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CST: 18/08/2019 08:12:10   

Targa Resources Corp. Reports First Quarter 2019 Financial Results

103 Days ago

HOUSTON, May 07, 2019 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported first quarter 2019 results.

First Quarter 2019 Financial Results

First quarter 2019 net income (loss) attributable to Targa Resources Corp. was ($38.9) million compared to $22.9 million for the first quarter of 2018.

The Company reported record quarterly earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $313.9 million for the first quarter of 2019 compared to $306.6 million for the first quarter of 2018 (see the section of this release entitled “Targa Resources Corp. - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, distributable cash flow, gross margin and operating margin, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”)).

“We continue to remain focused on execution across all areas of our business, and are on-track to bring online a substantial portion of our system expansions in the very near term, including our Grand Prix NGL Pipeline project,” said Joe Bob Perkins, Chief Executive Officer of the Company. “Our growth projects and commercial success further enhance our strategic position and attractive long-term outlook for Targa.”

On April 17, 2019, TRC declared a quarterly dividend of $0.91 per share of its common stock for the three months ended March 31, 2019, or $3.64 per share on an annualized basis. Total cash dividends of approximately $211.5 million will be paid on May 15, 2019 on all outstanding shares of common stock to holders of record as of the close of business on May 1, 2019. Also, on April 17, 2019, TRC declared a quarterly cash dividend of $23.75 per share of its Series A Preferred Stock. Total cash dividends of approximately $22.9 million will be paid on May 14, 2019 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on May 1, 2019.

The Company reported distributable cash flow for the first quarter of 2019 of $196.7 million compared to total common dividends to be paid of $211.5 million and total Series A Preferred Stock dividends to be paid of $22.9 million.

First Quarter 2019 - Sequential Quarter over Quarter Commentary

First quarter 2019 Adjusted EBITDA of $313.9 million was lower than the fourth quarter of 2018 predominantly as a result of the recognition of the full amount of the 2018 annual cash payment for the since terminated Splitter Agreement in the fourth quarter of 2018, which represented about 70% of the variance. Fundamentals for Targa’s Gathering and Processing and Downstream businesses were strong quarter over quarter, with higher sequential volumes in the Permian, Badlands, SouthOK and Coastal areas, and higher fractionation volumes. The remaining balance of the sequential variance was attributable to lower commodity price realizations and higher operating expenses in the Gathering and Processing segment from Permian system expansions. Sequential realized WAHA natural gas prices were 22% lower, NGL prices 17% lower, and condensate prices 4% lower, partially offset by an additional $4.5 million of realized hedge gains in the first quarter versus the fourth quarter. Sequential operating expenses were higher in the Gathering and Processing segment, primarily associated with new assets coming online and other system expansions that have driven labor costs higher in advance of full quarter contributions of Adjusted EBITDA. Please refer to the Company's first quarter 2019 Earnings Supplement presentation, which can be accessed through the Events and Presentations section of Targa’s website at www.targaresources.com, for additional details.

First Quarter 2019 - Capitalization and Liquidity

The Company’s total consolidated debt as of March 31, 2019 was $7,436.6 million including $435.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility. The consolidated debt included $7,001.6 million of Targa Resources Partners LP’s (“TRP” or the “Partnership”) debt, net of $42.7 million of debt issuance costs, with $670.0 million outstanding under TRP’s $2.2 billion senior secured revolving credit facility, $307.6 million outstanding under TRP’s accounts receivable securitization facility, $6,028.5 million of outstanding TRP senior notes, net of unamortized premiums, and $38.2 million of finance lease liabilities.

Total consolidated liquidity of the Company as of March 31, 2019, including $124.9 million of cash, was over $1.8 billion. As of March 31, 2019, TRC had available borrowing capacity under its senior secured revolving credit facility of $235.0 million. TRP had $670.0 million of borrowings and $69.8 million in letters of credit outstanding under its $2.2 billion senior secured revolving credit facility, resulting in available senior secured revolving credit facility capacity of $1,460.2 million. In addition to the availability under its senior secured revolving credit facility, the Partnership also had $30.0 million of availability under its accounts receivable securitization facility.

