HOUSTON, Nov. 05, 2020 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported third quarter 2020 results.
Third Quarter 2020 Financial Results
Third quarter 2020 net income (loss) attributable to Targa Resources Corp. was $69.3 million compared to a net loss of $(47.3) million for the third quarter of 2019.
The Company reported quarterly earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $419.1 million for the third quarter of 2020 compared to $349.6 million for the third 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, free 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 October 15, 2020, TRC declared a quarterly dividend of $0.10 per share of its common stock for the three months ended September 30, 2020, or $0.40 per share on an annualized basis. Total cash dividends of approximately $23.3 million will be paid on November 16, 2020 on all outstanding shares of common stock to holders of record as of the close of business on October 30, 2020. Also, on October 15, 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 November 13, 2020 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on October 30, 2020.
The Company reported distributable cash flow and free cash flow before dividends for the third quarter of 2020 of $294.7 million and $189.3 million.
Third Quarter 2020 - Sequential Quarter over Quarter Commentary
Targa reported third quarter 2020 Adjusted EBITDA of $419.1 million, representing a 19 percent increase over the second quarter. The sequential increase in Adjusted EBITDA was attributable to an improved commodity price environment and the resumption of production from temporary curtailments and producer activity, predominantly across Targa’s Permian gathering and processing systems, which drove increasing volumes through Targa’s Logistics and Transportation (“L&T”) systems. Targa also benefited from partial quarter contributions from new assets placed in-service during the quarter, including its 250 million cubic feet per day (“MMcf/d”) Gateway Plant in Permian Midland, the phased expansion of its liquefied petroleum gas (“LPG”) export facilities in Galena Park, and its 110 thousand barrel per day (“MBbl/d”) fractionation Train 8 in Mont Belvieu. In the Gathering and Processing (“G&P”) segment, the sequential increase in segment gross margin was predominantly attributable to higher Permian natural gas inlet volumes, which increased 9 percent in the third quarter over the second quarter, and higher Permian fee-based margin. In the L&T segment, the sequential increase in gross margin was primarily attributable to strong Grand Prix Pipeline (“Grand Prix”) transportation throughput and higher LPG export volumes, combined with higher fractionation volumes and higher marketing margin. Third quarter Grand Prix volumes increased 18 percent sequentially, while Targa’s LPG export volumes achieved a record 9.5 million barrels per month during the quarter, increasing 22 percent over the second quarter. Third quarter fractionation volumes were impacted by scheduled maintenance, which resulted in Targa building inventory, shifting the timing of incremental volumes to be fractionated to the fourth quarter. Operating expenses were flat sequentially, despite the addition of new assets beginning operations during the third quarter across both the G&P and L&T segments.
2020 Outlook
As previously disclosed, Targa estimates its full year 2020 Adjusted EBITDA to be at or around the high end of its previously provided outlook of $1.5 billion to $1.625 billion. Targa also estimates that its 2020 net growth capital spending to be around $700 million, and now estimates that its full year 2020 net maintenance capital to be approximately $110 million.
Third Quarter 2020 - Capitalization and Liquidity
The Company’s total consolidated debt as of September 30, 2020 was $7,914.1 million including $435.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility. The consolidated debt included $7,479.1 million of Targa Resources Partners LP’s (“TRP” or the “Partnership”) debt, net of $48.5 million of debt issuance costs, with $100.0 million outstanding under TRP’s $2.2 billion senior secured revolving credit facility, $250.0 million outstanding under TRP’s accounts receivable securitization facility, $7,145.0 million of outstanding TRP senior notes, net of unamortized premiums, and $32.6 million of finance lease liabilities.
Total consolidated liquidity of the Company as of September 30, 2020, including $275.0 million of cash, was approximately $2.6 billion. As of September 30, 2020, TRC had available borrowing capacity under its senior secured revolving credit facility of $235.0 million. TRP had $100.0 million of borrowings and $35.3 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 $2,064.7 million.
