Targa Resources Corp. Reports Fourth Quarter and Full Year 2020 Financial Results and Provides 2021 Operational and Financial Outlook
Targa Resources Corp. (TRGP) reported a fourth quarter 2020 net income of $33.6 million, significantly improving from a loss of $112.8 million in Q4 2019. For the full year, Targa's net loss narrowed to $1,553.9 million compared to $209.2 million in 2019, influenced by a total impairment charge of $2.4 billion. Adjusted EBITDA for Q4 2020 was $438.1 million, down from $465.2 million the previous year but reflecting a 5% increase from Q3 2020. The quarterly dividend was declared at $0.10 per share. Targa estimates a full-year 2021 Adjusted EBITDA between $1.675 billion and $1.775 billion.
- Fourth quarter net income of $33.6 million, up from a loss of $112.8 million in Q4 2019.
- Adjusted EBITDA for Q4 2020 at $438.1 million, a sequential increase of 5%.
- Estimated 2021 Adjusted EBITDA guidance of $1.675 billion to $1.775 billion, suggesting growth.
- Full year 2020 net loss of $1,553.9 million compared to $209.2 million in 2019.
- Significant impairment charges totaling $2.4 billion in 2020.
HOUSTON, Feb. 18, 2021 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported fourth quarter and full year 2020 results.
Fourth Quarter and Full Year 2020 Financial Results
Fourth quarter 2020 net income (loss) attributable to Targa Resources Corp. was
The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of
On January 20, 2021, TRC declared a quarterly dividend of
The Company reported distributable cash flow and free cash flow before dividends for the fourth quarter of 2020 of
Fourth Quarter 2020 - Sequential Quarter over Quarter Commentary
Targa reported fourth quarter 2020 Adjusted EBITDA of
Capitalization and Liquidity
The Company’s total consolidated debt as of December 31, 2020 was
Total consolidated liquidity as of December 31, 2020, was over
Financing Update
In November 2020, the Partnership redeemed the
In December 2020, the Partnership redeemed all of its 5,000,000 issued and outstanding
In December 2020, Targa repurchased 45,800 shares of the Company’s Series A Preferred Stock at
In February 2021, the Partnership issued
Share Repurchase Update
In October 2020, the Company’s Board of Directors approved a share repurchase program (the “Share Repurchase Program”) for the repurchase of up to
2021 Operational and Financial Expectations
The 2021 operational and financial expectations presented herein were developed in advance of the impacts of the severe winter weather currently being experienced across Targa’s operations. Both G&P and L&T operations have been affected and the impacts are being evaluated.
Targa estimates 2021 average Permian natural gas inlet volumes will increase 5 percent to 10 percent over its 2020 average Permian natural gas inlet volumes. Targa estimates 2021 average total Field Gathering and Processing natural gas inlet volumes will be flat over the 2020 average. In its L&T segment, Targa estimates average Grand Prix volume deliveries into Mont Belvieu to increase 25 percent or more over 2020.
For 2021, Targa estimates full year Adjusted EBITDA to be between
An earnings supplement presentation and an updated investor presentation are available under Events and Presentations in the Investors section of the Company’s website at www.targaresources.com/investors/events.
Conference Call
The Company will host a conference call for the investment community at 12:00 p.m. Eastern time (11:00 a.m. Central time) on February 23, 2021 to discuss fourth quarter and full year 2020 results. The conference call can be accessed via webcast under Events and Presentations in the Investors section of the Company’s website at www.targaresources.com/investors/events, or by going directly to https://edge.media-server.com/mmc/p/ch8ddv3n. 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 December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2020 vs. 2019 | 2020 | 2019 | 2020 vs. 2019 | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||||||
| Sales of commodities | $ | 2,270.2 | $ | 2,139.1 | $ | 131.1 | 6 | % | $ | 7,171.0 | $ | 7,393.8 | $ | (222.8 | ) | (3 | %) | |||||||||||||
| Fees from midstream services | 302.6 | 334.8 | (32.2 | ) | (10 | %) | 1,089.3 | 1,277.3 | (188.0 | ) | (15 | %) | ||||||||||||||||||
| Total revenues | 2,572.8 | 2,473.9 | 98.9 | 4 | % | 8,260.3 | 8,671.1 | (410.8 | ) | (5 | %) | |||||||||||||||||||
| Product purchases | 1,758.3 | 1,702.8 | 55.5 | 3 | % | 5,105.1 | 6,118.5 | (1,013.4 | ) | (17 | %) | |||||||||||||||||||
