |

| Series A Preferred Stock dividends | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Dividends | | | — | | | | | — | | | | | — | | | | | (91.7 | ) | | | | — | | | | — | | | | | — | | | | | — | | | | | (91.7 | ) | | | — | |

| Deemed dividends - accretion of beneficial conversion feature | | | — | | | | | — | | | | | (25.7 | ) | | | | — | | | | | — | | | | — | | | | | — | | | | | — | | | | | (25.7 | ) | | | 25.7 | |

| Common stock dividends | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Dividends | | | — | | | | | — | | | | | — | | | | | (749.4 | ) | | | | — | | | | — | | | | | — | | | | | — | | | | | (749.4 | ) | | | — | |

| Dividends in excess of retained earnings | | | — | | | | | — | | | | | (749.4 | ) | | | | 749.4 | | | | | — | | | | — | | | | | — | | | | | — | | | | | — | | | | — | |

| Contributions from noncontrolling interests | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | — | | | | | — | | | | | 141.6 | | | | | 141.6 | | | | — | |

| Purchase of noncontrolling interests in subsidiaries, net of tax impact | | | — | | | | | — | | | | | (13.6 | ) | | | | — | | | | | — | | | | — | | | | | — | | | | | (12.5 | ) | | | | (26.1 | ) | | | — | |

| Net income (loss) | | | — | | | | | — | | | | | — | | | | | 54.0 | | | | | — | | | | — | | | | | — | | | | | 50.2 | | | | | 104.2 | | | | — | |

| Balance, December 31, 2017 | | | 217,567 | | | | $ | 0.2 | | | | $ | 6,302.8 | | | | $ | (77.2 | ) | | | $ | (29.9 | ) | | | 586 | | | | $ | (35.6 | ) | | | $ | 595.7 | | | | $ | 6,756.0 | | | $ | 216.5 | |

| Impairment of property, plant and equipment | | | 378.0 | | | | — | | | | 32.6 | |

| Change in contingent considerations included in Other expense (income) | | | (99.6 | ) | | | (0.4 | ) | | | (1.2 | ) |

| Other, net | | | — | | | | (0.3 | ) | | | (1.7 | ) |

On February 6, 2018, we announced the formation of three development joint ventures (the “DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”).

Stonepeak will own an 80% interest in both the GCX DevCo JV, which will own our 25% interest in the Gulf Coast Express Pipeline (“GCX”), and the Fractionation DevCo JV, which will own a 100% interest in some of the assets associated with a newly announced 100 MBbl/d fractionation train in Mont Belvieu, Texas, expected to begin operations in the first quarter of 2019.

Stonepeak will own a 95% interest in the Grand Prix DevCo JV, which will own a 20% interest in the Grand Prix pipeline (“Grand Prix”).

We will hold the remaining interest of the DevCo JVs as well as control the management, construction and operation of Grand Prix and fractionation train.

For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, Targa has the option to acquire all or part of Stonepeak’s interests in the DevCo JVs.

Targa may acquire up to 50% of Stonepeak’s invested capital in multiple increments with a minimum of $100 million, and would be required to buy Stonepeak’s remaining 50% interest in a single final purchase.

We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable.

Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment.

When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within equity earnings (loss) in our Consolidated Statements of Operations.

Prior to our adoption of ASU 2017-04 (see “Recent Accounting Pronouncements”), if a reporting unit’s carrying amount exceeded the reporting unit’s fair value, we then compared the implied fair value of goodwill to its carrying value.

| | | | | | | | | |

| December 31, 2015 56,446,573 56,020,266 | | | | | | | | |

F-4

| Other | | | 1.2 | | | | (26.6 | ) | | | (8.0 | ) |

| Interest rate swaps: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Settlements reclassified to interest expense, net | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 0.3 | | | | (0.1 | ) | | | 0.2 | |

| Change in fair value | | | 23.7 | | | | — | | | | 23.7 | | | | 101.7 | | | | — | | | | 101.7 | | | | 52.2 | | | | — | | | | 52.2 | |

| Settlements reclassified to interest expense, net | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 2.1 | | | | — | | | | 2.1 | |

| Settlements reclassified to interest expense, net | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 2.4 | | | | (0.1 | ) | | | 2.3 | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Balance, December 31, 2013 | | | 42,162 | | | $ | — | | | $ | 151.6 | | | $ | 20.5 | | | $ | (0.5 | ) | | | 367 | | | $ | (22.8 | ) | | $ | 1,942.5 | | | $ | 2,091.3 | | | $ | — | |

| Dividends | | | — | | | | — | | | | — | | | | (113.1 | ) | | | — | | | | — | | | | — | | | | — | | | | (113.1 | ) | | | — | |

| Distributions | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (339.8 | ) | | | (339.8 | ) | | | — | |

| Net income | | | — | | | | — | | | | — | | | | 102.3 | | | | — | | | | — | | | | — | | | | 320.7 | | | | 423.0 | | | | — | |

| Sale of Partnership limited partner interests | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 436.0 | | | | 436.0 | | | | — | |

| Impact of subsidiary equity transactions | | | — | | | | — | | | | 56.8 | | | | — | | | | — | | | | — | | | | — | | | | (56.8 | ) | | | — | | | | — | |

| Payments of distribution equivalent rights | | | (0.3 | ) | | | (2.8 | ) | | | (1.6 | ) |

Partnership that we previously did not own.

Change in Reportable Segments

Concurrent with the TRC/TRP Merger in February 2016, management reevaluated our reportable segments.

See “Segment Information” included in Note 26 for a presentation of financial results by reportable segment, which have been recast to reflect our change in reporting segments for all periods presented.

Revisions of Previously Reported Activity in our Consolidated Statements of Comprehensive Income (Loss)

During the first quarter of 2016 we concluded that activity related to our commodity hedge contracts was not reported properly in our Consolidated Statements of Comprehensive Income (Loss) during 2015.

The errors resulted in misstatements of the statement caption “Change in fair value” and equal offsetting misstatements of the caption “Settlements reclassified to revenues.” Related income tax effects were also misstated.

The reported beginning and ending balance sheet values of Accumulated Other Comprehensive Income were unaffected.

We concluded that these misstatements were not material to any of the periods affected, as reported “Total Other Comprehensive Income” is unchanged.

However, we have revised previous Consolidated Statements of Comprehensive Income (Loss) reported during 2015 to properly reflect changes in fair value and settlements reclassified to revenues.

There is no impact on previously reported net income, total comprehensive income, cash flows, financial position or other profitability measures.