Growth Projects Update
Since the beginning of 2020, the Company has completed substantially all of its major growth capital projects underway either on- or under-budget. Targa has commenced operations on its:
- 110 MBbl/d Train 7 fractionator in Mont Belvieu,
- 250 MMcf/d Peregrine Plant in Permian Delaware,
- Phased expansion at its LPG export facility in Galena Park,
- 250 MMcf/d Gateway Plant in Permian Midland, and
- 110 MBbl/d Train 8 fractionator in Mont Belvieu.
Targa’s Grand Prix extension into Central Oklahoma is expected to be operational by the end of the fourth quarter of 2020. Targa announced today that it is relocating its existing 200 MMcf/d Longhorn cryogenic natural gas processing plant from North Texas to Permian Midland, where it will be renamed the Heim Plant, to accommodate anticipated production growth across its Permian Midland system. Relocating the plant will provide the Company with significant capital savings. The 200 MMcf/d Heim Plant is expected to begin operations in the fourth quarter of 2021, with a total estimated capital cost of approximately $90 million.
Financing and Asset Sales
In August 2020, the Partnership issued $1.0 billion aggregate principal amount of 4?% Senior Notes due 2031, resulting in net proceeds of approximately $991 million. A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer and redemption payments for the Partnership’s $580 million principal outstanding amount of 6¾% Senior Notes due 2024 (the “6¾% Notes”), with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facility. The Company accepted for purchase all the notes that were validly tendered as of the early tender date and redeemed the remaining aggregate principal amount of the 6¾% Notes.
On November 2, 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023.
Targa continues to evaluate and execute asset sales to reduce leverage and focus on its core operations. In October 2020, the Company closed on the sale of its assets in Channelview, Texas for approximately $58 million.
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 $500 million of its outstanding common stock. As of November 2, 2020, the Company has repurchased 4,505,507 shares at a weighted average price of $16.33 for a total net cost of approximately $74 million. There is approximately $426 million remaining under the authorized Share Repurchase Program.
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 November 5, 2020 to discuss its third quarter 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/w5f4facw . 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
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Three Months Ended
September 30, |
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Nine Months Ended
September 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 |
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2020 vs. 2019 |
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(In millions) |
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| Revenues: |
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| Sales of commodities |
$ |
1,840.8 |
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$ |
1,594.2 |
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|
$ |
246.6 |
|
|
|
15 |
% |
|
$ |
4,900.8 |
|
|
$ |
5,254.8 |
|
|
$ |
(354.0 |
) |
|
|
(7 |
%) |
| Fees from midstream services |
|
274.3 |
|
|
|
308.3 |
|
|
|
(34.0 |
) |
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(11 |
%) |
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|
786.7 |
|
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|
942.4 |
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|
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(155.7 |
) |
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(17 |
%) |
| Total revenues |
|
2,115.1 |
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|
|
1,902.5 |
|
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|
212.6 |
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|
11 |
% |
|
|
5,687.5 |
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|
|
6,197.2 |
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|
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(509.7 |
) |
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|
(8 |
%) |
| Product purchases |
|
1,303.2 |
|
|
|
1,328.1 |
|
|
|
(24.9 |
) |
|
|
(2 |
%) |