| Gross margin (1) | 814.5 | 771.1 | 43.4 | 6 | % | 3,155.2 | 2,552.6 | 602.6 | 24 | % | ||||||||||||||||||||
| Operating expenses | 214.7 | 192.1 | 22.6 | 12 | % | 779.8 | 792.9 | (13.1 | ) | (2 | %) | |||||||||||||||||||
| Operating margin (1) | 599.8 | 579.0 | 20.8 | 4 | % | 2,375.4 | 1,759.7 | 615.7 | 35 | % | ||||||||||||||||||||
| Depreciation and amortization expense | 217.8 | 252.7 | (34.9 | ) | (14 | %) | 865.1 | 971.6 | (106.5 | ) | (11 | %) | ||||||||||||||||||
| General and administrative expense | 74.0 | 57.2 | 16.8 | 29 | % | 254.6 | 280.7 | (26.1 | ) | (9 | %) | |||||||||||||||||||
| Impairment of long-lived assets | — | 225.3 | (225.3 | ) | (100 | %) | 2,442.8 | 225.3 | 2,217.5 | NM | ||||||||||||||||||||
| Other operating (income) expense | 42.8 | 67.5 | (24.7 | ) | (37 | %) | 116.6 | 89.2 | 27.4 | 31 | % | |||||||||||||||||||
| Income (loss) from operations | 265.2 | (23.7 | ) | 288.9 | NM | (1,303.7 | ) | 192.9 | (1,496.6 | ) | NM | |||||||||||||||||||
| Interest expense, net | (98.9 | ) | (96.0 | ) | (2.9 | ) | 3 | % | (391.3 | ) | (337.8 | ) | (53.5 | ) | 16 | % | ||||||||||||||
| Equity earnings (loss) | 18.5 | 23.1 | (4.6 | ) | (20 | %) | 72.6 | 39.0 | 33.6 | 86 | % | |||||||||||||||||||
| Gain (loss) from financing activities | (1.8 | ) | — | (1.8 | ) | — | 45.6 | (1.4 | ) | 47.0 | NM | |||||||||||||||||||
| Gain (loss) from sale of equity-method investment | — | 3.5 | (3.5 | ) | (100 | %) | — | 69.3 | (69.3 | ) | (100 | %) | ||||||||||||||||||
| Change in contingent considerations | 0.3 | — | 0.3 | — | 0.3 | (8.7 | ) | 9.0 | 103 | % | ||||||||||||||||||||
| Other, net | 1.2 | 0.1 | 1.1 | NM | 3.4 | — | 3.4 | — | ||||||||||||||||||||||
| Income tax (expense) benefit | (38.5 | ) | 77.9 | (116.4 | ) | (149 | %) | 248.1 | 87.9 | 160.2 | 182 | % | ||||||||||||||||||
| Net income (loss) | 146.0 | (15.1 | ) | 161.1 | NM | (1,325.0 | ) | 41.2 | (1,366.2 | ) | NM | |||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 112.4 | 97.7 | 14.7 | 15 | % | 228.9 | 250.4 | (21.5 | ) | (9 | %) | |||||||||||||||||||
| Net income (loss) attributable to Targa Resources Corp. | 33.6 | (112.8 | ) | 146.4 | 130 | % | (1,553.9 | ) | (209.2 | ) | (1,344.7 | ) | NM | |||||||||||||||||
| Dividends on Series A Preferred Stock | 22.9 | 22.9 | — | — | 91.7 | 91.7 | — | — | ||||||||||||||||||||||
| Deemed dividends on Series A Preferred Stock | 11.5 | 8.7 | 2.8 | 32 | % | 39.2 | 33.1 | 6.1 | 18 | % | ||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | (0.8 | ) | $ | (144.4 | ) | $ | 143.6 | 99 | % | $ | (1,684.8 | ) | $ | (334.0 | ) | $ | (1,350.8 | ) | NM | ||||||||||
| Financial data: | ||||||||||||||||||||||||||||||
| Adjusted EBITDA (1) | $ | 438.1 | $ | 465.2 | $ | (27.1 | ) | (6 | %) | $ | 1,636.6 | $ | 1,435.5 | $ | 201.1 | 14 | % | |||||||||||||
| Distributable cash flow (1) | 293.9 | 327.8 | (33.9 | ) | (10 | %) | 1,172.8 | 947.2 | 225.6 | 24 | % | |||||||||||||||||||
| Free cash flow (1) | 214.5 | (7.7 | ) | 222.2 | NM | 574.9 | (1,334.5 | ) | 1,909.4 | NM | ||||||||||||||||||||
(1) Gross margin, operating margin, Adjusted EBITDA, distributable cash flow and free cash flow are non-GAAP financial measures and are discussed under “Targa Resources Corp. – Non-GAAP Financial Measures.”
NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.
Three Months Ended December 31, 2020 Compared to Three Months Ended December 31, 2019
The increase in sales of commodities reflects higher natural gas liquid (“NGL”) and natural gas volumes (
The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, lower gas processing volumes and lower transportation fees, partially offset by increased export and pipeline transport volumes.
The increase in product purchases reflects higher NGL and natural gas volumes and prices, partially offset by lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, and lower petroleum products and condensate volumes.
Higher operating margin and gross margin in 2020 reflect increased segment results for both Gathering and Processing and Logistics and Transportation. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.
Depreciation and amortization expense decreased primarily due to a lower depreciable base associated with assets that were impaired during 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by depreciation related to major growth capital projects placed in service, including Train 7 in the first quarter of 2020 and the additional processing plants and associated infrastructure in the Permian Basin.
General and administrative expense increased primarily due to higher compensation and benefits and an increase in insurance costs.