The following table displays the impact of these revisions to activity reported in our Consolidated Statements of Comprehensive Income (Loss) during the year ended December 31, 2015:

| | | As Reported | | | | | | | | | | | | As Corrected | | | | | | | | | | |

| | | Pre-Tax | | | | Related Income Tax | | | | After Tax | | | | Pre-Tax | | | | Related Income Tax | | | | After Tax | | |

| Commodity hedging contracts: | | | | | | | | | | | | | | | | | | | | | | | | |

| Change in fair value | $ | | 7.4 | | $ | | (2.8 | ) | $ | | 4.6 | | $ | | 11.0 | | $ | | (4.2 | ) | $ | | 6.8 | |

| Settlements reclassified to revenues | | | (5.9 | ) | | | 2.2 | | | | (3.7 | ) | | | (9.5 | ) | | | 3.6 | | | | (5.9 | ) |

| | | | | | | | | | | | | | | | | | | | | | | | | |

| Change in fair value | | | 73.8 | | | | \- | | | | 73.8 | | | | 101.7 | | | | \- | | | | 101.7 | |

| Settlements reclassified to revenues | | | (48.9 | ) | | | \- | | | | (48.9 | ) | | | (76.8 | ) | | | \- | | | | (76.8 | ) |

| Other comprehensive income (loss) attributable to noncontrolling interests | | | 24.9 | | | | \- | | | | 24.9 | | | | 24.9 | | | | \- | | | | 24.9 | |

| Change in fair value | | | 81.2 | | | | (2.8 | ) | | | 78.4 | | | | 112.7 | | | | (4.2 | ) | | | 108.5 | |

The information required by this item is included in Note 20 – Contingencies in our Consolidated Financial Statements, and is incorporated herein by reference thereto.

Litigation related to TRC/TRP Merger

On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), Targa Resources GP LLC (“TRP GP”), the members of the board of TRP GP (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”).

This lawsuit was styled Leslie Blumberg et al.

v.

TRC Resources Corp., et al., Cause No. 2015-75481, in the 234th Judicial District Court of Harris County, Texas (the “State Court Lawsuit”).

The State Court Plaintiffs amended the State Court Lawsuit on July 26, 2016.

The State Court Plaintiffs alleged several causes of action challenging the TRC/TRP Merger.

Generally, the State Court Plaintiffs alleged that (i) the members of the TRP GP Board breached express and/or implied duties under the Partnership Agreement and (ii) TRC, TRP GP, and Merger Sub aided and abetted in these alleged breaches of duties.

The State Court Plaintiffs further alleged, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair, (e) the TRP GP Board had conflicts of interest due to TRC’s control of TRP GP, (f) the TRP GP Conflicts Committee’s financial advisor was conflicted and conducted flawed analyses, and (g) the joint proxy statement/prospectus filed in connection with the TRC/TRP Merger (the “Proxy”) failed to disclose allegedly material information concerning, among other things, (i) the TRC and TRP projections included in the Proxy, and (ii) the analyses conducted by the TRP GP Conflicts Committee’s financial advisor in connection with the TRC/TRP Merger.

Based on these allegations, the State Court Plaintiffs sought damages and attorneys’ fees.

On February 26 and 29, 2016, the State Court Defendants filed general denials and asserted affirmative defenses.

On August 26, 2016, the State Court Defendants filed Special Exceptions and a Motion for Summary Judgment.

On December 5, 2016, the Court granted Defendants’ Motion for Summary Judgment and dismissed the State Court Lawsuit in its entirety with prejudice.

Environmental Proceedings

On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014.

The Monument Gas Plant is owned by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A. Inc. The Partnership has been in discussions with the New Mexico Environment Department to resolve the alleged violations.

The New Mexico Environment Department has offered to settle the matter for $29,223.

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

10-K 1 [removed: trgp-10k_20161231.htm FORM] [added: trgp-10k_20171231.htm] 10-K

For the fiscal year ended December 31, [removed: 2016][added: 2017]

[removed: ][added: ]

| [removed: 1000] [added: 811] Louisiana St, Suite [removed: 4300,] [added: 2100,] Houston, Texas | | 77002 |

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, [removed: or a] smaller reporting [added: company, or an emerging growth] company.

See the definitions of “large accelerated filer,” “accelerated [removed: filer” and] [added: filer”,] “smaller reporting company” [added: and “emerging growth company”] in Rule 12b-2 of the Exchange Act.

The aggregate market value of the common stock held by non-affiliates of the registrant was approximately [removed: $6,774.8] [added: $9,571.8] million on June 30, [removed: 2016,] [added: 2017,] based on [removed: $42.14] [added: $45.20] per share, the closing price of the common stock as reported on the New York Stock Exchange (NYSE) on such date.

As of February [removed: 10, 2017,] [added: 12, 2018,] there were [removed: 193,949,450] [added: 218,830,282] shares of the registrant’s common stock, $0.001 par value, outstanding.

| [Item 1A. Risk Factors.](#ITEM_1A_RISK_FACTORS) | [removed: 30] [added: 33] |

| [Item 1B. Unresolved Staff Comments.](#ITEM_1B_UNRESOLVED_STAFF_COMMENTS) | [removed: 47] [added: 52] |

| [Item 2. Properties.](#ITEM_2_PROPERTIES) | [removed: 47] [added: 52] |

| [Item 3. Legal Proceedings.](#ITEM_3_LEGAL_PROCEEDINGS) | [removed: 48] [added: 52] |

| [Item 4. Mine Safety Disclosures.](#ITEM_4_MINE_SAFETY_PART_1) | [removed: 48] [added: 52] |

| [Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.](#ITEM_5_MARKET_FOR_REGISTRANTS_COMMON_EQU) | [removed: 49] [added: 53] |

| [Item 6. Selected Financial Data.](#ITEM_6_SELECTED_FINANCIAL_DATA) | [removed: 53] [added: 57] |

| [Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.](#ITEM_7_MANAGEMENTS_DISCUSSION_ANALYSIS_F) | [removed: 54] [added: 58] |

| [Item 7A. Quantitative and Qualitative Disclosures About Market Risk.](#ITEM_7A_QUANTITATIVE_QUALITATIVE_DISCLOS) | [removed: 82] [added: 83] |

| [Item 8. Financial Statements and Supplementary Data.](#ITEM_8_FINANCIAL_STATEMENTS_SUPPLEMENTAR) | [removed: 87] [added: 89] |

| [Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.](#ITEM_9_CHANGES_IN_DISAGREEMENTS_WITH_ACC) | [removed: 87] [added: 89] |

| [Item 9A. Controls and Procedures.](#ITEM_9A_CONTROLS_PROCEDURES) | [removed: 87] [added: 89] |

| [Item 9B. Other Information.](#ITEM_9B_OR_INFORMATION) | [removed: 88] [added: 89] |

| [Item 10. Directors, Executive Officers and Corporate Governance.](#ITEM_10_DIRECTORS_EXECUTIVE_FICERS_CORPO) | [removed: 89] [added: 90] |