|
|
3,346.8 |
|
|
|
4,415.7 |
|
|
|
(1,068.9 |
) |
|
|
(24 |
%) |
| Gross margin (1) |
|
811.9 |
|
|
|
574.4 |
|
|
|
237.5 |
|
|
|
41 |
% |
|
|
2,340.7 |
|
|
|
1,781.5 |
|
|
|
559.2 |
|
|
|
31 |
% |
| Operating expenses |
|
181.9 |
|
|
|
200.2 |
|
|
|
(18.3 |
) |
|
|
(9 |
%) |
|
|
565.1 |
|
|
|
600.8 |
|
|
|
(35.7 |
) |
|
|
(6 |
%) |
| Operating margin (1) |
|
630.0 |
|
|
|
374.2 |
|
|
|
255.8 |
|
|
|
68 |
% |
|
|
1,775.6 |
|
|
|
1,180.7 |
|
|
|
594.9 |
|
|
|
50 |
% |
| Depreciation and amortization expense |
|
203.7 |
|
|
|
244.3 |
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|
|
(40.6 |
) |
|
|
(17 |
%) |
|
|
647.3 |
|
|
|
718.9 |
|
|
|
(71.6 |
) |
|
|
(10 |
%) |
| General and administrative expense |
|
58.6 |
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|
|
69.9 |
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|
|
(11.3 |
) |
|
|
(16 |
%) |
|
|
180.6 |
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|
|
223.5 |
|
|
|
(42.9 |
) |
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|
(19 |
%) |
| Impairment of long-lived assets |
|
— |
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|
|
— |
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|
|
— |
|
|
|
— |
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|
|
2,442.8 |
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|
|
— |
|
|
|
2,442.8 |
|
|
|
— |
|
| Other operating (income) expense |
|
72.2 |
|
|
|
18.4 |
|
|
|
53.8 |
|
|
|
292 |
% |
|
|
73.8 |
|
|
|
21.7 |
|
|
|
52.1 |
|
|
|
240 |
% |
| Income (loss) from operations |
|
295.5 |
|
|
|
41.6 |
|
|
|
253.9 |
|
|
NM |
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|
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(1,568.9 |
) |
|
|
216.6 |
|
|
|
(1,785.5 |
) |
|
NM |
|
| Interest expense, net |
|
(97.7 |
) |
|
|
(89.1 |
) |
|
|
(8.6 |
) |
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(10 |
%) |
|
|
(292.4 |
) |
|
|
(241.8 |
) |
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|
(50.6 |
) |
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|
(21 |
%) |
| Equity earnings (loss) |
|
18.6 |
|
|
|
10.0 |
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|
|
8.6 |
|
|
|
86 |
% |
|
|
54.1 |
|
|
|
15.9 |
|
|
|
38.2 |
|
|
|
240 |
% |
| Gain (loss) from financing activities |
|
(13.7 |
) |
|
|
— |
|
|
|
(13.7 |
) |
|
|
— |
|
|
|
47.4 |
|
|
|
(1.4 |
) |
|
|
48.8 |
|
|
NM |
|
| Gain (loss) from sale of equity-method investment |
|
— |
|
|
|
65.8 |
|
|
|
(65.8 |
) |
|
|
(100 |
%) |
|
|
— |
|
|
|
65.8 |
|
|
|
(65.8 |
) |
|
|
(100 |
%) |
| Change in contingent considerations |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(8.8 |
) |
|
|
8.8 |
|
|
|
100 |
% |
| Other, net |
|
1.4 |
|
|
|
— |
|
|
|
1.4 |
|
|
|
— |
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|
2.2 |
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— |
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|
2.2 |
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|
|
— |
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| Income tax (expense) benefit |
|
(31.9 |
) |
|
|
3.8 |
|
|
|
(35.7 |
) |
|
NM |
|
|
|
286.6 |
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|
|
10.0 |
|
|
|
276.6 |
|
|
NM |
|
| Net income (loss) |
|
172.2 |
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|
|
32.1 |
|
|
|
140.1 |
|
|
NM |
|
|
|
(1,471.0 |
) |
|
|
56.3 |
|
|
|
(1,527.3 |
) |
|
NM |
|
| Less: Net income (loss) attributable to noncontrolling interests |
|
102.9 |
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|
|
79.4 |
|
|
|
23.5 |
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|
|
30 |
% |
|
|
116.5 |
|
|
|
152.7 |
|
|
|
(36.2 |
) |
|
|
(24 |
%) |
| Net income (loss) attributable to Targa Resources Corp. |
|
69.3 |
|
|
|
(47.3 |
) |
|
|
116.6 |
|
|
|
247 |
% |
|
|
(1,587.5 |
) |
|
|
(96.4 |
) |
|
|
(1,491.1 |
) |
|
NM |
|
| Dividends on Series A Preferred Stock |
|
22.9 |
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|
22.9 |
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|
|
— |
|
|
|
— |
|
|
|
68.8 |
|
|
|
68.8 |
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|
|
— |
|
|
|
— |
|
| Deemed dividends on Series A Preferred Stock |
|
9.5 |
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|
|
8.4 |
|
|
|
1.1 |
|
|
|
13 |
% |
|
|
27.7 |
|
|
|
24.4 |
|
|
|
3.3 |
|
|
|
14 |
% |
| Net income (loss) attributable to common shareholders |