The Company recognized a non-cash pre-tax impairment charge of
Other operating (income) expense in 2020 consisted primarily of write-downs of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the sale of the Company’s Delaware crude system, which was effective December 1, 2019, and write-down of certain assets to their recoverable amounts.
Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.
The decrease in equity earnings is primarily due to lower earnings from the Company’s investments in Gulf Coast Fractionators LP (“GCF”) and Gulf Coast Express Pipeline LLC (“GCX”).
During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 5¼% Senior Notes due 2023, resulting in a
During 2019, the Company closed on the sale of an equity-method investment that resulted in a gain during the fourth quarter of
The increase in income tax expense is primarily due to differences in pre-tax book income (loss) and a valuation allowance in 2020.
Net income attributable to noncontrolling interests was higher in 2020 primarily due to increased earnings allocated to interests holders in Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), Grand Prix Development LLC (“Grand Prix DevCo Joint Venture”) and Carnero G&P LLC.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
The decrease in sales of commodities reflects lower NGL, condensate, petroleum product and natural gas prices (
The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, partially offset by increased export and terminaling and storage volumes.
The decrease in product purchases reflects lower NGL, condensate, petroleum product and natural gas prices, lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, and lower petroleum products volumes, partially offset by higher NGL, natural gas and condensate volumes.
Higher operating margin and gross margin in 2020 reflect increased segment results for both Gathering and Processing and Logistics and Transportation. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.
Depreciation and amortization expense decreased primarily due to a lower depreciable base associated with assets that were impaired during 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by depreciation related to major growth capital projects placed in service, including Train 7 in the first quarter of 2020, the additional processing plants and associated infrastructure in the Permian Basin and a full year of depreciation related to Grand Prix, which was placed in service in the third quarter of 2019.
General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs.
The Company recognized non-cash pre-tax impairment charges of
Other operating (income) expense in 2020 consisted primarily of a loss associated with the sale of the Company’s assets in Channelview, Texas and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the sale of the Company’s Delaware crude system, which was effective December 1, 2019, and write-down of certain assets to their recoverable amounts.
Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.
The increase in equity earnings is primarily due to higher earnings from the Company’s investments in GCX and Little Missouri 4 LLC (“Little Missouri 4”), partially offset by lower earnings from GCF.
During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024 and the 5¼% Senior Notes due 2023, resulting in a
During 2019, the Partnership closed on the sale of an equity-method investment that resulted in a gain of
The increase in income tax benefit is primarily due to a higher pre-tax book loss and benefit of a net operating loss carryback from the CARES Act, partially offset by a valuation allowance in 2020.
Net income attributable to noncontrolling interests was lower in 2020 primarily due to the allocation of non-cash pre-tax impairment losses recognized during the first quarter of 2020, partially offset by increased earnings allocated to interests holders in the three development joint ventures with investment vehicles affiliated with Stonepeak Infrastructure Partners to fund portions of Grand Prix pipeline, Gulf Coast Express Pipeline and a fractionator in Mont Belvieu, Texas, Targa Badlands LLC and Grand Prix Joint Venture.
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 Transportation.
Gathering and Processing Segment
The Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central 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 (including the Bakken and Three Forks plays); and 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 December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2020 vs. 2019 | 2020 | 2019 | 2020 vs. 2019 | |||||||||||||||||||||||||