Financing Update

In January 2019, the Partnership issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of $1,487.3 million. The net proceeds from the offerings were used to redeem in full the Partnership’s 4⅛% Senior Notes due 2019, at par value plus accrued interest through the redemption date, with the remainder used for general partnership purposes, which included repaying borrowings under the Partnership’s credit facilities.

Badlands Interest Sale

In April 2019, the Company closed on the sale of a 45% interest in Targa Badlands LLC, the entity that holds substantially all of the Company's assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities for $1.6 billion in cash. The Company used the net cash proceeds to repay debt and for general corporate purposes, including funding the Company's growth capital program.

2019 Financial and Operational Expectations

Targa affirms its previously disclosed full year financial and operational outlook for 2019, which assumes NGL composite barrel prices average $0.60 per gallon, crude oil prices average $54 per barrel and Henry Hub natural gas prices average $3.00 per MMbtu for the year and is pro forma for the recently closed sale of a 45% interest in the Badlands. The sale of the Badlands is effective as of April 1, 2019 and the Company also affirms its previously provided expectation that second quarter Adjusted EBITDA will be lower than the first quarter of 2019 as a result of the Badlands partial interest sale. Through the first quarter, the Company spent $781.6 million on net growth capital expenditures, including net contributions to investments in unconsolidated affiliates, representing 34% of Targa’s estimated 2019 net growth capital expenditures of $2.3 billion.

Conference Call

The Company will host a conference call for the investment community at 11:00 a.m. Eastern time (10:00 a.m. Central time) on May 7, 2019 to discuss first quarter 2019 results. The conference call can be accessed via webcast through the Events and Presentations section of Targa’s website at www.targaresources.com, by going directly to https://edge.media-server.com/m6/p/a8ufffy8 or by dialing 877-881-2598. The conference ID number for the dial-in is 7255506. Please dial in ten minutes prior to the scheduled start time. A webcast replay will be available at the link above approximately two hours after the conclusion of the event.


Targa Resources Corp. – Consolidated Financial Results of Operations

  Three Months Ended March 31,                
  2019     2018     2019 vs. 2018  
     
  (In millions)  
Revenues                            
Sales of commodities $ 1,976.5     $ 2,173.7     $ (197.2 )   (9 %)
Fees from midstream services   322.9       281.9       41.0     15 %
Total revenues   2,299.4       2,455.6       (156.2 )   (6 %)
Product purchases   1,726.0       1,941.0       (215.0 )   (11 %)
Gross margin (1)   573.4       514.6       58.8     11 %
Operating expenses   190.2       173.2       17.0     10 %
Operating margin (1)   383.2       341.4       41.8     12 %
Depreciation and amortization expense   237.4       198.1       39.3     20 %
General and administrative expense   81.1       56.7       24.4     43 %
Other operating (income) expense   3.4       0.3       3.1     NM  
Income (loss) from operations   61.3       86.3       (25.0 )   (29 %)
Interest income (expense), net   (80.6 )     16.1       (96.7 )   NM  
Equity earnings (loss)   2.8       1.5       1.3     87 %
Gain (loss) from financing activities   (1.4 )           (1.4 )    
Change in contingent considerations   (9.7 )     (56.1 )     46.4     83 %
Income tax (expense) benefit   2.9       (8.9 )     11.8     133 %
Net income (loss)   (24.7 )     38.9       (63.6 )   (163 %)
Less: Net income (loss) attributable to noncontrolling interests   14.2       16.0       (1.8 )   (11 %)
Net income (loss) attributable to Targa Resources Corp.   (38.9 )     22.9       (61.8 )   (270 %)
Dividends on Series A Preferred Stock   22.9       22.9            
Deemed dividends on Series A Preferred Stock   7.9       7.0       0.9     13 %
Net income (loss) attributable to common shareholders $ (69.7 )   $ (7.0 )   $ (62.7 )   NM  
Financial data:                            
Adjusted EBITDA (1) $ 313.9     $ 306.6     $ 7.3     2 %
Distributable cash flow (1)   196.7       216.4       (19.7 )   (9 %)
Growth capital expenditures (2)   870.0       535.6       334.4     62 %
Maintenance capital expenditures (3)   35.6       22.4       13.2     59 %