$ |
36.9 |
|
|
$ |
(78.6 |
) |
|
$ |
115.5 |
|
|
|
147 |
% |
|
$ |
(1,684.0 |
) |
|
$ |
(189.6 |
) |
|
$ |
(1,494.4 |
) |
|
NM |
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| Financial data: |
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| Adjusted EBITDA (1) |
$ |
419.1 |
|
|
$ |
349.6 |
|
|
$ |
69.5 |
|
|
|
20 |
% |
|
$ |
1,198.5 |
|
|
$ |
970.3 |
|
|
$ |
228.2 |
|
|
|
24 |
% |
| Distributable cash flow (1) |
|
294.7 |
|
|
|
229.9 |
|
|
|
64.8 |
|
|
|
28 |
% |
|
|
878.9 |
|
|
|
619.4 |
|
|
|
259.5 |
|
|
|
42 |
% |
| Free cash flow (1) |
|
189.3 |
|
|
|
(218.5 |
) |
|
|
407.8 |
|
|
NM |
|
|
|
360.4 |
|
|
|
(1,326.8 |
) |
|
|
1,687.2 |
|
|
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 September 30, 2020 Compared to Three Months Ended September 30, 2019
The increase in commodity sales reflects higher natural gas liquid (“NGL”) and natural gas prices ($133.5 million), higher NGL, condensate and petroleum products volumes ($100.7 million) and the favorable impact of hedges ($171.0 million), partially offset by lower crude marketing and natural gas volumes ($128.9 million) and lower condensate and petroleum product prices ($29.6 million).
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, and lower gas processing volumes, partially offset by increased export and terminaling and storage volumes.
The decrease in product purchases reflects lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, and lower natural gas volumes, partially offset by higher NGL and natural gas prices.
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 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 compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs.
Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of the Company's assets in Channelview, Texas in connection with the sale of such assets in October 2020 (the “October 2020 Sale”) and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the 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 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 third quarter of 2020, the Partnership redeemed the 6¾% Notes, resulting in a $13.7 million net loss from financing activities.
During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million.
The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a decrease in valuation allowance.
Net income attributable to noncontrolling interests was higher in 2020 primarily due to income allocated to noncontrolling interest holders in the Grand Prix Joint Venture, Targa GCX Pipeline LLC (“GCX DevCo JV”) and the Centrahoma Joint Venture.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
The decrease in commodity sales reflects lower NGL, condensate, natural gas and petroleum product prices ($1,112.5 million) and lower crude marketing volumes ($254.7 million), partially offset by higher NGL, condensate, natural gas and petroleum product volumes ($664.3 million), the favorable impact of hedges ($345.1 million) and higher crude marketing prices ($3.8 million).
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, and lower gas processing volumes, partially offset by increased export and terminaling and storage volumes.
The decrease in product purchases reflects lower NGL, condensate, natural gas and petroleum product prices, as well as lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, partially offset by higher NGL, condensate, natural gas and petroleum product 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 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 compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs.
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 nine months ended September 30, 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.
Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of the Company's assets in Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the 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, partially offset by lower earnings from GCF.
During the nine months ended September 30, 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024, paying $831.0 million plus accrued interest to repurchase $883.4 million of the notes, resulting in a $47.4 million net gain from financing activities.
During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million.
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.