| [Item 11. Executive Compensation.](#ITEM_11_EXECUTIVE_COMPENSATION) | [removed: 95] [added: 96] |

| [Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.](#ITEM_12_SECURITY_OWNERSHIP_CERTAIN_BENEF) | [removed: 123] [added: 129] |

| [Item 13. Certain Relationships and Related Transactions, and Director Independence.](#ITEM_13_CERTAIN_RELATIONSHIPS_RELATED_TR) | [removed: 125] [added: 130] |

| [Item 14. Principal Accounting Fees and Services.](#ITEM_14_PRINCIPAL_ACCOUNTING_FEES_SERVIC) | [removed: 128] [added: 134] |

| [Item 15. Exhibits, Financial Statement Schedules.](#ITEM_15_EXHIBITS_FINANCIAL_STATEMENT_SCH) | [removed: 130] [added: 135] |

| [Item 16. Form 10-K Summary.](#ITEM_16_FORM_10K_SUMMARY) | [removed: 140] [added: 145] |

| | • | the timing and extent of changes in natural gas, natural gas [removed: liquids (“NGL”),] [added: liquids,] crude oil and other commodity prices, interest rates and demand for our services; |

| | • | the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and [removed: NGL] [added: natural gas liquid] supplies to our logistics and marketing facilities and our success in connecting our facilities to transportation services and markets; |

We own, operate, [added: acquire,] and develop a diversified portfolio of complementary midstream energy assets.

On February 17, 2016, TRC completed its acquisition of all of the outstanding common units of Targa Resources Partners LP [removed: (NYSE:NGLS)] [added: (NYSE: NGLS),] pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transaction, the “TRC/TRP Merger” or “Buy-in Transaction”).

The Partnership’s 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as [added: preferred] limited partner interests in TRP and continue to trade on the New York Stock Exchange (“NYSE”) under the symbol “NGLS [removed: PRA”.][added: PRA.” TRC also maintains a 2% general partner interest in the Partnership.]

[removed: You] [added: The following] should [added: be] read [removed: the following] in conjunction with our audited consolidated financial statements and the notes thereto.

We have prepared our accompanying consolidated financial statements under [removed: generally accepted accounting principles (GAAP)] [added: GAAP] and the rules and regulations of the [removed: Securities and Exchange Commission (SEC).][added: SEC.]

The address of our principal executive offices is [removed: 1000] [added: 811] Louisiana Street, Suite [removed: 4300,] [added: 2100,] Houston, Texas 77002, and our telephone number at this address is (713) 584-1000.

| | • | gathering, [removed: storing and] [added: storing,] terminaling [added: and selling] crude oil; and |

To provide these services, we operate in two primary [removed: segments (previously referred to as divisions):] [added: segments:] (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business).

The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma [added: (including the SCOOP] and [added: STACK) and] South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing segment includes [removed: all] the activities [added: and assets] necessary to convert mixed NGLs into NGL products and [removed: provides certain value added] [added: also includes other assets and value-added] services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses.

| | | | Emerging growth company | ☐ |

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

| [Signatures](#SIGNATURES) | 146 |

| LACT | | Lease Automatic Custody Transfer |

| SCOOP | | South Central Oklahoma Oil Province |

| STACK | | Sooner Trend, Anadarko, Canadian and Kingfisher |

Business.

Organization Structure

The diagram below shows our corporate structure as of February 12, 2018, which reflects the effect of the TRC/TRP Merger:


| (1) | Common shares outstanding as of February 12, 2018. |

The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including exposure to the SCOOP and STACK plays) and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

The Logistics and Marketing segment includes Grand Prix, as well as our equity interest in GCX, which are both currently under construction.

In 2017, we acquired additional gas gathering and processing and crude gathering systems located in the Permian Basin (the “Permian Acquisition”).

See further discussion of the Permian Acquisition in the “Recent Developments” section below.

We currently estimate that we will invest at least $1.6 billion in organic growth capital expenditures for announced projects in 2018.

The map below highlights our more significant assets:


Recent Developments

We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the "initial purchase price").

Subject to certain performance-based measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that would occur in April 2018 and April 2019.

The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

In addition, the Oahu Plant, a 60 MMcf/d plant in the Delaware Basin, which is expected to be completed in the first quarter of 2018, will be added to New Delaware’s footprint.

The New Midland assets include 10 MMcf/d of processing capacity.

New Delaware's gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and New Midland's gas gathering and processing assets were connected to our existing WestTX system in the fourth quarter of 2017.

We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and is expected to afford enhanced flexibility in serving producers.

In the first quarter of 2017, we restarted the idled 45 MMcf/d Benedum cryogenic processing plant.

In May 2017, we announced plans to build a new plant and further expand the gathering footprint of our Permian Midland system.

This project includes a new 200 MMcf/d cryogenic processing plant, known as the Johnson Plant, which is expected to begin operations in the third quarter of 2018.

We expect total net growth capital expenditures for the Johnson Plant to be approximately $100 million.

Also in May 2017, we announced plans to build a new plant and further expand the gathering footprint of our Permian Delaware system.

This project includes a new 250 MMcf/d cryogenic processing plant, known as the Wildcat Plant, which is expected to begin operations in the second quarter of 2018.

We expect total net growth capital expenditures for the Wildcat Plant to be approximately $130 million.

On February 6, 2018, we announced plans to construct two new 250 MMcf/d cryogenic natural gas processing plants in the Midland Basin to support increasing production.

The two plants are expected to begin operations in the first and third quarters of 2019, respectively.

The Raptor Plant, a gas processing facility with an initial capacity of 200 MMcf/d, and 45 miles of associated gathering pipelines, both part of a 50/50 joint venture with Sanchez Midstream Partners, L.P. (“SNMP”), which is associated with Sanchez Energy Corporation (“Sanchez”), began operations in the second quarter of 2017.

In February 2017, we announced that we were going to add compression to increase the processing capacity of the Raptor Plant to 260 MMcf/d, which was completed in the fourth quarter of 2017.

We manage operations of the high pressure gathering lines as well as the plant.

Eagle Ford Shale Acquisition of Flag City Natural Gas Processing Plant

In May 2017, we acquired a 150 MMcf/d natural gas processing plant (the “Flag City Plant”) and associated assets from subsidiaries of Boardwalk Pipeline Partners, L.P. (“Boardwalk”) for $60.0 million, subject to customary closing adjustments.

| --- | --- |

| --- | --- | --- |

| [Signatures](#SIGNATURES) | 141 |

| EP-PERMIAN | | Inside FERC Gas Market Report, El Paso (Permian Basin) |

Business

As we continue to control the Partnership, the change in our ownership interest as a result of the TRC/TRP Merger was accounted for as an equity transaction, which is reflected in our Consolidated Balance Sheet as a reduction of noncontrolling interests and corresponding increases in common stock, additional paid-in capital and deferred income tax liability.

