HOUSTON, Aug. 06, 2020 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported second quarter 2020 results.
Second Quarter 2020 Financial Results
Second quarter 2020 net income (loss) attributable to Targa Resources Corp. was $81.0 million compared to a net loss of $(10.2) million for the second quarter of 2019.
The Company reported quarterly earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $351.2 million for the second quarter of 2020 compared to $306.5 million for the second quarter of 2019 (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”)).
On July 16, 2020, TRC declared a quarterly dividend of $0.10 per share of its common stock for the three months ended June 30, 2020, or $0.40 per share on an annualized basis. Total cash dividends of approximately $23.3 million will be paid on August 17, 2020 on all outstanding shares of common stock to holders of record as of the close of business on July 31, 2020. Also, on July 16, 2020, 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 August 14, 2020 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on July 31, 2020.
The Company reported distributable cash flow for the second quarter of 2020 of $273.7 million compared to total common dividends to be paid of $23.3 million and total Series A Preferred Stock dividends to be paid of $22.9 million.
Second Quarter 2020 - Sequential Quarter over Quarter Commentary
Targa reported second quarter 2020 Adjusted EBITDA of $351.2 million. The sequential decrease in Adjusted EBITDA was attributable to the low commodity price environment, and temporary production curtailments and reduced producer activity, which resulted in lower volumes across Targa’s Gathering and Processing (“G&P”) and Logistics and Transportation (“L&T”) systems during the second quarter, partially offset by cost reduction measures that resulted in lower aggregate operating and general and administrative expenses despite new assets being placed in-service during the quarter. In the G&P segment, lower sequential gross margin was predominantly attributable to lower volumes in the Badlands and Central region attributable to temporary production shut-ins and reduced producer activity, and lower average commodity price realizations. Targa’s second quarter natural gas inlet volumes in the Permian were relatively flat when compared to the first quarter, despite the impacts of temporary production shut-ins and reduced activity levels during the quarter. In the L&T segment, lower sequential gross margin was primarily due to lower marketing margin, and modestly lower sequential fractionation, pipeline transportation and liquefied petroleum gas (“LPG”) export volumes during the second quarter. Seasonality in Targa’s wholesale marketing businesses, combined with less optimization margin realized in its marketing businesses during the second quarter, accounted for about half of the sequential decline in segment gross margin when compared to the first quarter. Lower fractionation and pipeline transportation volumes were also due to temporary production shut-ins and reduced producer activity. Lower LPG export volumes were attributable to scheduled downtime to tie-in the phased expansion at Targa’s LPG export facility at Galena Park, which began operations in August.
Updated 2020 Outlook
While commodity prices remain low and uncertainties associated with the impacts of COVID-19 continue, in certain areas of Targa’s operations like the Permian Basin, production from wells that were previously shut-in during the second quarter has largely resumed. Assuming crude oil prices average $40 per barrel WTI, NGL prices average $0.40 per gallon, and Henry Hub and Waha natural gas prices average $2.00 and $1.50 per million British Thermal unit, respectively and the Company’s current best estimates for a range of volume outcomes through the second half of 2020, Targa is increasing the low end of its previously provided 2020 Adjusted EBITDA outlook and now estimates full year Adjusted EBITDA to be between $1.5 billion to $1.625 billion.
Second Quarter 2020 - Capitalization and Liquidity
The Company’s total consolidated debt as of June 30, 2020 was $7,841.5 million including $435.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility. The consolidated debt included $7,406.5 million of Targa Resources Partners LP’s (“TRP” or the “Partnership”) debt, net of $43.7 million of debt issuance costs, with $440.0 million outstanding under TRP’s $2.2 billion senior secured revolving credit facility, $250.0 million outstanding under TRP’s accounts receivable securitization facility, $6,725.1 million of outstanding TRP senior notes, net of unamortized premiums, and $35.1 million of finance lease liabilities.
Total consolidated liquidity of the Company as of June 30, 2020, including $196.2 million of cash, was over $2.1 billion. As of June 30, 2020, TRC had available borrowing capacity under its senior secured revolving credit facility of $235.0 million. TRP had $440.0 million of borrowings and $56.8 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 $1,703.2 million.
Growth Projects Update
Since the beginning of 2020, the Company has completed the vast majority of its major growth capital projects underway either on- or under-budget. Targa commenced operations on its 110 thousand barrel per day (“Mbbl/d”) Train 7 fractionator in Mont Belvieu and its 250 million cubic feet per day (“MMcf/d”) Peregrine Plant in Permian Delaware, and has recently commenced operations on its phased expansion at its LPG export facility at Galena Park and its 250 MMcf/d Gateway Plant in Permian Midland. The Company remains on-track to complete its 110 Mbbl/d Train 8 fractionator in Mont Belvieu during the third quarter of 2020 and its Grand Prix NGL Pipeline (“Grand Prix”) extension into Central Oklahoma during the first quarter of 2021.