Net income attributable to noncontrolling interests was lower in 2020 primarily due to the allocation of impairment losses recognized during the first quarter of 2020 to noncontrolling interest holders, partially offset by higher income allocated to noncontrolling interest holders in Targa Badlands, LLC (“Targa Badlands”), the DevCo Joint Ventures and the 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 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 purchase and sale, 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:
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Three Months Ended
September 30, |
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|
|
|
|
|
|
|
|
Nine Months Ended
September 30, |
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|
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|
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|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
|
|
|
(In millions, except operating statistics and price amounts) |
|
| Gross margin |
$ |
|
362.9 |
|
|
$ |
|
366.7 |
|
|
$ |
|
(3.8 |
) |
|
|
(1 |
%) |
|
$ |
|
1,071.4 |
|
|
$ |
|
1,092.0 |
|
|
$ |
|
(20.6 |
) |
|
|
(2 |
%) |
| Operating expenses |
|
|
101.9 |
|
|
|
|
120.2 |
|
|
|
|
(18.3 |
) |
|
|
(15 |
%) |
|
|
|
317.7 |
|
|
|
|
375.2 |
|
|
|
|
(57.5 |
) |
|
|
(15 |
%) |
| Operating margin |
$ |
|
261.0 |
|
|
$ |
|
246.5 |
|
|
$ |
|
14.5 |
|
|
|
6 |
% |
|
$ |
|
753.7 |
|
|
$ |
|
716.8 |
|
|
$ |
|
36.9 |
|
|
|
5 |
% |
| Operating statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Plant natural gas inlet, MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Permian Midland (4) |
|
|
1,811.5 |
|
|
|
|
1,513.9 |
|
|
|
|
297.6 |
|
|
|
20 |
% |
|
|
|
1,722.1 |
|
|
|
|
1,421.3 |
|
|
|
|
300.8 |
|
|
|
21 |
% |
| Permian Delaware |
|
|
758.1 |
|
|
|
|
629.4 |
|
|
|
|
128.7 |
|
|
|
20 |
% |
|
|
|
712.4 |
|
|
|
|
552.2 |
|
|
|
|
160.2 |
|
|
|
29 |
% |
| Total Permian |
|
|
2,569.6 |
|
|
|
|
2,143.3 |
|
|
|
|
426.3 |
|
|
|
|
|
|
|
|
2,434.5 |
|
|
|
|
1,973.5 |
|
|
|
|
461.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SouthTX (5) |
|
|
233.6 |
|
|
|
|
328.6 |
|
|
|
|
(95.0 |
) |
|
|
(29 |
%) |
|
|
|
261.5 |
|
|
|
|
335.3 |
|
|
|
|
(73.8 |
) |
|
|
(22 |
%) |
| North Texas |
|
|
197.8 |
|
|
|
|
228.2 |
|
|
|
|
(30.4 |
) |
|
|
(13 |
%) |
|
|
|
206.3 |
|
|
|
|
227.6 |
|
|
|
|
(21.3 |
) |
|
|
(9 |
%) |
| SouthOK (6) |
|
|
386.9 |
|
|
|
|
590.8 |
|
|
|
|
(203.9 |
) |
|
|
(35 |
%) |
|
|
|
463.3 |
|
|
|
|
606.1 |
|
|
|
|
(142.8 |
) |
|
|
(24 |
%) |
| WestOK |
|
|
233.6 |
|
|
|
|
329.2 |
|
|
|
|
(95.6 |
) |
|
|
(29 |
%) |
|
|
|
258.7 |
|
|
|
|
335.2 |
|
|
|
|
(76.5 |
) |
|
|
(23 |
%) |
| Total Central |
|
|
1,051.9 |
|
|
|
|
1,476.8 |
|
|
|
|
(424.9 |
) |
|
|
|
|
|
|
|
1,189.8 |
|
|
|
|
1,504.2 |
|
|
|
|
(314.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Badlands (7),(8) |
|
|
137.0 |
|
|
|
|
120.8 |
|
|
|
|
16.2 |
|
|
|
13 |
% |
|
|
|
136.1 |
|
|
|
|
103.4 |
|
|
|
|
32.7 |
|
|
|
32 |
% |
| Total Field |
|
|
3,758.5 |
|
|
|
|
3,740.9 |