No gain or loss was recognized in our Consolidated Statements of Operations related to the TRC/TRP Merger.

Concurrent with the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure.

The Gathering and Processing division was previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing.

The Logistics and Marketing division was previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution.

Management determined that the increase in activity within Field Gathering and Processing due to the acquisition by Targa of Atlas Energy LP (“ATLS”) and our acquisition of Atlas Pipeline Partners, L.P. (“APL”) (collectively, the “Atlas mergers”) coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted.

Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team.

Assuming the closing of the Permian Acquisition (as defined below) occurs in the first quarter of 2017, we currently estimate that we will invest at least $700 million in growth capital expenditures (exclusive of outlays for business acquisitions) for announced projects in 2017.

Volatility of Commodity Prices

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves.

Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels.

Prices of oil, natural gas and NGLs have been volatile, and we expect this volatility to continue.

Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related reduced activity levels from our customers.

Beginning in the fourth quarter of 2014, oil, natural gas and NGL prices declined significantly primarily due to global supply and demand imbalances.

Oil, natural gas and NGL prices continued to decline in 2015 and the first half of 2016, but have since experienced some recovery.

2016 Developments

Logistics and Marketing Segment Expansion

Cedar Bayou Fractionator Train 5

The gross cost of Train 5 was approximately $331 million (our net cost was approximately $299 million).

cost of approximately $140 million.

As contemplated by the agreement entered into with Noble in December 2014 (the “December 2014 Agreement”), the Splitter Agreement completes and terminates the December 2014 Agreement, while retaining our economic benefits from that previous agreement.

In October 2015, we announced that we had entered into joint venture agreements with Sanchez Energy Corporation (“Sanchez”) to construct a new 200MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Plant”) and approximately 45 miles of associated pipelines.

In July 2016, Sanchez sold its interest in the gathering joint venture to Sanchez Production Partners L.P. (“SPP”) and in November 2016 sold its interest in the processing joint venture to SPP.

We own a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect Sanchez's Catarina gathering system to the plant.

We hold a portion of the transportation capacity on the pipeline, and the gathering joint venture receives fees for transportation.

We expect to invest approximately $125 million of growth capital expenditures related to the joint ventures.

We will manage construction and operations of the plant and high pressure gathering lines, while the plant is expected to begin operations late in the first quarter of 2017 and to be fully operational in April 2017.

Permian Basin Buffalo Plant

In April 2016, we commenced commercial operations of a new 200 MMcf/d cryogenic processing plant, known as the Buffalo Plant, in our WestTX system.

This project also included the laying of new high and low pressure gathering lines in Martin and Andrews counties of Texas.

The addition of the Buffalo Plant positions us to handle increasing production from our joint venture partner in WestTX, Pioneer (the largest active driller in the Spraberry and Wolfberry Trends), and from other active producers in the area.

Purchase of Versado Membership Interest

In October 2016, we acquired the remaining membership interest in Versado Gas Processors, L.L.C. (“Versado”) that we did not own.

Targa held a 63% controlling interest in Versado prior to this transaction and already reported Versado on a consolidated basis.

In November 2016, we announced plans to restart the currently idled 45 MMcf/d Benedum cryogenic processing plant and to add 20 MMcf/d of capacity at our Midkiff plant in our WestTX system.

Our principal executive offices are located at [removed: 1000] [added: 811] Louisiana Street, Suite [removed: 4300,] [added: 2100,] Houston, Texas 77002 and our telephone number is 713-584-1000.

Our common stock is listed on the NYSE under the symbol “TRGP.” As of December 31, [removed: 2016,] [added: 2017,] there were approximately [removed: 258] [added: 246] stockholders of record of our common stock.

As of February [removed: 10, 2017,] [added: 12, 2018,] there were [removed: 193,949,450] [added: 218,830,282] shares of common stock outstanding.

| December 31, 2016 | | [removed: $] | 59.35 | | | [removed: $] | 41.35 | | | [removed: $] | 0.9100 | |

[removed: ][added: ]

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

With respect to any quarter ending on or prior to December 31, 2017, we [removed: may elect,] [added: could have elected,] in lieu of paying a [removed: distribution,] [added: dividend,] to add the amount that would have been paid as a [removed: distribution] [added: dividend] to the Liquidation Preference.

If we [removed: make] [added: were to have made] such election, we [removed: must grant] [added: would have granted] to the holders of the Preferred Shares [added: (the “Holders”)] a corresponding number of additional warrants having the same terms (including exercise price) as the warrants issued on the date of the closing of the transaction pursuant to which the Preferred Shares were issued (the “Closing Date”).

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

| Three Months Ended | | Date Paid or To Be Paid | | Total Common Dividends Declared | | | | Amount of Common Dividends Paid or To Be Paid | | | | Accrued Dividends (1) | | | | [removed: Dividend] [added: Dividends] Declared per Share of Common Stock | | |

| December 31, 2017 | | $ | 48.45 | | | $ | 39.59 | | | $ | 0.9100 | |

| September 30, 2017 | | | 48.73 | | | | 42.49 | | | | 0.9100 | |

| June 30, 2017 | | | 60.62 | | | | 40.25 | | | | 0.9100 | |

| March 31, 2017 | | | 61.83 | | | | 53.74 | | | | 0.9100 | |

| 2017 | | | | | | | | | | | | | | | | | | |

| December 31, 2017 | | February 15, 2018 | $ | | 202.4 | | $ | | 199.1 | | $ | | 3.3 | | $ | | 0.91000 | |

| September 30, 2017 | | November 15, 2017 | | | 199.0 | | | | 196.2 | | | | 2.8 | | | | 0.91000 | |

| June 30, 2017 | | August 15, 2017 | | | 198.6 | | | | 196.2 | | | | 2.4 | | | | 0.91000 | |

| March 31, 2017 | | May 16, 2017 | | | 182.8 | | | | 180.3 | | | | 2.5 | | | | 0.91000 | |

There were no sales of unregistered equity securities for the year ended December 31, 2017.

| October 1, 2017 - October 31, 2017 | | | 130 | | $ | | 45.95 | | | | — | | | | — | |

| December 1, 2017 - December 31, 2017 | | | 4,146 | | $ | | 46.36 | | | | — | | | | — | |

_________________________________

| December 31, 2014 | | | 139.99 | | | | 88.01 | | | | 0.7750 | |

| September 30, 2014 | | | 145.00 | | | | 126.42 | | | | 0.7325 | |

| June 30, 2014 | | | 160.97 | | | | 99.30 | | | | 0.6900 | |

| March 31, 2014 | | | 99.92 | | | | 84.17 | | | | 0.6475 | |

| --- | --- | --- |

| | • | the expenses of being a public company; |

| 2014 | | | | | | | | | | | | | | | | | | |

| December 31, 2014 | | February 17, 2015 | $ | | 32.8 | | $ | | 32.6 | | $ | | 0.2 | | $ | | 0.77500 | |

| September 30, 2014 | | November 17, 2014 | | | 31.0 | | | | 30.8 | | | | 0.2 | | | | 0.73250 | |

| June 30, 2014 | | August 15, 2014 | | | 29.2 | | | | 29.0 | | | | 0.2 | | | | 0.69000 | |

| March 31, 2014 | | May 16, 2014 | | | 27.4 | | | | 27.2 | | | | 0.2 | | | | 0.64750 | |

On October 19, 2016, the Partnership executed the Third A&R Partnership Agreement, which became effective on December 1, 2016.