| (In millions, except operating statistics and price amounts) | ||||||||||||||||||||||||||||||
| Gross margin | $ | 378.6 | $ | 403.9 | $ | (25.3 | ) | (6 | %) | $ | 1,450.3 | $ | 1,496.0 | $ | (45.7 | ) | (3 | %) | ||||||||||||
| Operating expenses | 114.7 | 114.2 | 0.5 | 0 | % | 432.6 | 489.6 | (57.0 | ) | (12 | %) | |||||||||||||||||||
| Operating margin | $ | 263.9 | $ | 289.7 | $ | (25.8 | ) | (9 | %) | $ | 1,017.7 | $ | 1,006.4 | $ | 11.3 | 1 | % | |||||||||||||
| Operating statistics (1): | ||||||||||||||||||||||||||||||
| Plant natural gas inlet, MMcf/d (2),(3) | ||||||||||||||||||||||||||||||
| Permian Midland (4) | 1,815.4 | 1,621.0 | 194.4 | 12 | % | 1,745.6 | 1,471.6 | 274.0 | 19 | % | ||||||||||||||||||||
| Permian Delaware | 779.8 | 740.7 | 39.1 | 5 | % | 729.4 | 599.7 | 129.7 | 22 | % | ||||||||||||||||||||
| Total Permian | 2,595.2 | 2,361.7 | 233.5 | 2,475.0 | 2,071.3 | 403.7 | ||||||||||||||||||||||||
| SouthTX (5) | 208.0 | 279.4 | (71.4 | ) | (26 | %) | 248.1 | 321.2 | (73.1 | ) | (23 | %) | ||||||||||||||||||
| North Texas | 187.4 | 224.9 | (37.5 | ) | (17 | %) | 201.6 | 226.9 | (25.3 | ) | (11 | %) | ||||||||||||||||||
| SouthOK (6) | 382.4 | 606.1 | (223.7 | ) | (37 | %) | 443.0 | 606.1 | (163.1 | ) | (27 | %) | ||||||||||||||||||
| WestOK | 222.2 | 315.3 | (93.1 | ) | (30 | %) | 249.5 | 330.2 | (80.7 | ) | (24 | %) | ||||||||||||||||||
| Total Central | 1,000.0 | 1,425.7 | (425.7 | ) | 1,142.2 | 1,484.4 | (342.2 | ) | ||||||||||||||||||||||
| Badlands (7),(8) | 142.8 | 156.2 | (13.4 | ) | (9 | %) | 137.8 | 116.7 | 21.1 | 18 | % | |||||||||||||||||||
| Total Field | 3,738.0 | 3,943.6 | (205.6 | ) | 3,755.0 | 3,672.4 | 82.6 | |||||||||||||||||||||||
| Coastal | 555.0 | 757.6 | (202.6 | ) | (27 | %) | 643.3 | 774.2 | (130.9 | ) | (17 | %) | ||||||||||||||||||
| Total | 4,293.0 | 4,701.2 | (408.2 | ) | (9 | %) | 4,398.3 | 4,446.6 | (48.3 | ) | (1 | %) | ||||||||||||||||||
| NGL production, MBbl/d (3) | ||||||||||||||||||||||||||||||
| Permian Midland (4) | 260.2 | 236.7 | 23.5 | 10 | % | 250.8 | 209.1 | 41.7 | 20 | % | ||||||||||||||||||||
| Permian Delaware | 105.3 | 99.7 | 5.6 | 6 | % | 99.1 | 78.6 | 20.5 | 26 | % | ||||||||||||||||||||
| Total Permian | 365.5 | 336.4 | 29.1 | 349.9 | 287.7 | 62.2 | ||||||||||||||||||||||||
| SouthTX (5) | 18.5 | 34.4 | (15.9 | ) | (46 | %) | 26.1 | 41.6 | (15.5 | ) | (37 | %) | ||||||||||||||||||
| North Texas | 22.1 | 26.3 | (4.2 | ) | (16 | %) | 23.9 | 26.8 | (2.9 | ) | (11 | %) | ||||||||||||||||||
| SouthOK (6) | 45.9 | 72.1 | (26.2 | ) | (36 | %) | 52.4 | 67.1 | (14.7 | ) | (22 | %) | ||||||||||||||||||
| WestOK | 17.8 | 19.3 | (1.5 | ) | (8 | %) | 20.3 | 21.6 | (1.3 | ) | (6 | %) | ||||||||||||||||||
| Total Central | 104.3 | 152.1 | (47.8 | ) | 122.7 | 157.1 | (34.4 | ) | ||||||||||||||||||||||
| Badlands (8) | 16.1 | 18.3 | (2.2 | ) | (12 | %) | 16.3 | 13.8 | 2.5 | 18 | % | |||||||||||||||||||
| Total Field | 485.9 | 506.8 | (20.9 | ) | 488.9 | 458.6 | 30.3 | |||||||||||||||||||||||
| Coastal | 35.7 | 46.1 | (10.4 | ) | (23 | %) | 40.0 | 46.8 | (6.8 | ) | (15 | %) | ||||||||||||||||||
| Total | 521.6 | 552.9 | (31.3 | ) | (6 | %) | 528.9 | 505.4 | 23.5 | 5 | % | |||||||||||||||||||
| Crude oil, Badlands, MBbl/d | 144.7 | 189.0 | (44.3 | ) | (23 | %) | 156.5 | 172.6 | (16.1 | ) | (9 | %) | ||||||||||||||||||
| Crude oil, Permian, MBbl/d (9) | 37.4 | 74.9 | (37.5 | ) | (50 | %) | 43.3 | 83.3 | (40.0 | ) | (48 | %) | ||||||||||||||||||
| Natural gas sales, BBtu/d (3),(10) | 2,140.8 | 2,048.6 | 92.2 | 5 | % | 2,094.8 | 2,020.6 | 74.2 | 4 | % | ||||||||||||||||||||
| NGL sales, MBbl/d (3),(10) | 380.3 | 420.1 | (39.8 | ) | (9 | %) | 399.5 | 391.9 | 7.6 | 2 | % | |||||||||||||||||||
| Condensate sales, MBbl/d | 13.6 | 12.4 | 1.2 | 10 | % | 15.5 | 12.3 | 3.2 | 26 | % | ||||||||||||||||||||
| Average realized prices - inclusive of hedges (11): | ||||||||||||||||||||||||||||||
| Natural gas, $/MMBtu | 1.75 | 1.48 | 0.27 | 18 | % | 1.27 | 1.35 | (0.08 | ) | (6 | %) | |||||||||||||||||||
| NGL, $/gal | 0.32 | 0.32 | — | — | 0.26 | 0.34 | (0.08 | ) | (24 | %) | ||||||||||||||||||||
| Condensate, $/Bbl | 42.37 | 51.44 | (9.07 | ) | (18 | %) | 39.40 | 49.99 | (10.59 | ) | (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 year and the denominator is the number of calendar days during the year.