|
|
|
|
17.6 |
|
|
|
|
|
|
|
|
3,760.4 |
|
|
|
|
3,581.1 |
|
|
|
|
179.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Coastal |
|
|
522.8 |
|
|
|
|
764.9 |
|
|
|
|
(242.1 |
) |
|
|
(32 |
%) |
|
|
|
672.9 |
|
|
|
|
779.9 |
|
|
|
|
(107.0 |
) |
|
|
(14 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
4,281.3 |
|
|
|
|
4,505.8 |
|
|
|
|
(224.5 |
) |
|
|
(5 |
%) |
|
|
|
4,433.3 |
|
|
|
|
4,361.0 |
|
|
|
|
72.3 |
|
|
|
2 |
% |
| NGL production, MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Permian Midland (4) |
|
|
253.0 |
|
|
|
|
216.5 |
|
|
|
|
36.5 |
|
|
|
17 |
% |
|
|
|
247.6 |
|
|
|
|
199.8 |
|
|
|
|
47.8 |
|
|
|
24 |
% |
| Permian Delaware |
|
|
105.3 |
|
|
|
|
82.3 |
|
|
|
|
23.0 |
|
|
|
28 |
% |
|
|
|
97.1 |
|
|
|
|
71.4 |
|
|
|
|
25.7 |
|
|
|
36 |
% |
| Total Permian |
|
|
358.3 |
|
|
|
|
298.8 |
|
|
|
|
59.5 |
|
|
|
|
|
|
|
|
344.7 |
|
|
|
|
271.2 |
|
|
|
|
73.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SouthTX (5) |
|
|
29.2 |
|
|
|
|
41.5 |
|
|
|
|
(12.3 |
) |
|
|
(30 |
%) |
|
|
|
28.7 |
|
|
|
|
44.0 |
|
|
|
|
(15.3 |
) |
|
|
(35 |
%) |
| North Texas |
|
|
23.7 |
|
|
|
|
27.3 |
|
|
|
|
(3.6 |
) |
|
|
(13 |
%) |
|
|
|
24.5 |
|
|
|
|
26.9 |
|
|
|
|
(2.4 |
) |
|
|
(9 |
%) |
| SouthOK (6) |
|
|
45.9 |
|
|
|
|
69.5 |
|
|
|
|
(23.6 |
) |
|
|
(34 |
%) |
|
|
|
54.6 |
|
|
|
|
65.4 |
|
|
|
|
(10.8 |
) |
|
|
(17 |
%) |
| WestOK |
|
|
19.3 |
|
|
|
|
19.2 |
|
|
|
|
0.1 |
|
|
|
1 |
% |
|
|
|
21.2 |
|
|
|
|
22.4 |
|
|
|
|
(1.2 |
) |
|
|
(5 |
%) |
| Total Central |
|
|
118.1 |
|
|
|
|
157.5 |
|
|
|
|
(39.4 |
) |
|
|
|
|
|
|
|
129.0 |
|
|
|
|
158.7 |
|
|
|
|
(29.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Badlands (8) |
|
|
17.0 |
|
|
|
|
14.0 |
|
|
|
|
3.0 |
|
|
|
21 |
% |
|
|
|
16.3 |
|
|
|
|
12.2 |
|
|
|
|
4.1 |
|
|
|
34 |
% |
| Total Field |
|
|
493.4 |
|
|
|
|
470.3 |
|
|
|
|
23.1 |
|
|
|
|
|
|
|
|
490.0 |
|
|
|
|
442.1 |
|
|
|
|
47.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Coastal |
|
|
32.5 |
|
|
|
|
45.4 |
|
|
|
|
(12.9 |
) |
|
|
(28 |
%) |
|
|
|
41.5 |
|
|
|
|
47.0 |
|
|
|
|
(5.5 |
) |
|
|
(12 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
525.9 |
|
|
|
|
515.7 |
|
|
|
|
10.2 |
|
|
|
2 |
% |
|
|
|
531.5 |
|
|
|
|
489.1 |
|
|
|
|
42.4 |
|
|
|
9 |
% |
| Crude oil, Badlands, MBbl/d |
|
|
146.4 |
|
|
|
|
164.3 |
|
|
|
|
(17.9 |
) |
|
|
(11 |
%) |
|
|
|
160.4 |
|
|
|
|
167.0 |
|
|
|
|
(6.6 |
) |
|
|
(4 |
%) |
| Crude oil, Permian, MBbl/d (9) |
|
|
44.6 |
|
|
|
|
95.2 |
|
|
|
|
(50.6 |
) |
|
|
(53 |
%) |
|
|
|
45.3 |
|
|
|
|
86.1 |
|
|
|
|
(40.8 |
) |
|
|
(47 |
%) |
| Natural gas sales, BBtu/d (3),(10) |
|
|
2,032.3 |
|
|
|
|
2,056.6 |
|
|
|
|
(24.3 |
) |
|
|
(1 |
%) |
|
|
|
2,079.3 |
|
|
|
|
2,011.2 |
|
|
|
|
68.1 |
|
|
|
3 |
% |
| NGL sales, MBbl/d (3),(10) |
|
|
389.5 |
|
|
|
|
398.0 |
|
|
|
|
(8.5 |
) |
|
|
(2 |
%) |
|
|
|
406.0 |
|
|
|
|
382.4 |
|
|
|
|
23.6 |
|
|
|
6 |
% |
| Condensate sales, MBbl/d |
|
|
13.6 |
|
|
|
|
11.0 |
|
|
|
|
2.6 |
|
|
|
24 |
% |
|
|
|
16.1 |
|
|
|
|
12.2 |
|
|
|
|
3.9 |
|
|
|
32 |
% |