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 August 6, 2020 to discuss its second quarter 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/mmc/p/45feoqa5. 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 June 30, 3030, |
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Six Months Ended June 30, |
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2020 |
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2019 |
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2020 vs. 2019 |
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2020 |
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2019 |
|
|
2020 vs. 2019 |
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|
(In millions) |
| Revenues: |
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|
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|
| Sales of commodities |
$ |
1,280.6 |
|
|
$ |
1,684.2 |
|
|
$ |
(403.6 |
) |
|
|
(24 |
%) |
|
$ |
3,060.2 |
|
|
$ |
3,660.7 |
|
|
$ |
(600.5 |
) |
|
|
(16 |
%) |
| Fees from midstream services |
|
242.9 |
|
|
|
311.1 |
|
|
|
(68.2 |
) |
|
|
(22 |
%) |
|
|
512.2 |
|
|
|
634.0 |
|
|
|
(121.8 |
) |
|
|
(19 |
%) |
| Total revenues |
|
1,523.5 |
|
|
|
1,995.3 |
|
|
|
(471.8 |
) |
|
|
(24 |
%) |
|
|
3,572.4 |
|
|
|
4,294.7 |
|
|
|
(722.3 |
) |
|
|
(17 |
%) |
| Product purchases |
|
860.6 |
|
|
|
1,361.6 |
|
|
|
(501.0 |
) |
|
|
(37 |
%) |
|
|
2,043.6 |
|
|
|
3,087.6 |
|
|
|
(1,044.0 |
) |
|
|
(34 |
%) |
| Gross margin (1) |
|
662.9 |
|
|
|
633.7 |
|
|
|
29.2 |
|
|
|
5 |
% |
|
|
1,528.8 |
|
|
|
1,207.1 |
|
|
|
321.7 |
|
|
|
27 |
% |
| Operating expenses |
|
183.4 |
|
|
|
210.2 |
|
|
|
(26.8 |
) |
|
|
(13 |
%) |
|
|
383.3 |
|
|
|
400.5 |
|
|
|
(17.2 |
) |
|
|
(4 |
%) |
| Operating margin (1) |
|
479.5 |
|
|
|
423.5 |
|
|
|
56.0 |
|
|
|
13 |
% |
|
|
1,145.5 |
|
|
|
806.6 |
|
|
|
338.9 |
|
|
|
42 |
% |
| Depreciation and amortization expense |
|
204.5 |
|
|
|
237.2 |
|
|
|
(32.7 |
) |
|
|
(14 |
%) |
|
|
443.6 |
|
|
|
474.6 |
|
|
|
(31.0 |
) |
|
|
(7 |
%) |
| General and administrative expense |
|
61.5 |
|
|
|
72.8 |
|
|
|
(11.3 |
) |
|
|
(16 |
%) |
|
|
121.9 |
|
|
|
153.6 |
|
|
|
(31.7 |
) |
|
|
(21 |
%) |
| Impairment of long-lived assets |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2,442.8 |
|
|
|
— |
|
|
|
2,442.8 |
|
|
|
— |
|
| Other operating (income) expense |
|
0.4 |
|
|
|
(0.2 |
) |
|
|
0.6 |
|
|
NM |
|
|
|
1.6 |
|
|
|
3.3 |
|
|
|
(1.7 |
) |
|
|
(52 |
%) |
| Income (loss) from operations |
|
213.1 |
|
|
|
113.7 |
|
|
|
99.4 |
|
|
|
87 |
% |
|
|
(1,864.4 |
) |
|
|
175.1 |
|
|
|
(2,039.5 |
) |
|
NM |
|
| Interest expense, net |
|
(96.7 |
) |
|
|
(72.1 |
) |
|
|
(24.6 |
) |
|
|
(34 |
%) |
|
|
(194.7 |
) |
|
|
(152.7 |
) |
|
|
(42.0 |
) |
|
|
(28 |
%) |
| Equity earnings (loss) |
|
14.9 |
|
|
|
3.2 |
|
|
|
11.7 |
|
|
NM |
|
|
|
35.5 |
|
|
|
5.9 |
|
|
|
29.6 |
|
|
NM |
|
| Gain (loss) from financing activities |
|
21.8 |
|
|
|
— |
|
|
|
21.8 |
|
|
|
— |
|
|
|
61.1 |
|
|
|
(1.4 |
) |
|
|
62.5 |
|
|
NM |
|
| Change in contingent considerations |
|
— |
|
|
|
0.8 |
|
|
|
(0.8 |
) |
|
|
(100 |
%) |
|
|
— |
|
|
|
(8.9 |
) |
|
|
8.9 |
|
|
|
100 |
% |
| Other, net |
|
0.8 |
|
|
|
— |
|
|
|
0.8 |
|
|
|
— |
|
|
|
0.8 |
|
|
|
— |
|
|
|
0.8 |
|
|
|
— |
|
| Income tax (expense) benefit |
|
23.2 |
|
|
|
3.3 |
|
|
|
19.9 |
|
|
NM |
|
|
|
318.5 |
|
|
|
6.2 |
|
|
|
312.3 |
|
|
NM |
|
| Net income (loss) |
|
177.1 |
|
|
|
48.9 |
|
|
|
128.2 |
|
|
|
262 |
% |
|
|
(1,643.2 |
) |
|
|
24.2 |
|
|
|
(1,667.4 |
) |
|
NM |
|
| Less: Net income (loss) attributable to noncontrolling interests |
|
96.1 |
|
|
|
59.1 |
|
|
|
37.0 |
|
|
|
63 |
% |
|
|
13.6 |
|
|
|
73.3 |
|
|
|
(59.7 |
) |
|
|
(81 |
%) |
| Net income (loss) attributable to Targa Resources Corp. |
|
81.0 |
|
|
|
(10.2 |
) |
|
|
91.2 |
|
|
NM |
|
|
|
(1,656.8 |
) |
|
|
(49.1 |
) |
|
|
(1,607.7 |
) |
|
NM |
|
| Dividends on Series A Preferred Stock |
|
22.9 |
|
|
|
22.9 |
|
|
|
— |
|
|
|
— |
|
|
|
45.8 |
|
|
|
45.8 |
|
|
|
— |
|
|
|
— |
|
| Deemed dividends on Series A Preferred Stock |
|
9.2 |
|
|
|
8.1 |
|
|
|
1.1 |
|
|
|
14 |
% |
|
|
18.2 |
|
|
|
16.0 |
|
|
|
2.2 |
|
|
|
14 |
% |
| Net income (loss) attributable to common shareholders |
$ |
48.9 |
|
|
$ |
(41.2 |
) |
|
$ |
90.1 |
|
|
|
219 |
% |
|
$ |
(1,720.8 |
) |
|
$ |
(110.9 |
) |
|
$ |
(1,609.9 |
) |
|
NM |
|
| Financial data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted EBITDA (1) |
$ |
351.2 |
|
|
$ |
306.5 |
|
|
$ |
44.7 |
|
|
|
15 |
% |
|
$ |
779.3 |
|
|
$ |
620.6 |
|
|
$ |
158.7 |
|
|
|
26 |
% |
| Distributable cash flow (1) |
|
273.7 |
|
|
|
192.0 |
|
|
|
81.7 |
|
|
|
43 |
% |
|
|
575.5 |
|
|
|
388.8 |
|
|
|
186.7 |
|
|
|
48 |
% |
| Growth capital expenditures (2) |
|
142.8 |
|
|
|
821.4 |
|
|
|
(678.6 |
) |
|
|
(83 |
%) |
|
|
420.1 |
|
|
|
1,691.5 |
|
|
|
(1,271.4 |
) |
|
|
(75 |
%) |
| Maintenance capital expenditures (3) |
|
26.8 |
|
|
|
35.5 |
|
|
|
(8.7 |
) |
|
|
(25 |
%) |
|
|
53.7 |
|
|
|
71.1 |
|
|
|
(17.4 |
) |
|
|
(24 |
%) |