(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
(5) SouthTX includes the Raptor Plant, of which the Company owns a
(6) SouthOK includes the Centrahoma Joint Venture, of which the Company owns
(7) Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 Plant.
(8) As of April 3, 2019, Targa owns
(9) Permian crude oil volumes reflect the sale of the Delaware crude system, which was effective December 1, 2019.
(10) Natural gas and NGL sales statistics in 2020 include statistics related to new commercial arrangements effective in January 2020, which resulted in a change from net presentation as “Fees from midstream services” to gross presentation as “Sales of commodities” and “Product purchases”. This change in presentation did not result in an impact to the Company’s operating or gross margin.
(11) Average realized prices include the effect of realized commodity hedge gain/loss attributable to the Company’s equity volumes, previously shown in Other. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator.
The following table presents the realized commodity hedge gain/(loss) attributable to the Company’s equity volumes that are included in the gross margin of Gathering and Processing segment:
| Three Months Ended December 31, 2020 | Three Months Ended December 31, 2019 | |||||||||||||||||||||||
| (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) | 17.5 | $ | (0.15 | ) | $ | (2.6 | ) | 15.9 | $ | 0.83 | $ | 13.1 | ||||||||||||
| NGL (MMgal) | 129.3 | 0.03 | 3.6 | 117.6 | 0.09 | 10.1 | ||||||||||||||||||
| Crude oil (MBbl) | 0.5 | 15.09 | 7.2 | 0.4 | (2.10 | ) | (0.9 | ) | ||||||||||||||||
| $ | 8.2 | $ | 22.3 | |||||||||||||||||||||
| Year Ended December 31, 2020 | Year Ended December 31, 2019 | |||||||||||||||||||||||
| (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) | 68.1 | $ | 0.37 | $ | 25.1 | 62.9 | $ | 1.17 | $ | 73.7 | ||||||||||||||
| NGL (MMgal) | 451.4 | 0.12 | 53.3 | 369.7 | 0.10 | 38.0 | ||||||||||||||||||
| Crude oil (MBbl) | 1.9 | 18.54 | 34.9 | 1.5 | (2.29 | ) | (3.5 | ) | ||||||||||||||||
| $ | 113.3 | $ | 108.2 | |||||||||||||||||||||
(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
Three Months Ended December 31, 2020 Compared to Three Months Ended December 31, 2019
The decrease in Gathering and Processing segment gross margin was primarily due to lower volumes in the Central region and the Badlands and lower realized hedge gains, partially offset by higher system volumes and fee-based margin in the Permian region. Lower volumes in the Central region and the Badlands were attributable to reduced producer activity and continued producer shut-ins. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Peregrine and Gateway plants in 2020. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the fourth quarter of 2020, which necessitated temporary shut downs of certain facilities. Total crude oil volumes decreased in the Badlands due to reduced producer activity, while the decrease in the Permian was primarily due to the sale of the Delaware Crude System in the fourth quarter of 2019.
Operating expenses were lower due to cost reduction measures implemented in response to the impact of the COVID-19 pandemic on the Company’s business, which resulted in decreases in compensation and benefits, chemicals and contract labor, despite the addition of the Peregrine and Gateway processing facilities in the Permian.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
During the year ended December 31, 2020, the COVID-19 pandemic reduced economic activity and the related demand for energy commodities, which contributed to weak commodity prices compared to historical levels and price volatility. The drop in commodity prices also resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production, particularly during the second quarter.
The resulting decrease in Gathering and Processing segment gross margin was primarily due to lower Central region volumes and lower commodity prices, partially offset by higher inlet volumes and fee-based margin in the Permian region and the Badlands and higher realized hedge gains. Lower volumes in the Central region were attributable to reduced producer activity and temporary shut-ins. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third and fourth quarters of 2020, which necessitated temporary shut downs of certain facilities. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.
Operating expenses were lower due to cost reduction measures implemented in response to the impact of the COVID-19 pandemic on the Company’s business, which resulted in decreases in contract labor, chemicals and compressor rentals, despite the addition of the Peregrine and Gateway processing facilities in the Permian.