____________
(1)   Gross margin, operating margin, Adjusted EBITDA, and distributable cash flow are non-GAAP financial measures and are discussed under “Targa Resources Corp. – Non-GAAP Financial Measures.”
(2)   Growth capital expenditures, net of contributions from noncontrolling interest, were $752.5 million and $446.8 million for the three months ended March 31, 2019 and 2018. Net contributions to investments in unconsolidated affiliates were $29.1 million and $32.4 million for the three months ended March 31, 2019 and 2018.
(3)   Maintenance capital expenditures, net of contributions from noncontrolling interests, were $34.4 million and $21.9 million for the three months ended March 31, 2019 and 2018.
NM   Due to a low denominator, the noted percentage change is disproportionately high and, as a result, considered not meaningful.

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

The decrease in commodity sales reflects lower natural gas liquid (“NGL”), natural gas and condensate prices ($437.8 million) and lower petroleum volumes due to the sale of certain petroleum logistics storage and terminaling facilities in the fourth quarter of 2018 ($40.5 million), partially offset by higher NGL and crude marketing volumes ($228.4 million) and the impact of hedges ($50.5 million). The increase in fee-based revenue was primarily due to higher gas processing and crude gathering fees.

The decrease in product purchases reflects decreased NGL, natural gas and condensate prices, partially offset by increases in volumes.

The higher operating margin and gross margin in 2019 reflect increased segment margin results for Gathering and Processing and Logistics and Marketing. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense increased primarily due to higher depreciation related to major growth projects placed in service, including the Permian Basin segment of the Grand Prix pipeline (“Grand Prix”), and additional processing plants and associated infrastructure in the Permian Basin. The increase is partially offset by lower depreciation for the Company's downstream facilities, resulting from the sale of certain petroleum logistics storage and terminaling facilities in the fourth quarter of 2018.

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

Interest expense, net, increased due to a reduction of non-cash interest income related to the mandatorily redeemable interests, and higher average borrowings, partially offset by higher capitalized interest related to the Company's major growth investments. During 2018, the Company recognized non-cash interest income resulting from a decrease in the estimated redemption value of the mandatorily redeemable interests, primarily attributable to the February 2018 amendments to such arrangements.

During 2019, the Company recorded expense of $9.7 million resulting from an increase in the value of the contingent consideration liability we incurred in connection with our acquisition of certain gas gathering and processing and crude gathering assets in the Permian Basin (the “Permian Acquisition”). The increase in 2019 was primarily attributable to the elimination of discounting and an increase in actual gross margin through the end of the earn-out period. During 2018, the Company recorded expense of $56.1 million resulting primarily from the increase in fair value as of March 31, 2018 of the Permian Acquisition contingent consideration liability. The fair value change was primarily related to an increase in underlying forecasted volumes for the remainder of the earn-out period and a shorter term over which such projections are discounted.

During 2019, the Company recorded an income tax benefit, whereas in 2018, the Company recorded income tax expense. The change was primarily due to lower net income (loss) before tax, a lower annual effective tax rate and higher tax benefits related to share-based payment awards that vested during the quarter.

Review of Segment Performance

The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin and gross margin as important performance measures of the core profitability of its operations. These measures are key components of internal financial reporting and are reviewed for consistency and trend analysis. For a discussion of operating margin and gross margin, see “Targa Resources Corp. - Non-GAAP Financial Measures - Operating Margin” and “Targa Resources Corp. - Non-GAAP Financial Measures - Gross Margin.” Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation.

The Company operates in two primary segments: (i) Gathering and Processing; and (ii) Logistics and Marketing.

Gathering and Processing Segment

The Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) 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 following table provides summary data regarding results of operations of this segment for the periods indicated:

  Three Months Ended March 31,                
  2019     2018     2019 vs. 2018  
     
  (In millions, except operating statistics and price amounts)  
Gross margin $ 351.9     $ 325.6     $ 26.3     8 %
Operating expenses   122.9       104.8       18.1     17 %
Operating margin $ 229.0     $ 220.8     $ 8.2     4 %
Operating statistics (1):                            
Plant natural gas inlet, MMcf/d (2),(3)                            
Permian Midland (4)   1,334.4       1,014.1       320.3     32 %
Permian Delaware   480.4       409.2       71.2     17 %
Total Permian   1,814.8       1,423.3       391.5        
                             