The Third A&R Partnership Agreement amendments include among other things (i) eliminating the IDRs held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special GP Interest (as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.

On December 1, 2016, the Partnership issued to the General Partner (i) 20,380,286 Common Units and 424,590 General Partner Units in exchange for the elimination of the IDRs and (ii) 11,267,485 Common Units and 234,739 General Partner Units in exchange for elimination of the Special GP Interest in connection with the Third A&R Partnership Agreement.

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

In October 2016, Warrants exercisable into a maximum of 13,299,671 shares of our common stock were exercised by their holders and net settled by us for 7,633,564 shares of common stock.

In December 2016, Warrants exercisable into a maximum of 828,238 shares of our common stock were exercised by their holders and net settled by us for 517,669 shares of common stock.

| October 1, 2016 - October 31, 2016 | | | 300 | | | | 47.92 | | | | — | | | | — | |

| November 1, 2016 - November 30, 2016 | | | 2,571 | | | | 43.93 | | | | — | | | | — | |

| December 1, 2016 - December 31, 2016 | | | 3,994 | | | | 54.89 | | | | — | | | | — | |

| | [removed: 2016] [added: 2017] | | | | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | | | [removed: 2013] [added: 2014] | | | | [removed: 2012] [added: 2013] | | |

| Revenues | $ | [removed: 6,690.9] [added: 8,814.9] | | | $ | [removed: 6,658.6] [added: 6,690.9] | | | $ | [removed: 8,616.5] [added: 6,658.6] | | | $ | [removed: 6,314.7] [added: 8,616.5] | | | $ | [removed: 5,679.0] [added: 6,314.7] | |

| Income [added: (loss)] from operations | | [removed: 55.8] [added: (122.4] | [added: )] | | | [removed: 159.3] [added: 55.8] | | | | [removed: 640.5] [added: 159.3] | | | | [removed: 368.2] [added: 640.5] | | | | [removed: 336.3] [added: 368.2] | |

| Net income (loss) | | [added: 104.2 | | | |] (159.1 | ) | | | (151.4 | ) | | | 423.0 | | | | 201.3 | | [removed: | | 159.3 | |]

| Net income (loss) attributable to common shareholders | | [removed: (278.1] [added: (63.4] | ) | | | [removed: 58.3] [added: (278.1] | [added: )] | | | [removed: 102.3] [added: 58.3] | | | | [removed: 65.1] [added: 102.3] | | | | [removed: 38.1] [added: 65.1] | |

| Net income (loss) per common share - basic | | [removed: (1.80] [added: (0.31] | ) | | | [removed: 1.09] [added: (1.80] | [added: )] | | | [removed: 2.44] [added: 1.09] | | | | [removed: 1.56] [added: 2.44] | | | | [removed: 0.93] [added: 1.56] | |

| Net income (loss) per common share - diluted | | [removed: (1.80] [added: (0.31] | ) | | | [removed: 1.09] [added: (1.80] | [added: )] | | | [removed: 2.43] [added: 1.09] | | | | [removed: 1.55] [added: 2.43] | | | | [removed: 0.91] [added: 1.55] | |

| Total assets | $ | [removed: 12,871.2] [added: 14,388.6] | | | $ | [removed: 13,211.0] [added: 12,871.2] | | | $ | [removed: 6,423.5] [added: 13,211.0] | | | $ | [removed: 6,022.5] [added: 6,423.5] | | | $ | [removed: 5,081.5] [added: 6,022.5] | |

| Long-term debt | | [removed: 4,606.0] [added: 4,703.0] | | | | [removed: 5,718.8] [added: 4,606.0] | | | | [removed: 2,855.5] [added: 5,718.8] | | | | [removed: 2,963.2] [added: 2,855.5] | | | | [removed: 2,451.8] [added: 2,963.2] | |

| Series A Preferred 9.5% Stock | | [removed: 190.8] [added: 216.5] | | | | [removed: \-] [added: 190.8] | | | | [removed: \-] [added: —] | | | | [removed: \-] [added: —] | | | | [removed: \-] [added: —] | |

| Dividends declared per share | $ | 3.6400 | | | $ | [removed: 3.5250] [added: 3.6400] | | | $ | [removed: 2.8450] [added: 3.5250] | | | $ | [removed: 2.2050] [added: 2.8450] | | | $ | [removed: 1.6388] [added: 2.2050] | |

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

Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, [removed: 2016,] [added: 2017,] our disclosure controls and procedures were [removed: not] effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required [removed: disclosure because of the material weakness in our internal control over financial reporting as discussed below.][added: disclosure.]

Our Management’s Report on Internal Control Over Financial Reporting is included on page F-2 of this Annual [removed: Report, which] [added: Report and] is incorporated herein by reference.

Management concluded that our internal control over financial reporting was [removed: not] effective as of December 31, [removed: 2016, because of the material weakness described in Management’s Report on Internal Control Over Financial Reporting.][added: 2017.]

| [removed: (c)] [added: (b)] | Changes in Internal Control Over Financial Reporting |

There have been no changes in our internal control over financial reporting during our most recent fiscal quarter [added: ended December 31, 2017] that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

| --- | --- |

| (b) | Remediation Plans |

In response to the material weakness identified in our Form 10-Q for the period ended September 30, 2016, we developed a plan for remediation that consists of the following elements:

| | • | Performing an independent detailed review and re-performance of key elements of the interim tax provision calculation and entries to provide additional assurance that clerical errors are detected, and that detailed reviews already required under our controls and procedures are performed timely and effectively. |

| --- | --- | --- |

| | • | Incorporating into our process a formal interim tax provision checklist designed to ensure that we identify and appropriately address unusual and infrequently occurring circumstances requiring special consideration under GAAP applicable to interim income taxes. |

| | • | Conducting formal reviews with financial and tax executive management to provide enhanced transparency and to facilitate an assessment of appropriateness of the estimated annual effective tax rate utilized in the preparation of interim income tax provisions. |

We will have the opportunity to test the operational effectiveness of the revised controls and procedures in conjunction with the preparation of our interim financial statements during 2017.