(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 $404.2 million and $1,440.5 million for the six months ended June 30, 2020 and 2019. Net contributions to investments in unconsolidated affiliates were $0.3 million and $57.3 million for the six months ended June 30, 2020 and 2019.
(3) Maintenance capital expenditures, net of contributions from noncontrolling interests, were $51.4 million and $67.2 million for the six months ended June 30, 2020 and 2019.
NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019
The decrease in commodity sales reflects lower natural gas liquid (“NGL”), condensate, and petroleum products prices ($476.2 million) and lower crude marketing, petroleum products, and natural gas volumes ($150.3 million), partially offset by higher NGL and condensate volumes ($137.9 million), higher natural gas prices ($59.5 million) and the favorable impact of hedges ($26.1 million).
The decrease in fees from midstream services is primarily due to new transportation arrangements for Badlands 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 volumes.
The decrease in product purchases reflects decreased NGL, condensate and petroleum products prices, partially offset by increases in volumes.
Higher operating margin and gross margin in 2020 reflect increased segment results for 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 the first quarter of 2020 and the sale of the Delaware crude gathering system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including Train 7 and the additional processing plants and associated infrastructure in the Permian Basin.
General and administrative expense decreased due to cost reduction measures resulting in lower non-labor expenses and reduced compensation and benefits.
Interest expense, net, increased due to higher average borrowings and lower capitalized interest resulting from lower growth capital investments.
The increase in equity earnings is primarily due to higher earnings from the Company's investments in Gulf Coast Express Pipeline LLC (“GCX”) and Little Missouri 4 LLC (“Little Missouri 4”), partially offset by lower earnings from Gulf Coast Fractionators LP (“GCF”).
During the three months ended June 30, 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, paying $117.7 million plus accrued interest to repurchase $140.6 million of the notes, resulting in a $21.8 million net gain from financing activities.
The increase in income tax benefit is primarily due to change in the valuation allowance.
Net income attributable to noncontrolling interests was higher in 2020 primarily due to income allocated to noncontrolling interest holders in Targa Badlands LLC (“Targa Badlands”), Targa GCX Pipeline LLC (“GCX DevCo JV”), and the Grand Prix Pipeline LLC (“Grand Prix Joint Venture”).
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019
The decrease in commodity sales reflects lower NGL, natural gas, condensate, and petroleum products prices ($1,243.0 million) and lower crude marketing volumes ($131.2 million), partially offset by higher NGL, natural gas, condensate, and petroleum products volumes ($596.5 million) and the favorable impact of hedges ($174.1 million).
The decrease in fees from midstream services is primarily due to new transportation arrangements for Badlands volumes during the six months ended June 30, 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 volumes.
The decrease in product purchases reflects decreased NGL, natural gas, petroleum products and condensate prices, partially offset by increases in volumes.
Higher operating margin and gross margin in 2020 reflect increased segment results for 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 the first quarter of 2020 and the sale of the Delaware crude gathering system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including Train 7 and the additional processing plants and associated infrastructure in the Permian Basin.
General and administrative expense decreased due to cost reduction measures resulting in reduced compensation and benefits and lower non-labor expenses.
The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems in the first quarter of 2020 associated with the Company's Mid-Continent operations and full impairment of the Company’s Coastal operations - all of which are in the Company’s Gathering and Processing segment. Based on then-current market conditions, the Company’s first quarter impairment assessment projected further decline in natural gas production across the Mid-Continent and Gulf of Mexico. The Company did not recognize any impairments of long-lived assets during the first quarter of 2019. The Company may identify additional triggering events in the future, which will require additional evaluations of the recoverability of the carrying value of the Company’s long-lived assets and may result in future impairments.
Interest expense, net, increased due to higher average borrowings and lower capitalized interest resulting from lower growth capital investments.
The increase in equity earnings is primarily due to higher earnings from the Company’s investments in GCX and Little Missouri 4, partially offset by lower earnings from GCF.