| Average realized prices - inclusive of hedges (11): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas, $/MMBtu |
|
|
1.34 |
|
|
|
|
1.13 |
|
|
|
|
0.21 |
|
|
|
19 |
% |
|
|
|
1.10 |
|
|
|
|
1.31 |
|
|
|
|
(0.21 |
) |
|
|
(16 |
%) |
| NGL, $/gal |
|
|
0.29 |
|
|
|
|
0.28 |
|
|
|
|
0.01 |
|
|
|
4 |
% |
|
|
|
0.24 |
|
|
|
|
0.35 |
|
|
|
|
(0.11 |
) |
|
|
(31 |
%) |
| Condensate, $/Bbl |
|
|
43.49 |
|
|
|
|
50.23 |
|
|
|
|
(6.74 |
) |
|
|
(13 |
%) |
|
|
|
38.56 |
|
|
|
|
49.49 |
|
|
|
|
(10.93 |
) |
|
|
(22 |
%) |
(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 volume and includes the Targa 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 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 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 September 30, 2020 |
|
|
Three Months Ended September 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) |
|
|
17.5 |
|
|
$ |
0.20 |
|
|
$ |
3.5 |
|
|
|
18.8 |
|
|
$ |
1.07 |
|
|
$ |
20.1 |
|
| NGL (MMgal) |
|
|
126.4 |
|
|
|
0.08 |
|
|
|
10.5 |
|
|
|
110.0 |
|
|
|
0.17 |
|
|
|
18.5 |
|
| Crude oil (MBbl) |
|
|
0.5 |
|
|
|
16.75 |
|
|
|
8.0 |
|
|
|
0.4 |
|
|
|
(1.76 |
) |
|
|
(0.7 |
) |
|
|
|
|
|
|
|
|
|
|
$ |
22.0 |
|
|
|
|
|
|
|
|
|
|
$ |
37.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2020 |
|
|
Nine Months Ended September 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) |
|
|
50.6 |
|
|
$ |
0.55 |
|
|
$ |
27.7 |
|
|
|
47.0 |
|
|
$ |
1.29 |
|
|
$ |
60.6 |
|
| NGL (MMgal) |
|
|
322.1 |
|
|
|
0.15 |
|
|
|
49.7 |
|
|
|
252.1 |
|
|
|
0.11 |
|
|
|
27.9 |
|
| Crude oil (MBbl) |
|
|
1.4 |
|
|
|
19.72 |
|
|
|
27.7 |
|
|
|
1.1 |
|
|
|
(2.28 |
) |
|
|
(2.6 |
) |
|
|
|
|
|
|
|
|
|
|
$ |
105.1 |
|
|
|
|
|
|
|
|
|
|
$ |
85.9 |
|
(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 September 30, 2020 Compared to Three Months Ended September 30, 2019
Gathering and Processing segment gross margin contributions, attributable to higher system volumes and fee-based margin in the Permian region, were offset by lower volumes in the Central region and lower realized hedge gains. 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 and Gateway plants in 2020. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. 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 quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. 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 that resulted in decreases in compensation and benefits, contract labor and chemicals, despite the addition of the Peregrine and Gateway processing facilities in the Permian.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