In our Form 10-K for the year ended December 31, 2015, we identified and disclosed a material weakness in our controls over the valuation of certain assets in the Atlas mergers.

Specifically, we did not have adequate controls in place over our review procedures associated with the development and application of inputs, assumptions, and calculations used in cash flow-based fair value measurements associated with business combinations, thus they did not operate as designed and at an appropriate level of detail commensurate with our financial reporting requirements.

To remediate the material weakness, we implemented formal processes covering the development, application and review of inputs, assumptions, and calculations used in cash flow-based value measurements.

We tested our formal processes in conjunction with developing our cash flow estimates necessary for our annual goodwill impairment evaluation in the fourth quarter of fiscal 2016.

We successfully completed the testing necessary to conclude that this material weakness has been remediated.

The following table sets forth certain information with respect to our directors, executive officers and other officers as of February 17, [removed: 2017:][added: 2018:]

| Joe Bob Perkins | | [removed: 56] [added: 57] | | Chief Executive Officer and Director |

| James W. Whalen | | [removed: 75] [added: 76] | | Executive Chairman of the Board and Director |

| Michael A. Heim | | [removed: 68] [added: 69] | | Vice Chairman of the Board and Director |

| Jeffrey J. McParland | | [removed: 62] [added: 63] | | [removed: President-Finance and Administration] [added: President-Administration] |

| Paul W. Chung | | [removed: 56] [added: 57] | | Executive Vice President, General Counsel and Secretary |

| Matthew J. Meloy | | [removed: 39] [added: 40] | | Executive Vice President and Chief Financial Officer |

| John R. [removed: Sparger] [added: Klein] | | [removed: 63] [added: 67] | | Senior Vice President and Chief Accounting Officer |

| D. Scott Pryor | | [removed: 54] [added: 55] | | Executive Vice President – Logistics and Marketing |

| Patrick J. McDonie | | [removed: 56] [added: 57] | | Executive Vice President – Southern Field Gathering and Processing |

| Dan C. Middlebrooks | | [removed: 60] [added: 61] | | Executive Vice President – Northern Field Gathering and Processing |

| Clark White | | [removed: 57] [added: 58] | | Executive Vice President – Engineering and Operations |

| Rene R. Joyce | | [removed: 69] [added: 70] | | Director |

| Charles R. Crisp | | [removed: 69] [added: 70] | | Director |

| Chris Tong | | [removed: 60] [added: 61] | | Director |

| Ershel C. Redd Jr. | | [removed: 69] [added: 70] | | Director |

| Laura C. Fulton | | [removed: 53] [added: 54] | | Director |

| Waters S. Davis, IV | | [removed: 63] [added: 64] | | Director |

| Robert B. Evans | | [removed: 68] [added: 69] | | Director |

Between October 2002 and October 2005, Mr. Whalen served as the Senior Vice President and [added: Chief Financial Officer of Parker Drilling Company.]

[removed: McParland has] [added: He previously] served as President — Finance and Administration of the Company [removed: since] [added: between] October 25, 2010 and [added: February 22, 2017 and] of the General Partner [removed: since] [added: between] December 15, [removed: 2010.][added: 2010 and February 22, 2017.]

He [added: has] also served as Executive Vice President and Chief Financial Officer of the Company between October 27, 2005 and October 25, 2010.

[removed: Sparger] [added: Klein] has served as Senior Vice President and Chief Accounting Officer of the Company [removed: since January 2006] and [removed: of] the General Partner since [removed: October 2006.][added: February 22, 2017.]

Mr. Joyce served as President of onshore pipeline operations of Coral Energy, LLC, a subsidiary of Shell [removed: Oil] from 1998 through 1999 and President of energy services of Coral, a subsidiary of Shell which was the gas and power marketing joint venture between Shell and Tejas, during 1999.

His experience and industry knowledge, complemented by an engineering and legal educational background, enable Mr. Joyce to provide the board with executive [removed: council] [added: counsel] on the full range of business, technical, and professional matters.

Mr. Crisp is also a director of Southern Company Gas (formerly known as AGL Resources Inc.), a subsidiary of The Southern Company, EOG Resources Inc. and [removed: Intercontinental Exchange] [added: IntercontinentalExchange] Inc. Mr. Crisp brings extensive energy experience, a vast understanding of many aspects of our industry and experience serving on the boards of other public companies in the energy industry.

[added: Mr. Tong is a director of Kosmos Energy Ltd.] He served as Senior Vice President and Chief Financial Officer of Noble Energy, Inc. from January 2005 until August 2009.

Mr. Tong brings a breadth and depth of experience as a chief financial officer in the energy industry, a financial [added: executive, a director of other public companies and a member of other audit committees.]

Ms. Fulton has served as the Chief Financial Officer of [removed: Hi-Crush] [added: Hi\-Crush] Proppants LLC since April 2012 and [removed: Hi-Crush] [added: Hi\-Crush] GP LLC, the general partner of [removed: Hi-Crush] [added: Hi\-Crush] Partners LP, since May 2012.

Prior to AEI, Ms. Fulton spent 12 years with Lyondell Chemical Company in various capacities, including as general auditor responsible for internal audit and the [removed: Sarbanes-Oxley] [added: Sarbanes\-Oxley] certification process, and as the assistant controller.

Class I, Class II and Class III directors will serve until our annual meetings of stockholders in [removed: 2017,] [added: 2020,] 2018 and 2019, respectively.

Our board of directors has three standing committees [removed: -] [added: –] an Audit Committee, a Compensation Committee and a Nominating and Governance Committee - and may have such other committees as the board of directors shall determine from time to time.

In May [removed: 2016,] [added: 2017,] the Compensation Committee considered the independence of BDO USA, LLP (“BDO”), our compensation consultant, in light of new SEC rules and the NYSE listing standards.

Requests for print copies may be directed to: Investor Relations, Targa Resources Corp., [removed: 1000] [added: 811] Louisiana, Suite [removed: 4300,] [added: 2100,] Houston, Texas 77002 or made by telephone by calling (713) 584-1000.

Interested parties may communicate directly with our non-management directors by writing to: Non-Management Directors, Targa Resources Corp., [removed: 1000] [added: 811] Louisiana, Suite [removed: 4300,] [added: 2100,] Houston, Texas 77002.