During the six months ended June 30, 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, paying $239.8 million plus accrued interest to repurchase $303.3 million of the notes, resulting in a $61.1 million net gain from financing activities.
The increase in income tax benefit is primarily due to a higher pre-tax book loss and an additional benefit of net operating loss carryback from the CARES Act.
Net income attributable to noncontrolling interests was lower in 2020 primarily due to impairment losses allocated to noncontrolling interest holders, partially offset by income allocated to noncontrolling interest holders in Targa Badlands, GCX DevCo JV, the Grand Prix Joint Venture and Train 6.
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 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, 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 June 30, |
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
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|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
(In millions, except operating statistics and price amounts) |
|
| Gross margin |
$ |
|
338.3 |
|
|
$ |
|
363.8 |
|
|
$ |
|
(25.5 |
) |
|
|
(7 |
%) |
|
$ |
|
708.7 |
|
|
$ |
|
725.1 |
|
|
$ |
|
(16.4 |
) |
|
|
(2 |
%) |
| Operating expenses |
|
|
101.1 |
|
|
|
|
131.7 |
|
|
|
|
(30.6 |
) |
|
|
(23 |
%) |
|
|
|
215.9 |
|
|
|
|
254.8 |
|
|
|
|
(38.9 |
) |
|
|
(15 |
%) |
| Operating margin |
$ |
|
237.2 |
|
|
$ |
|
232.1 |
|
|
$ |
|
5.1 |
|
|
|
2 |
% |
|
$ |
|
492.8 |
|
|
$ |
|
470.3 |
|
|
$ |
|
22.5 |
|
|
|
5 |
% |
| Operating statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Plant natural gas inlet, MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Permian Midland (4) |
|
|
1,698.9 |
|
|
|
|
1,425.3 |
|
|
|
|
273.6 |
|
|
|
19 |
% |
|
|
|
1,677.0 |
|
|
|
|
1,374.2 |
|
|
|
|
302.8 |
|
|
|
22 |
% |
| Permian Delaware |
|
|
651.6 |
|
|
|
|
545.1 |
|
|
|
|
106.5 |
|
|
|
20 |
% |
|
|
|
689.3 |
|
|
|
|
513.0 |
|
|
|
|
176.3 |
|
|
|
34 |
% |
| Total Permian |
|
|
2,350.5 |
|
|
|
|
1,970.4 |
|
|
|
|
380.1 |
|
|
|
|
|
|
|
|
2,366.3 |
|
|
|
|
1,887.2 |
|
|
|
|
479.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SouthTX (5) |
|
|
265.1 |
|
|
|
|
313.8 |
|
|
|
|
(48.7 |
) |
|
|
(16 |
%) |
|
|
|
275.7 |
|
|
|
|
338.7 |
|
|
|
|
(63.0 |
) |
|
|
(19 |
%) |
| North Texas |
|
|
197.8 |
|
|
|
|
224.0 |
|
|
|
|
(26.2 |
) |
|
|
(12 |
%) |
|
|
|
210.6 |
|
|
|
|
227.2 |
|
|
|
|
(16.6 |
) |
|
|
(7 |
%) |
| SouthOK (6) |
|
|
439.8 |
|
|
|
|
607.7 |
|
|
|
|
(167.9 |
) |
|
|
(28 |
%) |
|
|
|
501.9 |
|
|
|
|
613.8 |
|
|
|
|
(111.9 |
) |
|
|
(18 |
%) |
| WestOK |
|
|
251.2 |
|
|
|
|
338.2 |
|
|
|
|
(87.0 |
) |
|
|
(26 |
%) |
|
|
|
271.4 |
|
|
|
|
338.2 |
|
|
|
|
(66.8 |
) |
|
|
(20 |
%) |
| Total Central |
|
|
1,153.9 |
|
|
|
|
1,483.7 |
|
|
|
|
(329.8 |
) |
|
|
|
|
|
|
|
1,259.6 |
|
|
|
|
1,517.9 |
|
|
|
|
(258.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Badlands (7),(8) |
|
|
111.6 |
|
|
|
|
92.3 |
|
|
|
|
19.3 |
|
|
|
21 |
% |
|
|
|
135.6 |
|
|
|
|
94.6 |
|
|
|
|
41.0 |
|
|
|
43 |
% |
| Total Field |
|
|
3,616.0 |
|
|
|
|
3,546.4 |
|
|
|
|
69.6 |
|
|
|
|
|
|
|
|
3,761.5 |
|
|
|
|
3,499.7 |
|
|
|
|
261.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Coastal |
|
|
713.0 |
|
|
|
|
804.9 |
|
|
|
|
(91.9 |
) |
|
|
(11 |
%) |
|
|
|
748.8 |
|
|
|
|
787.5 |
|
|
|
|
(38.7 |
) |
|
|
(5 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
4,329.0 |
|
|
|
|
4,351.3 |
|
|
|
|
(22.3 |
) |
|
|
(1 |
%) |
|
|
|
4,510.3 |
|
|
|
|
4,287.2 |
|
|
|
|
223.1 |
|
|
|
5 |
% |
| NGL production, MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Permian Midland (4) |