Logistics and Transportation Segment
The Logistics and Transportation 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 transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to liquefied petroleum gas exporters and certain natural gas supply and marketing activities in support of the Company’s other businesses. The Logistics and Transportation segment also includes Grand Prix, which connects 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, as well as the Company’s equity interest in GCX, a natural gas pipeline connecting the Waha hub in West Texas and other receipt points, including many of the Company’s Midland Basin processing facilities, to Agua Dulce in South Texas and other delivery points. The associated assets, including these pipelines, are generally connected to and supplied in part by the Company’s Gathering and Processing segment and, except for the pipelines 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 December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2020 vs. 2019 | 2020 | 2019 | 2020 vs. 2019 | |||||||||||||||||||||||||||||||||
| (In millions, except operating statistics and price amounts) | ||||||||||||||||||||||||||||||||||||||
| Gross margin | $ | 423.7 | $ | 381.2 | $ | 42.5 | 11 | % | $ | 1,480.7 | $ | 1,173.9 | $ | 306.8 | 26 | % | ||||||||||||||||||||||
| Operating expenses (1) | 101.7 | 79.2 | 22.5 | 28 | % | 352.7 | 306.7 | 46.0 | 15 | % | ||||||||||||||||||||||||||||
| Operating margin | $ | 322.0 | $ | 302.0 | $ | 20.0 | 7 | % | $ | 1,128.0 | $ | 867.2 | $ | 260.8 | 30 | % | ||||||||||||||||||||||
| Operating statistics MBbl/d (2): | ||||||||||||||||||||||||||||||||||||||
| Fractionation volumes (3) | 632.3 | 596.7 | 35.6 | 6 | % | 602.9 | 519.0 | 83.9 | 16 | % | ||||||||||||||||||||||||||||
| Export volumes (4) | 369.5 | 267.1 | 102.4 | 38 | % | 300.4 | 237.9 | 62.5 | 26 | % | ||||||||||||||||||||||||||||
| Pipeline throughput (5) | 355.4 | 266.4 | 89.0 | 33 | % | 293.7 | 100.4 | 193.3 | NM | |||||||||||||||||||||||||||||
| NGL sales | 844.4 | 740.3 | 104.1 | 14 | % | 752.5 | 651.0 | 101.5 | 16 | % | ||||||||||||||||||||||||||||
(1) Effective January 1, 2020, pursuant to amendments to contractual arrangements with the Company’s partners, the Company’s share of operating expenses associated with GCF, an investment in an unconsolidated affiliate, are included in operating expenses.
(2) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year.
(3) 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 Transportation segment results include effects of variable energy costs that impact both gross margin and operating expenses.
(4) 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.
(5) Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu.
NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.
Three Months Ended December 31, 2020 Compared to Three Months Ended December 31, 2019
The increase in Logistics and Transportation segment gross margin was driven by higher pipeline transportation, fractionation and LPG export system volumes from higher supply volumes from the Company’s Permian Gathering and Processing systems and associated downstream system expansions, partially offset by fewer optimization opportunities in the Company’s marketing businesses. NGL transportation and fractionation volumes increased due to higher volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and the commencement of operations of Train 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020.
Operating expenses were higher due to system expansions, including Grand Prix, fractionation capacity and expansion of the Company’s LPG export capabilities, certain one-time maintenance expenses including hurricane damage repairs, higher fuel and power costs, and the Company’s share of operating expenses associated with GCF, partially offset by cost reduction measures.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
The increase in Logistics and Transportation segment gross margin was driven by higher pipeline transportation, fractionation and LPG export system volumes from higher supply volumes from the Company’s Permian Gathering and Processing systems and associated downstream system expansions, partially offset by fewer optimization opportunities in the Company’s marketing businesses. NGL transportation and fractionation volumes increased due to higher volumes delivered on Grand Prix and the commencement of operations of Train 6 in the second quarter of 2019, Train 7 and Train 8.
Operating expenses were higher due to system expansions, including Grand Prix, fractionation capacity and expansion of the Company’s LPG export capabilities and the Company’s share of operating expenses associated with GCF and certain one-time maintenance expenses including hurricane damage repairs, partially offset by lower fuel and power costs and cost reduction measures.
Other
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2020 | 2019 | 2020 vs. 2019 | 2020 | 2019 | 2020 vs. 2019 | |||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Gross margin | $ | 13.8 | $ | (12.7 | ) | $ | 26.5 | $ | 229.7 | $ | (113.9 | ) | $ | 343.6 | ||||||||||
| Operating margin | $ | 13.8 | $ | (12.7 | ) | $ | 26.5 | $ | 229.7 | $ | (113.9 | ) | $ | 343.6 | ||||||||||
Other contains the results of commodity derivative activity mark-to-market gains/(losses) related to derivative contracts that were not designated as cash flow hedges. The Company has entered into derivative instruments to hedge the commodity price associated with a portion of the Company’s future commodity purchases and sales and natural gas transportation basis risk within the Company’s Logistics and Transportation segment.
About Targa Resources Corp.
Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream infrastructure companies in North America. The Company owns, operates, acquires and develops a diversified portfolio of complementary midstream infrastructure assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, transporting and purchasing and selling natural gas; transporting, storing, fractionating, treating and purchasing and selling NGLs and NGL products, including services to LPG exporters; and gathering, storing, terminaling and purchasing 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, free 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. These 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.
The Company utilizes non-GAAP measures to analyze the Company’s performance. Gross margin, operating margin, Adjusted EBITDA, distributable cash flow, and free cash flow are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP measures is net income (loss) attributable to TRC. These non-GAAP measures should not be considered as an alternative to GAAP net income attributable to TRC and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Additionally, because the Company’s non-GAAP measures exclude some, but not all, items that affect net income, and are defined differently by different companies within the Company’s industry, the Company’s definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of the Company’s non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into the Company’s decision-making processes.
Adjusted EBITDA
Adjusted EBITDA is defined 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 the Company’s financial statements such as investors, commercial banks and others to measure the ability of the Company’s assets to generate cash sufficient to pay interest costs, support the Company’s indebtedness and pay dividends to the Company’s investors.