Based solely upon a review of the copies of the Form 3, 4 and 5 reports furnished to us and certifications from our directors and executive officers, we believe that during [removed: 2016,] [added: 2017,] all of our directors, executive officers and beneficial owners of more than 10% of our common units complied with Section 16(a) filing requirements applicable to them.

| Robert M. Muraro | | 41 | | Executive Vice President – Commercial |

| Jennifer R. Kneale | | 39 | | Vice President – Finance |

McParland has served as President – Administration of the Company since February 22, 2017.

Mr. Meloy will serve as President of the Company and the General Partner, effective March 1, 2018.

Mr. Pryor will serve as President – Logistics and Marketing of the Company and the General Partner, effective March 1, 2018.

Mr. McDonie will serve as President – Gathering and Processing of the Company and the General Partner, effective March 1, 2018.

Robert M.

Muraro has served as Executive Vice President – Commercial of the Company and the General Partner since February 22, 2017.

Mr. Muraro will serve as Chief Commercial Officer of the Company and the General Partner, effective March 1, 2018.

previously served as Senior Vice President – Commercial and Business Development of Targa Midstream Services LLC (“Targa Midstream”) and various other subsidiaries of the Partnership between March 2016 and February 2017.

He also served as Vice President – Commercial Development of Targa Midstream and various other subsidiaries of the Partnership between January 2013 and March 2016.

He held the position of Director of Business Development between August 2004 and January 2013.

Mr. Klein previously served as Senior Vice President – Controller of the Company and the General Partner between December 2015 and February 2017.

He also served as Vice President – Controller of the Company between March 2007 and December 2015 and of the General Partner between November 2007 and December 2015.

Mr. Klein served as a senior executive in a consulting firm from 1995 through 2006.

Prior to 1995, he held various executive accounting management positions in the energy industry and in public accounting.

Jennifer R.

Kneale will serve as Chief Financial Officer of the Company and the General Partner, effective March 1, 2018.

Ms. Kneale has served as Vice President - Finance of the Company and the General Partner since December 16, 2015.

She previously served as Senior Director, Finance of the Company and the General Partner between March 2015 and December 2015.

She also served as Director, Finance of the Company and the General Partner between May 2013 and February 2015.

Ms. Kneale was with Tudor, Pickering, Holt & Co. in its energy private equity group, TPH Partners, from September 2011 to May 2013, most recently serving as Director of Investor Relations.

Ms. Kneale will replace Mr. Meloy as Chief Financial Officer of the Company on the effective date of her appointment.

Mr. Joyce is a director of Apache Corporation.

Chief Financial Officer of Parker Drilling Company.

He also served as an officer of an affiliate of the Company during 2004 and 2005.

Mr. Sparger served as Vice President, Internal Audit of the Company between October 2005 and January 2006.

Mr. Sparger served as a consultant in the energy industry from 2002 through September 2004, providing advice to various energy companies and entities regarding processes, systems, accounting and internal controls.

Prior to 2002, he worked in various accounting and administrative positions with companies in the energy industry, audit and consulting positions in public accounting and consulting positions with a large international consulting firm.

Mr. Tong is a director of Kosmos Energy Ltd. He also served as a director of Cloud Peak Energy Inc. from October 2009 until May 2012.

executive, a director of other public companies and a member of other audit committees.

For [removed: 2016,] [added: 2017,] our named executive officers were:

| Name | Position During [removed: 2016] [added: 2017] |

Our [removed: main source] [added: operating assets are held by subsidiaries] of [removed: cash flow is from our interests in] the Partnership, and our named executive officers also served as executive officers of its General Partner during [removed: 2016.][added: 2017.]

[removed: Immediately prior to completion of the merger pursuant to which the] [added: The] Company acquired all of the Partnership common units not already owned by it [added: pursuant to a merger transaction] (the “Buy-In Transaction”) [removed: on] [added: effective as of] February 17, [removed: 2016, the Company owned an 8.8% interest in the Partnership, including the 2% General Partner interest, and was the indirect parent of the General Partner.][added: 2016.]

During [removed: 2016,] [added: 2017,] the Partnership reimbursed us and our affiliates for the compensation of our named executive officers pursuant to the Partnership’s partnership agreement.

See [removed: “—Transactions] [added: “Transactions] with Related Persons—Reimbursement of Operating and General and Administrative Expense” [added: in “Item 13 – Certain Relationships and Related Transactions, and Director Independence”] for additional information regarding the Partnership’s reimbursement obligations.

The Compensation Committee believes that [removed: the actions] it has taken [added: actions] to govern compensation in a responsible [removed: way] [added: way,] as described in this [removed: CD&A] [added: CD&A,] and [added: that] the Company’s performance over its trading history [removed: demonstrate] [added: demonstrates] that our compensation programs are structured to pay reasonable amounts for performance based on our understanding of the markets in which we compete for executive talent and the returns our shareholders have realized.

We held our [removed: last] [added: most recent] advisory [removed: say on pay] [added: say-on-pay] vote regarding executive compensation at our [removed: 2014] [added: 2017] Annual Meeting.

At that meeting, more than [removed: 99%] [added: 97%] of the votes cast by our shareholders [removed: approved] [added: approved, on an advisory basis, of] the compensation paid to our named executive officers as described in the CD&A and the other related compensation tables and disclosures contained in our Proxy Statement filed with the SEC on [removed: April 7, 2014.][added: March 29, 2017.]

The Board of Directors and the Compensation Committee reviewed the results of this vote and concluded that, with this level of support, no changes to our compensation design and philosophy needed to be considered as a result of the [removed: say on pay] [added: say-on-pay] vote.

In accordance with the preference expressed by our shareholders to conduct an advisory vote on executive compensation every [removed: three years,] [added: year,] the next advisory vote will occur this year at the [removed: 2017] [added: 2018] Annual Meeting.

As described in “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” in our Annual Report on Form [removed: 10-K,] [added: 10-K for the year ended December 31, 2017,] our [removed: 2016] [added: 2017] strategic and operational accomplishments and our [removed: 2016] [added: 2017] financial results (including the financial results of the Partnership on a consolidated basis) demonstrate the performance of [added: our businesses through the industry downturn, which, along with our ongoing growth capital expenditure programs, have allowed us to increase both our business scale and diversity.]