|
|
245.0 |
|
|
|
|
198.0 |
|
|
|
|
47.0 |
|
|
|
24 |
% |
|
|
|
245.0 |
|
|
|
|
191.3 |
|
|
|
|
53.7 |
|
|
|
28 |
% |
| Permian Delaware |
|
|
89.6 |
|
|
|
|
71.4 |
|
|
|
|
18.2 |
|
|
|
25 |
% |
|
|
|
93.0 |
|
|
|
|
65.9 |
|
|
|
|
27.1 |
|
|
|
41 |
% |
| Total Permian |
|
|
334.6 |
|
|
|
|
269.4 |
|
|
|
|
65.2 |
|
|
|
|
|
|
|
|
338.0 |
|
|
|
|
257.2 |
|
|
|
|
80.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SouthTX (5) |
|
|
28.8 |
|
|
|
|
41.7 |
|
|
|
|
(12.9 |
) |
|
|
(31 |
%) |
|
|
|
28.5 |
|
|
|
|
45.2 |
|
|
|
|
(16.7 |
) |
|
|
(37 |
%) |
| North Texas |
|
|
23.5 |
|
|
|
|
26.6 |
|
|
|
|
(3.1 |
) |
|
|
(12 |
%) |
|
|
|
24.9 |
|
|
|
|
26.7 |
|
|
|
|
(1.8 |
) |
|
|
(7 |
%) |
| SouthOK (6) |
|
|
51.3 |
|
|
|
|
68.3 |
|
|
|
|
(17.0 |
) |
|
|
(25 |
%) |
|
|
|
59.0 |
|
|
|
|
63.3 |
|
|
|
|
(4.3 |
) |
|
|
(7 |
%) |
| WestOK |
|
|
21.0 |
|
|
|
|
23.8 |
|
|
|
|
(2.8 |
) |
|
|
(12 |
%) |
|
|
|
22.1 |
|
|
|
|
24.0 |
|
|
|
|
(1.9 |
) |
|
|
(8 |
%) |
| Total Central |
|
|
124.6 |
|
|
|
|
160.4 |
|
|
|
|
(35.8 |
) |
|
|
|
|
|
|
|
134.5 |
|
|
|
|
159.2 |
|
|
|
|
(24.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Badlands (8) |
|
|
13.9 |
|
|
|
|
11.3 |
|
|
|
|
2.6 |
|
|
|
23 |
% |
|
|
|
16.0 |
|
|
|
|
11.3 |
|
|
|
|
4.7 |
|
|
|
42 |
% |
| Total Field |
|
|
473.1 |
|
|
|
|
441.1 |
|
|
|
|
32.0 |
|
|
|
|
|
|
|
|
488.5 |
|
|
|
|
427.7 |
|
|
|
|
60.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Coastal |
|
|
43.2 |
|
|
|
|
47.3 |
|
|
|
|
(4.1 |
) |
|
|
(9 |
%) |
|
|
|
46.0 |
|
|
|
|
47.8 |
|
|
|
|
(1.8 |
) |
|
|
(4 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
516.3 |
|
|
|
|
488.4 |
|
|
|
|
27.9 |
|
|
|
6 |
% |
|
|
|
534.5 |
|
|
|
|
475.5 |
|
|
|
|
59.0 |
|
|
|
12 |
% |
| Crude oil gathered, Badlands, MBbl/d |
|
|
157.9 |
|
|
|
|
167.3 |
|
|
|
|
(9.4 |
) |
|
|
(6 |
%) |
|
|
|
167.5 |
|
|
|
|
168.4 |
|
|
|
|
(0.9 |
) |
|
|
(1 |
%) |
| Crude oil gathered, Permian, MBbl/d (9) |
|
|
40.2 |
|
|
|
|
86.3 |
|
|
|
|
(46.1 |
) |
|
|
(53 |
%) |
|
|
|
45.6 |
|
|
|
|
81.4 |
|
|
|
|
(35.8 |
) |
|
|
(44 |
%) |
| Natural gas sales, BBtu/d (3),(10) |
|
|
2,048.9 |
|
|
|
|
2,049.7 |
|
|
|
|
(0.8 |
) |
|
|
(0 |
%) |
|
|
|
2,103.0 |
|
|
|
|
1,988.1 |
|
|
|
|
114.9 |
|
|
|
6 |
% |
| NGL sales, MBbl/d (3),(10) |
|
|
395.0 |
|
|
|
|
389.3 |
|
|
|
|
5.7 |
|
|
|
1 |
% |
|
|
|
414.3 |
|
|
|
|
374.5 |
|
|
|
|
39.8 |
|
|
|
11 |
% |
| Condensate sales, MBbl/d |
|
|
16.1 |
|
|
|
|
13.2 |
|
|
|
|
2.9 |
|
|
|
22 |
% |
|
|
|
17.3 |
|
|
|
|
12.8 |
|
|
|
|
4.5 |
|
|
|
35 |
% |
| Average realized prices - inclusive of hedges (11): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas, $/MMBtu |
|
|
1.03 |
|
|
|
|
0.90 |
|
|
|
|
0.13 |
|
|
|
14 |
% |
|
|
|
0.98 |
|
|
|
|
1.40 |
|
|
|
|
(0.42 |
) |
|
|
(30 |
%) |
| NGL, $/gal |
|
|
0.19 |
|
|
|
|
0.34 |
|
|
|
|
(0.15 |
) |
|
|
(44 |
%) |
|
|
|
0.21 |
|
|
|
|
0.39 |
|
|
|
|
(0.18 |
) |
|
|
(46 |
%) |
| Condensate, $/Bbl |
|
|
28.13 |
|
|
|
|
49.82 |
|
|
|
|
(21.69 |
) |
|
|
(44 |
%) |
|
|
|
36.61 |
|
|
|
|
48.49 |
|
|
|
|
(11.88 |
) |
|
|
(24 |
%) |
(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. 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 the Company. 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 and includes the Targa-gathered volumes processed at the Little Missouri 4 Plant.
(8) As of April 3, 2019, Targa owns 55% of Targa Badlands, prior to which the Company owned a 100% interest. Targa Badlands is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(9) Permian crude oil gathered volumes reflect the sale of the Delaware crude gathering system, which was effective December 1, 2019.