SouthTX (5)   363.9       416.3       (52.4 )   (13 %)
North Texas   230.5       235.1       (4.6 )   (2 %)
SouthOK (6)   620.0       529.9       90.1     17 %
WestOK   338.1       350.1       (12.0 )   (3 %)
Total Central   1,552.5       1,531.4       21.1        
                             
Badlands (7)   96.9       73.3       23.6     32 %
Total Field   3,464.2       3,028.0       436.2        
                             
Coastal   769.9       724.3       45.6     6 %
                             
Total   4,234.1       3,752.3       481.8     13 %
NGL production, MBbl/d (3)                            
Permian Midland (4)   184.3       140.2       44.1     31 %
Permian Delaware   60.5       45.7       14.8     32 %
Total Permian   244.8       185.9       58.9        
                             
SouthTX (5)   48.8       54.1       (5.3 )   (10 %)
North Texas   26.8       25.9       0.9     3 %
SouthOK (6)   58.3       48.9       9.4     19 %
WestOK   24.1       19.4       4.7     24 %
Total Central   158.0       148.3       9.7        
                             
Badlands   11.4       10.2       1.2     12 %
Total Field   414.2       344.4       69.8        
                             
Coastal   48.4       42.6       5.8     14 %
                             
Total   462.6       387.0       75.6     20 %
Crude oil gathered, Badlands, MBbl/d   169.5       117.7       51.8     44 %
Crude oil gathered, Permian, MBbl/d   67.4       49.4       18.0     36 %
Natural gas sales, BBtu/d (3)   1,925.9       1,767.3       158.6     9 %
NGL sales, MBbl/d   359.5       300.4       59.1     20 %
Condensate sales, MBbl/d   12.5       16.2       (3.7 )   (23 %)
Average realized prices (8):                            
Natural gas, $/MMBtu   1.89       2.37       (0.48 )   (20 %)
NGL, $/gal   0.45       0.59       (0.14 )   (24 %)
Condensate, $/Bbl   47.09       59.66       (12.57 )   (21 %)

____________
(1)   Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.
(2)   Plant natural gas inlet represents the Company's undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than Badlands.
(3)   Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.
(4)   Permian Midland includes operations in WestTX, of which the Company owns 72.8%, and other plants that are owned 100% by the Company. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in the Company's reported financials.
(5)   SouthTX includes the Raptor Plant, of which the Company owns a 50% interest through the Carnero Joint Venture. SouthTX also includes the Silver Oak II Plant, of which the Company owned a 100% interest until it was contributed to the Carnero Joint Venture in May 2018. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in the Company's reported financials.
(6)   SouthOK includes the Centrahoma Joint Venture, of which the Company owns 60%, and other plants that are owned 100% by us. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in the Company's reported financials.
(7)   Badlands natural gas inlet represents the total wellhead gathered volume.
(8)   Average realized prices exclude the impact of hedging activities presented in Other.

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

The increase in gross margin was primarily due to higher Badlands and Permian volumes, partially offset by lower commodity prices and lower SouthTX volumes. The effect of commodity prices excludes the impact of hedging activities presented in Other. NGL production, NGL sales and natural gas sales increased primarily due to higher Field Gathering and Processing inlet volumes and increased NGL recoveries including reduced ethane rejection. Total crude oil gathered volumes increased in the Permian region due to production from new wells. In the Badlands, total crude oil gathered volumes and natural gas gathered volumes increased primarily due to production from new wells and system expansions.

The increase in operating expenses was primarily driven by gas plant and system expansions in the Permian region. Operating expenses in other regions were relatively flat.

Logistics and Marketing Segment

The Logistics and Marketing segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to liquefied petroleum gas (“LPG”) exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of the Company’s other businesses. The Logistics and Marketing segment also includes Grand Prix, as well as the Company's equity interest in Gulf Coast Express Pipeline LLC (“GCX”), which are both currently under construction and expected to fully begin operations in 2019. Grand Prix, once fully completed, will integrate the Company's gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with the Company's downstream facilities in Mont Belvieu, Texas. The associated assets, including these pipeline projects, are generally connected to and supplied in part by the Company’s Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

The following table provides summary data regarding results of operations of this segment for the periods indicated:

    Three Months Ended March 31,          
    2019     2018     2019 vs. 2018  
  (In millions, except operating statistics and price amounts)  
Gross margin   $ 219.5     $ 206.9     $ 12.6     6 %
Operating expenses     67.4       68.5       (1.1 )   (2 %)
Operating margin   $ 152.1     $ 138.4     $ 13.7     10 %
Operating statistics MBbl/d (1):                              
Fractionation volumes (2)     456.6       389.7       66.9     17 %
Export volumes (3)     213.1       201.9       11.2     6 %
NGL sales     586.2       514.8       71.4     14 %
Average realized prices:                              
NGL realized price, $/gal   $ 0.60     $ 0.76     $ (0.16 )   (21 %)

____________
(1)   Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.
(2)   Fractionation contracts include pricing terms composed of base fees and fuel and power components that vary with the cost of energy. As such, the Logistics and Marketing segment results include effects of variable energy costs that impact both gross margin and operating expenses. Fractionation volumes for 2019 reflect volumes delivered and fractionated, whereas fractionation volumes for 2018 reflect volumes delivered and settled under fractionation contracts.
(3)   Export volumes represent the quantity of NGL products delivered to third-party customers at the Company's Galena Park Marine Terminal that are destined for international markets.

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

Logistics and Marketing gross margin increased due to higher LPG export margin, higher fractionation margin, partially offset by lower terminaling and storage throughput, and lower commercial transportation margin. LPG export margin increased primarily due to higher volumes despite restrictions and temporary closures of the Houston Ship Channel during the quarter. Fractionation margin increased due to higher supply volume, partially offset by lower system product gains. Fractionation margin was partially impacted by the variable effects of fuel and power that are largely reflected in operating expenses (see footnote (2) above). Terminaling and storage throughput decreased due to the sale of certain petroleum logistics storage and terminaling facilities in the fourth quarter of 2018. Commercial transportation margin decreased due to the sale of the Company’s inland marine barge business in the second quarter of 2018. 

Operating expenses decreased due to lower taxes and maintenance. 

Other

    Three Months Ended March 31,          
    2019     2018     2019 vs. 2018  
       
    (In millions)  
Gross margin   $ 2.1     $ (17.8 )   $ 19.9  
Operating margin   $ 2.1     $ (17.8 )   $ 19.9  

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

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

    Three Months Ended March   31, 2019     Three Months Ended March   31, 2018  
       
    (In millions, except volumetric data and price amounts)  
    Volume
Settled
    Price
Spread
(1)
    Gain
(Loss)
    Volume
Settled
    Price
Spread
(1)
    Gain
(Loss)
 
Natural gas (BBtu)     12.1     $ 0.72     $ 8.7       17.4     $ 0.33     $ 5.8  
NGL (MMgal)     69.4       0.01       0.5       87.2       (0.11 )     (9.4 )
Crude oil (MBbl)     0.3       (0.04 )           0.4       (10.30 )     (4.6 )
Non-hedge accounting (2)                     (7.1 )                     (9.6 )
                    $ 2.1                     $ (17.8 )

____________
(1)   The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
(2)   Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes.

About Targa Resources Corp.

Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. The Company owns, operates, acquires, and develops a diversified portfolio of complementary midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, transporting and selling natural gas; transporting, storing, fractionating, treating, and selling NGLs and NGL products, including services to LPG exporters; and gathering, storing, terminaling and selling crude oil.

For more information, please visit the Company’s website at www.targaresources.com.

Targa Resources Corp. - Non-GAAP Financial Measures

This press release includes the Company’s non-GAAP financial measures: Adjusted EBITDA, distributable cash flow, gross margin and operating margin. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. The Company’s non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities or any other GAAP measure of liquidity or financial performance.