In summary, [removed: some] [added: certain] of our more significant financial, operational and strategic highlights in [removed: 2016] [added: 2017] included:

[removed: | | • |] Excellent execution across our [removed: businesses, despite a commodity price environment substantially below expectations,] [added: businesses] with Company Adjusted EBITDA of [removed: $1.065] [added: $1.14] billion, [added: driven by higher] Field G&P [added: volumes, higher fractionation volumes,] and [added: continued strong] export volumes [removed: essentially flat to 2015 and at or above] [added: while exceeding] public [added: EBITDA] guidance, and [added: with] dividend coverage that achieved public guidance; [removed: |]

[removed: | | • |] Excellent execution on [removed: 2016] [added: 2017] growth capital expenditures of approximately [removed: $506 million for expansion projects] [added: $2 billion (including acquisitions)] completed or on track to be completed [added: generally] on time and [removed: near] [added: on] budget; [removed: |]

[removed: | | • |] Continued development of our potential future expansion project portfolio; [removed: |]

[removed: | | • |] Excellent financial execution including capital raising and balance sheet and liquidity management while funding growth expenditures and maintaining dividend per share; and [removed: |]

[removed: | | • |] A continued strong track record and performance regarding safety, including industry safety recognition in [removed: 2016, although less than satisfactory performance with respect to maintaining adequate internal controls,] [added: 2017] and strong compliance performance in all other aspects of our business, including environmental and regulatory compliance. [removed: |]

See “—Components of Executive Compensation Program for Fiscal [removed: 2016—Annual] [added: 2017—Annual] Incentive Bonus” for further discussion of certain of these summary highlights.

Please also see our Annual Report on Form 10-K for the year ended December 31, [removed: 2016] [added: 2017] for a reconciliation of Adjusted EBITDA to net income [removed: and net cash provided by operating activities.][added: (loss) attributable to TRC.]

Summary of [removed: 2016 and] 2017 [added: and 2018] Compensation Decisions

While the compensation arrangements for our named executive officers during fiscal [removed: 2016] [added: 2017] remained substantially similar to those in place during fiscal [removed: 2015,] [added: 2016,] specific compensatory actions in [removed: 2016] [added: 2017] included the following:

With respect to [removed: 2017] [added: 2018] compensation, the Compensation Committee has made the following determinations, which are described in greater detail below under “—Changes for [removed: 2017”:][added: 2018”:]

| [removed: |] • | Increases to [removed: 2017] [added: 2018] Total [removed: Compensation and Limited Increases to Base Pay.] [added: Compensation.] For [removed: 2017,] [added: 2018,] base salary raises were approved for the named executive officers [removed: (other than Messrs. Heim and McParland)] ranging from [removed: 2.0%] [added: 11%] to [removed: 3.4%.] [added: 29%.] The Compensation Committee authorized base salary increases for [removed: certain of] the named executive officers in order to align the total direct compensation of these individuals more closely with the total direct compensation provided to similarly situated executives at companies within our [removed: 2017] [added: 2018] Peer Group, adjusted for company size, and, in the case of [added: our named executive officers other than] Mr. [removed: Meloy,] [added: Perkins,] to reflect [removed: professional growth] [added: their promotions to new positions] and the assumption of additional [removed: responsibilities.] [added: responsibilities effective March 1, 2018.] See “—Changes for [removed: 2017—2017] [added: 2018—2018] Peer Group” for a description of the companies that comprise the [removed: 2017] [added: 2018] Peer Group. In addition, for [removed: 2017] [added: 2018] under our annual incentive bonus plan, the target bonus percentages for our named executive officers [removed: (other than Mr. Heim)] were increased in order to align their total direct compensation more closely with the total direct compensation provided to similarly situated officers at companies within our [removed: 2017] [added: 2018] Peer Group, adjusted for company [removed: size.] [added: size, and to reflect the changes in positions and responsibilities referenced above.] For similar reasons, the long-term equity incentive award [removed: opportunities] [added: targets] for [removed: 2017] [added: 2018] for the named executive officers [removed: (other than Mr. Heim)] were also [removed: increased.] [added: increased] |

The Compensation Committee believes our executive compensation program should enable us to attract and retain key executives by providing a total compensation program that is competitive with the market in which we compete for [added: executive talent, which encompasses not only diversified midstream companies but also other energy industry companies as described in “—Methodology and Process—Role of Peer Group and Market Analysis” below.]

[removed: | | • | Accountability for Performance.] The Compensation Committee believes our executive compensation program should ensure an alignment between our strategic, operational and financial performance and the total compensation received by our named executive officers. [removed: This includes providing compensation for performance that reflects individual and company performance both in absolute terms and relative to our Peer Group. |]

[removed: | | • | Alignment with Shareholder Interests.] The Compensation Committee believes our executive compensation program should ensure a balance between short-term and long-term compensation while emphasizing at-risk or variable compensation as a valuable means of supporting our strategic goals and aligning the interests of our named executive officers with those of our shareholders. [removed: |]

[removed: | | • | Supportive of Business Goals.] The Compensation Committee believes that our total compensation program should support our business objectives and priorities. [removed: |]

Consistent with this philosophy and the compensation objectives, our [removed: 2016] [added: 2017] executive compensation program consisted of the following elements:

| Base Salary | Competitive fixed-cash compensation based on an individual’s role, experience, qualifications and performance | [removed: • A] [added: •A] core element of competitive total compensation, important in attracting and retaining key executives |

| Annual Incentive Bonus | Variable payouts tied to achievement of annual financial, operational and strategic business priorities and determined in the sole discretion of the Compensation Committee | [removed: • Aligns] [added: •Aligns] named executive officers with annual strategic, operational and financial results [removed: • Recognizes] [added: •Recognizes] individual and performance-based contributions to annual results [removed: • Supplements] [added: •Supplements] base salary to help attract and retain executives |

| Long-Term Equity Incentive Awards | Restricted stock [added: awards granted under our Stock Incentive Plan Performance share] unit awards granted under our Stock Incentive Plan | [removed: • Aligns] [added: •Aligns] named executive officers with sustained long-term value creation [removed: • Creates] [added: •Creates] opportunity for a meaningful and sustained ownership stake [removed: • Combined] [added: •Combined] with salary and annual bonus, provides a competitive target total direct compensation opportunity [added: substantially contingent on our equity performance and performance relative to our LTIP peer group] |

| Benefits | 401(k) plan, health and welfare benefits | [removed: • Our] [added: •Our] named executive officers are eligible to participate in benefits provided to other Company employees [removed: • Contributes] [added: •Contributes] toward financial security for various life events (e.g., disability or death) [removed: • Generally] [added: •Generally] competitive with companies in the midstream sector |

| Post-Termination Compensation | “Double trigger” [removed: cash] change in control payments [added: payable in cash] Accelerated vesting of equity awards upon certain change in control transactions and qualifying termination events Continued vesting of equity awards following retirement, subject to provision of consulting services or compliance with non-compete obligations | [removed: • Helps] [added: •Helps] mitigate possible disincentives to pursue value-added merger or acquisition transactions if employment prospects are uncertain [removed: • Provides] [added: •Provides] assistance with transition if post-transaction employment is not offered [removed: • Allows] [added: •Allows] the Company to benefit from employee non-compete obligations and ongoing access to cooperative employees |