Distributable Cash Flow and Free Cash Flow
Distributable cash flow is defined as Adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). The Preferred Units issued by the Partnership in October 2015 were redeemed in December 2020 and are no longer outstanding as of the end of the year. Free cash flow is defined as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and free cash flow are performance measures used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to assess the Company’s ability to generate cash earnings (after servicing the Company’s debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.
The following table presents a reconciliation of net income attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Free Cash Flow for the periods indicated:
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Free Cash Flow | ||||||||||||||||||||
| Net income (loss) attributable to TRC | $ | 33.6 | $ | (112.8 | ) | $ | (1,553.9 | ) | $ | (209.2 | ) | |||||||||
| Income attributable to TRP preferred limited partners | 6.7 | 2.9 | 15.1 | 11.3 | ||||||||||||||||
| Interest (income) expense, net | 98.9 | 96.0 | 391.3 | 337.8 | ||||||||||||||||
| Income tax expense (benefit) | 38.5 | (77.9 | ) | (248.1 | ) | (87.9 | ) | |||||||||||||
| Depreciation and amortization expense | 217.8 | 252.7 | 865.1 | 971.6 | ||||||||||||||||
| Impairment of long-lived assets | — | 225.3 | 2,442.8 | 225.3 | ||||||||||||||||
| (Gain) loss on sale or disposition of business and assets | 0.4 | 63.8 | 58.4 | 71.1 | ||||||||||||||||
| Write-down of assets | 42.1 | 3.7 | 55.6 | 17.9 | ||||||||||||||||
| (Gain) loss from sale of equity-method investment | — | (3.5 | ) | — | (69.3 | ) | ||||||||||||||
| (Gain) loss from financing activities (1) | 1.8 | — | (45.6 | ) | 1.4 | |||||||||||||||
| Equity (earnings) loss | (18.5 | ) | (23.1 | ) | (72.6 | ) | (39.0 | ) | ||||||||||||
| Distributions from unconsolidated affiliates and preferred partner interests, net | 27.0 | 27.8 | 108.6 | 61.2 | ||||||||||||||||
| Change in contingent considerations | (0.3 | ) | (0.1 | ) | (0.3 | ) | 8.7 | |||||||||||||
| Compensation on equity grants | 16.7 | 11.3 | 66.2 | 60.3 | ||||||||||||||||
| Risk management activities | (14.0 | ) | 12.0 | (228.2 | ) | 112.8 | ||||||||||||||
| Severance and related benefits (2) | — | — | 6.5 | — | ||||||||||||||||
| Noncontrolling interests adjustments (3) | (12.6 | ) | (12.9 | ) | (224.3 | ) | (38.5 | ) | ||||||||||||
| TRC Adjusted EBITDA | $ | 438.1 | $ | 465.2 | $ | 1,636.6 | $ | 1,435.5 | ||||||||||||
| Distributions to TRP preferred limited partners | (6.7 | ) | (2.9 | ) | (15.1 | ) | (11.3 | ) | ||||||||||||
| Interest expense on debt obligations (4) | (99.4 | ) | (95.1 | ) | (388.9 | ) | (342.1 | ) | ||||||||||||
| Cash tax refund | — | — | 44.4 | — | ||||||||||||||||
| Maintenance capital expenditures | (41.8 | ) | (40.2 | ) | (109.5 | ) | (141.7 | ) | ||||||||||||
| Noncontrolling interests adjustments of maintenance capital expenditures | 3.7 | 0.8 | 5.3 | 6.8 | ||||||||||||||||
| Distributable Cash Flow | $ | 293.9 | $ | 327.8 | $ | 1,172.8 | $ | 947.2 | ||||||||||||
| Growth capital expenditures, net (5) | (79.4 | ) | (335.5 | ) | (597.9 | ) | (2,281.7 | ) | ||||||||||||
| Free Cash Flow | $ | 214.5 | $ | (7.7 | ) | $ | 574.9 | $ | (1,334.5 | ) | ||||||||||
(1) Gains or losses on debt repurchases or early debt extinguishments.
(2) Represents one-time severance and related benefit expense related to the Company’s cost reduction measures.
(3) Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests).
(4) Excludes amortization of interest expense.
(5) Represents growth capital expenditures, net of contributions from noncontrolling interests and net contributions to investments in unconsolidated affiliates.
The Company has completed a number of announced growth capital projects since early 2019, and this has resulted in lower growth capital expenditures in 2020 and a transition to free cash flow. The following table details construction and project completion timing of the Company’s announced major growth capital projects:
| Three Months Ended | ||||||||||||||||
| March 31, 2019 | June 30, 2019 | September 30, 2019 | December 31, 2019 | March 31, 2020 | June 30, 2020 | September 30, 2020 | December 31, 2020 | |||||||||
| Major Growth Capital Project (1): | ||||||||||||||||
| Gathering & Processing: | ||||||||||||||||
| Hopson Plant (2) | UC | C | ||||||||||||||
| Falcon Plant (3) | UC | UC | C | |||||||||||||
| Pembrook Plant (2) | UC | UC | C | |||||||||||||
| Little Missouri 4 Plant (4) | UC | UC | C | |||||||||||||
| Peregrine Plant (3) | UC | UC | UC | UC | UC | C | ||||||||||
| Gateway Plant (2) | UC | UC | UC | UC | C | |||||||||||
| Heim Plant (5) | UC | |||||||||||||||
| Logistics & Transportation: | ||||||||||||||||
| Train 6 | UC | C | ||||||||||||||
| Grand Prix NGL Pipeline | UC | UC | C | |||||||||||||
| Gulf Coast Express Pipeline | UC | UC | C | |||||||||||||
| Train 7 | UC | UC | UC | UC | C | |||||||||||
| Train 8 | UC | UC | UC | UC | UC | UC | C | |||||||||
| LPG Export Expansion | UC | UC | UC | UC | UC | UC | C | |||||||||
| Grand Prix Central OK Extension | UC | UC | UC | UC | UC | UC | UC | C | ||||||||
(1) “UC” and “C” indicates under construction and project completed, respectively, as of the end of the period presented above.