(10) Natural gas and NGL sales statistics include Badlands starting January 1, 2020. New transportation arrangements for Badlands volumes 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 volumes 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 June 30, 2020 |
|
|
Three Months Ended June 30, 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) |
|
|
17.3 |
|
|
$ |
0.53 |
|
|
$ |
9.2 |
|
|
|
16.1 |
|
|
$ |
1.97 |
|
|
$ |
31.8 |
|
| NGL (MMgal) |
|
|
100.2 |
|
|
|
0.22 |
|
|
|
21.7 |
|
|
|
72.7 |
|
|
|
0.12 |
|
|
|
8.9 |
|
| Crude oil (MBbl) |
|
|
0.5 |
|
|
|
29.85 |
|
|
|
14.1 |
|
|
|
0.4 |
|
|
|
(4.98 |
) |
|
|
(1.8 |
) |
|
|
|
|
|
|
|
|
|
|
$ |
45.0 |
|
|
|
|
|
|
|
|
|
|
$ |
38.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2020 |
|
|
Six Months Ended June 30, 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) |
|
|
33.1 |
|
|
$ |
0.73 |
|
|
$ |
24.1 |
|
|
|
28.2 |
|
|
$ |
1.43 |
|
|
$ |
40.4 |
|
| NGL (MMgal) |
|
|
195.7 |
|
|
|
0.20 |
|
|
|
39.2 |
|
|
|
142.1 |
|
|
|
0.07 |
|
|
|
9.4 |
|
| Crude oil (MBbl) |
|
|
0.9 |
|
|
|
21.24 |
|
|
|
19.7 |
|
|
|
0.7 |
|
|
|
(2.58 |
) |
|
|
(1.8 |
) |
|
|
|
|
|
|
|
|
|
|
$ |
83.0 |
|
|
|
|
|
|
|
|
|
|
$ |
48.0 |
|
(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 June 30, 2020 Compared to Three Months Ended June 30, 2019
The decrease in gross margin was primarily due to lower volumes in the Central region, attributable to temporary shut-ins and reduced producer activity, and lower realized NGL and condensate prices, partially offset by higher volumes and fee-based margin in the Permian. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Pembrook and Falcon plants in 2019 and the Peregrine plant in the second quarter of 2020. These increases were partially offset by the impact of temporary shut-ins and reduced producer activity. In the Badlands, natural gas gathered 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, partially offset by the impact of temporary shut-ins and reduced producer activity. Total crude oil gathered volumes decreased in the Badlands due to temporary shut-ins and reduced producer activity, while the decrease in the Permian was primarily due to the sale of the Delaware crude gathering system in the fourth quarter of 2019.
Despite the addition of new processing facilities in the Permian, operating expenses were lower due to cost reduction measures that resulted in a decrease in expenses from contract labor, chemicals, taxes and supplies.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019
The decrease in gross margin was primarily due to lower volumes in the Central region attributable to temporary shut-ins and reduced producer activity, and lower realized commodity prices, partially offset by higher volumes and fee-based margin in the Permian and Badlands. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Pembrook and Falcon plants in 2019 and the Peregrine plant in the second quarter of 2020. These increases were partially offset by the impact of temporary shut-ins and reduced producer activity. In the Badlands, natural gas gathered 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, partially offset by the impact of temporary shut-ins and reduced producer activity. Total crude oil gathered volumes were flat in the Badlands, while the decrease in the Permian was primarily due to the sale of the Delaware crude gathering system in the fourth quarter of 2019.
Despite the addition of new processing facilities in the Permian, operating expenses were lower due to cost reduction measures that resulted in a decrease in expenses from contract labor, taxes and chemicals, partially offset by increased compensation and related benefits.
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 LPG 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. 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 June 30, |
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
(In millions, except operating statistics and price amounts) |
|
| Gross margin |
|
$ |
|
314.7 |
|
|
$ |
|
262.5 |
|
|
$ |
|
52.2 |
|
|
|
20 |
% |
|
$ |
|
695.0 |
|
|
$ |
|
482.0 |
|
|
$ |
|
213.0 |
|
|
44 |
% |
| Operating expenses (1) |
|
|
|
83.2 |
|
|
|
|
78.1 |
|
|
|
|
5.1 |
|
|
|
7 |
% |
|
|
|
169.5 |
|
|
|
|
145.7 |
|
|
|
|
23.8 |
|
|
16 |
% |
| Operating margin |
|
$ |
|
231.5 |
|
|
$ |
|
184.4 |
|
|
$ |
|
47.1 |
|
|
|
26 |
% |
|
$ |
|
525.5 |
|
|
$ |
|
336.3 |
|
|
$ |
|
189.2 |
|
|
56 |
% |
| Operating statistics MBbl/d (2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fractionation volumes (3) |
|
|
|
579.3 |
|
|
|
|
512.5 |
|
|
|
|
66.8 |
|
|
|
13 |
% |
|
|
|
602.3 |
|
|
|
|
484.7 |
|
|
|
|
117.6 |
|
|
24 |
% |
| Export volumes (4) |
|
|
|
253.8 |
|
|
|
|
231.5 |
|
|
|
|
22.3 |
|
|
|
10 |
% |
|
|
|
261.3 |
|
|
|
|
222.4 |
|
|
|
|
38.9 |
|
|
17 |
% |
| Pipeline throughput (5) |
|
|
|
256.1 |
|
|
|
|
— |
|
|
|
|
256.1 |
|
|
|
— |
|
|
|
|
258.9 |
|
|
|
|
— |
|
|
|
|
258.9 |
|
|
— |
|
| NGL sales |
|
|
|
692.6 |
|
|
|
|
605.2 |
|
|
|
|
87.4 |
|
|
|
14 |
% |
|
|
|
720.4 |
|
|
|
|
594.8 |
|
|
|
|
125.6 |
|
|
21 |
% |
(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 period and the denominator is the number of calendar days during the period.