Adjusted EBITDA

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

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

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

Distributable Cash Flow

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

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

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

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

The following table presents a reconciliation of net income of the Company to Adjusted EBITDA and Distributable Cash Flow for the periods indicated:

    Three Months Ended March 31,  
    2019     2018  
       
    (In millions)  
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA and Distributable Cash Flow                
Net income (loss) attributable to TRC   $ (38.9 )   $ 22.9  
Income attributable to TRP preferred limited partners     2.8       2.8  
Interest (income) expense, net (1)     80.6       (16.1 )
Income tax expense (benefit)     (2.9 )     8.9  
Depreciation and amortization expense     237.4       198.1  
(Gain) loss on sale or disposition of assets     3.2       (0.1 )
(Gain) loss from financing activities (2)     1.4        
Equity (earnings) loss     (2.8 )     (1.5 )
Distributions from unconsolidated affiliates and preferred partner interests, net     6.8       6.9  
Change in contingent considerations     9.7       56.1  
Compensation on equity grants     16.5       13.2  
Splitter Agreement (3)           10.8  
Risk management activities     7.2       9.7  
Noncontrolling interests adjustments (4)     (7.1 )     (5.1 )
TRC Adjusted EBITDA   $ 313.9     $ 306.6  
Distributions to TRP preferred limited partners     (2.8 )     (2.8 )
Splitter Agreement (3)           (10.8 )
Interest expense on debt obligations (5)     (80.0 )     (54.8 )
Maintenance capital expenditures     (35.6 )     (22.3 )
Noncontrolling interests adjustments of maintenance capital expenditures     1.2       0.5  
Distributable Cash Flow   $ 196.7     $ 216.4  

____________
(1)   Includes the change in estimated redemption value of the mandatorily redeemable preferred interests.
(2)   Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments.
(3)   In Adjusted EBITDA, the Splitter Agreement adjustment represents the recognition of the annual cash payment received under the condensate splitter agreement over the four quarters following receipt. In Distributable Cash Flow, the Splitter Agreement adjustment represents the amounts necessary to reflect the annual cash payment in the period received less the amount recognized in Adjusted EBITDA. As a result of Vitol Americas Corp.’s election to terminate the Splitter Agreement in December 2018, the full amount of the 2018 annual cash payment was recognized in Adjusted EBITDA in the fourth quarter of 2018.
(4)   Noncontrolling interest portion of depreciation and amortization expense.
(5)   Excludes amortization of interest expense.

Gross Margin

The Company defines gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by the Company’s contract mix and commodity hedging program.

Gathering and Processing segment gross margin consists primarily of:

  • revenues from the sale of natural gas, condensate, crude oil and NGLs less producer payments and other natural gas and crude oil purchases; and
  • service fees related to natural gas and crude oil gathering, treating and processing.

Logistics and Marketing segment gross margin consists primarily of:

  • service fees (including the pass-through of energy costs included in fee rates);
  • system product gains and losses; and
  • NGL and natural gas sales, less NGL and natural gas purchases, transportation costs and the net inventory change.

The gross margin impacts of the Company’s equity volumes hedge settlements are reported in Other.

Operating Margin

The Company defines operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of the Company’s operations.

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

  • the financial performance of the Company’s assets without regard to financing methods, capital structure or historical cost basis;
  • the Company’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
  • the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

The following table presents a reconciliation of net income of the Company to operating margin and gross margin for the periods indicated:

    Three Months Ended March 31,  
    2019     2018  
    (In millions)  
Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin                
Net income (loss) attributable to TRC   $ (38.9 )   $ 22.9  
Net income (loss) attributable to noncontrolling interests     14.2       16.0  
Net income (loss)     (24.7 )     38.9  
Depreciation and amortization expense     237.4       198.1  
General and administrative expense     81.1       56.7  
Interest (income) expense, net     80.6       (16.1 )
Income tax expense (benefit)     (2.9 )     8.9  
(Gain) loss on sale or disposition of assets     3.2       (0.1 )
(Gain) loss from financing activities     1.4        
Change in contingent considerations     9.7       56.1  
Other, net     (2.6 )     (1.1 )
Operating margin     383.2       341.4  
Operating expenses     190.2       173.2  
Gross margin   $ 573.4     $ 514.6  
                 


Forward-Looking Statements

Certain statements in this release are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Company’s control, which could cause results to differ materially from those expected by management of the Company. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas, natural gas liquids and crude oil, the timing and success of business development efforts; and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Company’s filings with the Securities and Exchange Commission, including its Annual Report on Form 10-K for the year ended December 31, 2018, and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Contact the Company's investor relations department by email at InvestorRelations@targaresources.com or by phone at (713) 584-1133.

Sanjay Lad
Senior Director, Finance & Investor Relations

Jennifer Kneale
Chief Financial Officer

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