(2) Part of the Company’s Permian Midland operating area.
(3) Part of the Company’s Permian Delaware operating area.
(4) Part of the Company’s Badlands operating area.
(5) In November 2020, the Company announced the relocation of the former Longhorn Plant from the Company’s North Texas system to the Company’s Permian Midland system as the Heim Plant. The Heim Plant is expected to begin operations in the fourth quarter of 2021.
Gross Margin
Gross margin is defined 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:
- service fees related to natural gas and crude oil gathering, treating and processing; and
- revenues from the sale of natural gas, condensate, crude oil and NGLs less producer payments, natural gas and crude oil purchases, and the Company’s equity volume hedge settlements.
Logistics and Transportation 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, third-party transportation costs and the net inventory change.
The gross margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.
Operating Margin
Operating margin is defined 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 capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.
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 December 31, | Year Ended December 31, | |||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin | ||||||||||||||||||||
| Net income (loss) attributable to TRC | $ | 33.6 | $ | (112.8 | ) | $ | (1,553.9 | ) | $ | (209.2 | ) | |||||||||
| Net income (loss) attributable to noncontrolling interests | 112.4 | 97.7 | 228.9 | 250.4 | ||||||||||||||||
| Net income (loss) | 146.0 | (15.1 | ) | (1,325.0 | ) | 41.2 | ||||||||||||||
| Depreciation and amortization expense | 217.8 | 252.7 | 865.1 | 971.6 | ||||||||||||||||
| General and administrative expense | 74.0 | 57.2 | 254.6 | 280.7 | ||||||||||||||||
| Impairment of long-lived assets | — | 225.3 | 2,442.8 | 225.3 | ||||||||||||||||
| Interest (income) expense, net | 98.9 | 96.0 | 391.3 | 337.8 | ||||||||||||||||
| Equity (earnings) loss | (18.5 | ) | (23.1 | ) | (72.6 | ) | (39.0 | ) | ||||||||||||
| Income tax expense (benefit) | 38.5 | (77.9 | ) | (248.1 | ) | (87.9 | ) | |||||||||||||
| (Gain) loss on sale or disposition of business and assets | 0.4 | 63.8 | 58.4 | 71.1 | ||||||||||||||||
| Write-down of assets | 42.1 | 3.7 | 55.6 | 17.9 | ||||||||||||||||
| (Gain) loss from sale of equity-method investment | — | (3.5 | ) | — | (69.3 | ) | ||||||||||||||
| (Gain) loss from financing activities | 1.8 | — | (45.6 | ) | 1.4 | |||||||||||||||
| Change in contingent considerations | (0.3 | ) | (0.1 | ) | (0.3 | ) | 8.7 | |||||||||||||
| Other, net | (0.9 | ) | — | (0.8 | ) | 0.2 | ||||||||||||||
| Operating margin | $ | 599.8 | $ | 579.0 | $ | 2,375.4 | $ | 1,759.7 | ||||||||||||
| Operating expenses | 214.7 | 192.1 | 779.8 | 792.9 | ||||||||||||||||
| Gross margin | $ | 814.5 | $ | 771.1 | $ | 3,155.2 | $ | 2,552.6 | ||||||||||||
The following table presents a reconciliation of estimated net income of the Company to estimated Adjusted EBITDA for 2021:
| 2021E | |||
| (In millions) | |||
| Reconciliation of Estimated Net Income attributable to TRC to | |||
| Estimated Adjusted EBITDA | |||
| Net income attributable to TRC | $ | 300.0 | |
| Interest expense, net | 375.0 | ||
| Income tax expense | 100.0 | ||
| Depreciation and amortization expense | 895.0 | ||
| Equity earnings | (65.0 | ) | |
| Distributions from unconsolidated affiliates and preferred partner interests, net | 110.0 | ||
| Compensation on equity grants | 60.0 | ||
| Noncontrolling interest adjustments (1) | (50.0 | ) | |
| TRC Estimated Adjusted EBITDA | $ | 1,725.0 | |
(1) Noncontrolling interest portion of depreciation and amortization expense.
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 impact of pandemics such as COVID-19, actions by the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC oil producing countries, 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 most recent Annual Report on Form 10-K, 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
Vice President, Finance & Investor Relations
Jennifer Kneale
Chief Financial Officer
FAQ
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