(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.
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019
The increase in Logistics and Transportation segment gross margin was primarily due to higher NGL transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes, as a result of the commencement of operations of Train 7 in the first quarter of 2020 and operations of Train 6 for a portion of the second quarter of 2019. LPG export margin increased primarily due to higher volumes, driven in part by phased expansions of the Company’s LPG export capabilities. Marketing margin decreased due to less optimization margin realized in its marketing businesses.
Operating expenses were higher due to the addition of incremental fractionation capacity, higher taxes primarily attributable to Train 7, and higher compensation and benefits, partially offset by lower fuel and power costs and cost reduction measures.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019
The increase in Logistics and Transportation segment gross margin was primarily due to higher NGL transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes, as a result of the commencement of operations of Train 7 in the first quarter of 2020 and operations of Train 6 for a portion of the second quarter of 2019. LPG export margin increased primarily due to higher volumes driven in part by phased expansions of the Company’s LPG export capabilities, partially offset by lower fees. Marketing margin decreased primarily due to less optimization margin realized in its marketing businesses.
Operating expenses were higher due to the addition of incremental fractionation capacity, higher taxes primarily attributable to Grand Prix and to Train 7, higher compensation and benefits and higher maintenance, partially offset by lower fuel and power costs and cost reduction measures.
Other
|
|
Three Months Ended June 30, |
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
|
(In millions) |
|
|
(In millions) |
|
| Gross margin |
|
$ |
10.8 |
|
|
$ |
7.0 |
|
|
$ |
3.8 |
|
|
$ |
127.2 |
|
|
$ |
— |
|
|
$ |
127.2 |
|
| Operating margin |
|
$ |
10.8 |
|
|
$ |
7.0 |
|
|
$ |
3.8 |
|
|
$ |
127.2 |
|
|
$ |
— |
|
|
$ |
127.2 |
|
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 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.
The Company utilizes non-GAAP measures to analyze the Company’s performance. Gross margin, operating margin, Adjusted EBITDA and distributable 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
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 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
The Company defines distributable cash flow 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). Distributable cash flow is a performance measure 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 paying preferred distributions, servicing the Company’s debt and funding maintenance capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or funding growth capital expenditures.
The following table presents a reconciliation of net income attributable to TRC to Adjusted EBITDA and Distributable Cash Flow for the periods indicated:
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
|
|
(In millions) |
|
| Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA and Distributable Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net income (loss) attributable to TRC |
|
$ |
|
81.0 |
|
|
$ |
|
(10.2 |
) |
|
$ |
|
(1,656.8 |
) |
|
$ |
|
(49.1 |
) |
| Income attributable to TRP preferred limited partners |
|
|
|
2.8 |
|
|
|
|
2.8 |
|
|
|
|
5.6 |
|
|
|
|
5.6 |
|
| Interest (income) expense, net |
|
|
|
96.7 |
|
|
|
|
72.1 |
|
|
|
|
194.7 |
|
|
|
|
152.7 |
|
| Income tax expense (benefit) |
|
|
|
(23.2 |
) |
|
|
|
(3.3 |
) |
|
|
|
(318.5 |
) |
|
|
|
(6.2 |
) |
| Depreciation and amortization expense |
|
|
|
204.5 |
|
|
|
|
237.2 |
|
|
|
|
443.6 |
|
|
|
|
474.6 |
|
| Impairment of long-lived assets |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
2,442.8 |
|
|
|
|
— |
|
| (Gain) loss on sale or disposition of assets |
|
|
|
(0.7 |
) |
|
|
|
(0.2 |
) |
|
|
|
— |
|
|
|
|
3.1 |
|
| (Gain) loss from financing activities (1) |
|
|
|
(21.8 |
) |
|
|
|
— |
|
|
|
|
(61.1 |
) |
|
|
|
1.4 |
|
| Equity (earnings) loss |
|
|
|
(14.9 |
) |
|
|
|
(3.2 |
) |
|
|
|
(35.5 |
) |
|
|
|
(5.9 |
) |
| Distributions from unconsolidated affiliates and preferred partner interests, net |
|
|
|
27.7 |
|
|
|
|
12.6 |
|
|
|
|
53.4 |
|
|
|
|
19.4 |
|
| Change in contingent considerations |
|
|
|
— |
|
|
|
|
(0.8 |
) |
|
|
|
— |
|
|
|
|
8.9 |
|
| Compensation on equity grants |
|
|
|
16.1 |
|
|
|
|
16.2 |
|
|
|
|
33.1 |
|
|
|
|
32.7 |
|
| Risk management activities |
|
|
|
(10.4 |
) |
|
|
|
(7.1 |
) |
|
|
|
(125.9 |
) |
|
|
|
0.1 |
|
| Severance and related benefits (2) |
|
|
|
6.5 |
|
|
|
|
— |
|
|
|
|
6.5 |
|
|
|
|
— |
|
| Noncontrolling interests adjustments (3) |
|
|
|
(13.1 |
) |
|
|
|
(9.6 |
) |
|
|
|
(202.6 |
) |
|
|
|
(16.7 |
) |
| TRC Adjusted EBITDA |
|
$ |
|
351.2 |
|
|
$ |
|
306.5 |
|
|
$ |
|
779.3 |
|
|
$ |
|
620.6 |
|
| Distributions to TRP preferred limited partners |
|
|
|
(2.8 |
) |
|
|
|
(2.8 |
) |
|
|
|
(5.6 |
) |
|
|
|
(5.6 |
) |
| Interest expense on debt obligations (4) |
|
|
|
(94.1 |
) |
|
|
|
(78.9 |
) |
|
|
|
(191.2 |
) |
|
|
|
(159.0 |
) |
| Cash tax refund |
|
|
|
44.4 |
|
|
|
|
— |
|
|
|
|
44.4 |
|
|
|
|
— |
|
| Maintenance capital expenditures |
|
|
|
(26.8 |
) |
|
|
|
(35.5 |
) |
|
|
|
(53.7 |
) |
|
|
|
(71.1 |
) |
| Noncontrolling interests adjustments of maintenance capital expenditures |
|
|
|
1.8 |
|
|
|
|
2.7 |
|
|
|
|
2.3 |
|
|
|
|
3.9 |
|
| Distributable Cash Flow |
|
$ |
|
273.7 |
|
|
$ |
|
192.0 |
|
|
$ |
|
575.5 |
|
|
$ |
|
388.8 |
|
_____________________
(1) Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments.
(2) Represents one-time severance and related benefit expenses 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.
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:
- 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, other 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
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.
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 June 30, |
|
|
Six Months Ended June 30, |
|
|
|
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 |
|
$ |
|
81.0 |
|
|
$ |
|
(10.2 |
) |
|
$ |
|
(1,656.8 |
) |
|
$ |
|
(49.1 |
) |
| Net income (loss) attributable to noncontrolling interests |
|
|
|
96.1 |
|
|
|
|
59.1 |
|
|
|
|
13.6 |
|
|
|
|
73.3 |
|
| Net income (loss) |
|
|
|
177.1 |
|
|
|
|
48.9 |
|
|
|
|
(1,643.2 |
) |
|
|
|
24.2 |
|
| Depreciation and amortization expense |
|
|
|
204.5 |
|
|
|
|
237.2 |
|
|
|
|
443.6 |
|
|
|
|
474.6 |
|
| General and administrative expense |
|
|
|
61.5 |
|
|
|
|
72.8 |
|
|
|
|
121.9 |
|
|
|
|
153.6 |
|
| Impairment of long-lived assets |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
2,442.8 |
|
|
|
|
— |
|
| Interest (income) expense, net |
|
|
|
96.7 |
|
|
|
|
72.1 |
|
|
|
|
194.7 |
|
|
|
|
152.7 |
|
| Equity (earnings) loss |
|
|
|
(14.9 |
) |
|
|
|
(3.2 |
) |
|
|
|
(35.5 |
) |
|
|
|
(5.9 |
) |
| Income tax expense (benefit) |
|
|
|
(23.2 |
) |
|
|
|
(3.3 |
) |
|
|
|
(318.5 |
) |
|
|
|
(6.2 |
) |
| (Gain) loss on sale or disposition of assets |
|
|
|
(0.7 |
) |
|
|
|
(0.2 |
) |
|
|
|
— |
|
|
|
|
3.1 |
|
| (Gain) loss from financing activities |
|
|
|
(21.8 |
) |
|
|
|
— |
|
|
|
|
(61.1 |
) |
|
|
|
1.4 |
|
| Change in contingent considerations |
|
|
|
— |
|
|
|
|
(0.8 |
) |
|
|
|
— |
|
|
|
|
8.9 |
|
| Other, net |
|
|
|
0.3 |
|
|
|
|
— |
|
|
|
|
0.8 |
|
|
|
|
0.2 |
|
| Operating margin |
|
|
|
479.5 |
|
|
|
|
423.5 |
|
|
|
|
1,145.5 |
|
|
|
|
806.6 |
|
| Operating expenses |
|
|
|
183.4 |
|
|
|
|
210.2 |
|
|
|
|
383.3 |
|
|
|
|
400.5 |
|
| Gross margin |
|
$ |
|
662.9 |
|
|
$ |
|
633.7 |
|
|
$ |
|
1,528.8 |
|
|
$ |
|
1,207.1 |
|
The following table presents a reconciliation of estimated net income of the Company to estimated Adjusted EBITDA for 2020:
|
|
|
2020E |
|
|
|
(In millions) |
|
Reconciliation of Estimated Net Loss attributable to TRC to
Estimated Adjusted EBITDA |
|
|
|
|
|
| Net loss attributable to TRC |
|
$ |
|
(1,627.5 |
) |
|
| Impairment of long-lived assets |
|
|
|
2,443.0 |
|
|
| Income attributable to TRP preferred limited partners |
|
|
|
11.0 |
|
|
| Interest expense, net |
|
|
|
380.0 |
|
|
| Income tax expense (benefit) |
|
|
(260.0 |
) |
|
| Depreciation and amortization expense |
|
|
|
830.0 |
|
|
| Equity (earnings) loss |
|
|
|
(70.0 |
) |
|
| Distributions from unconsolidated affiliates and preferred partner interests, net |
|
|
|
100.0 |
|
|
| Compensation on equity grants |
|
|
|
70.0 |
|
|
| Risk management activities and other |
|
|
|
(120.0 |
) |
|
| Severance and related benefits (1) |
|
|
|
6.5 |
|
|
| Noncontrolling interests adjustments (2) |
|
|
|
(200.0 |
) |
|
| TRC Estimated Adjusted EBITDA |
|
$ |
|
1,563.0 |
|
|
(1) Represents one-time severance and related benefit expenses related to the Company’s cost reduction measures.
(2) Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests).
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 Annual Report on Form 10-K for the year ended December 31, 2019, 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