Gathering and Processing segment gross margin contributions, attributable to higher inlet volumes and fee-based margin in the Permian region and Badlands and higher realized hedge gains, were offset by lower commodity prices and lower Central region volumes. 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. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. 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 quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. 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 that resulted in decreases in contract labor, chemicals and compression rentals and lower ad valorem taxes, 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 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, as well as the Company's equity interest in GCX, a natural gas pipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix 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
September 30, |
|
|
|
|
|
|
Nine Months Ended
September 30, |
|
|
|
|
|
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
|
|
|
(In millions, except operating statistics and price amounts) |
|
| Gross margin |
|
$ |
|
362.0 |
|
|
$ |
|
310.4 |
|
|
$ |
|
51.6 |
|
|
|
17 |
% |
|
$ |
|
1,057.0 |
|
|
$ |
|
792.4 |
|
|
$ |
|
264.6 |
|
|
|
33 |
% |
| Operating expenses (1) |
|
|
|
81.6 |
|
|
|
|
81.5 |
|
|
|
|
0.1 |
|
|
|
0 |
% |
|
|
|
251.0 |
|
|
|
|
227.4 |
|
|
|
|
23.6 |
|
|
|
10 |
% |
| Operating margin |
|
$ |
|
280.4 |
|
|
$ |
|
228.9 |
|
|
$ |
|
51.5 |
|
|
|
22 |
% |
|
$ |
|
806.0 |
|
|
$ |
|
565.0 |
|
|
$ |
|
241.0 |
|
|
|
43 |
% |
| Operating statistics MBbl /d (2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fractionation volumes (3) |
|
|
|
589.5 |
|
|
|
|
508.8 |
|
|
|
|
80.7 |
|
|
|
16 |
% |
|
|
|
598.0 |
|
|
|
|
492.8 |
|
|
|
|
105.2 |
|
|
|
21 |
% |
| Export volumes (4) |
|
|
|
308.5 |
|
|
|
|
239.2 |
|
|
|
|
69.3 |
|
|
|
29 |
% |
|
|
|
277.2 |
|
|
|
|
228.1 |
|
|
|
|
49.1 |
|
|
|
22 |
% |
| Pipeline throughput (5) |
|
|
|
300.9 |
|
|
|
|
131.8 |
|
|
|
|
169.1 |
|
|
|
128 |
% |
|
|
|
273.0 |
|
|
|
|
44.4 |
|
|
|
|
228.6 |
|
|
NM |
|
| NGL sales |
|
|
|
724.1 |
|
|
|
|
672.1 |
|
|
|
|
52.0 |
|
|
|
8 |
% |
|
|
|
721.6 |
|
|
|
|
620.9 |
|
|
|
|
100.7 |
|
|
|
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 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.
NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.
Three Months Ended September 30, 2020 Compared to Three Months Ended September 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 higher 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 Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of the Company's LPG export capabilities. Marketing margin decreased primarily due to less optimization margin realized in the Company's marketing businesses.
Operating expenses were flat, despite the operations of a number of system expansions, including Grand Prix, additional incremental fractionation capacity and expansion of the Company's LPG export capabilities. Lower fuel and power costs and cost reduction measures that resulted in lower compensation and maintenance were offset by increased taxes primarily attributable to Grand Prix and the inclusion of the Company's share of operating expenses associated with GCF.
Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 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 higher 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 6 in the second quarter of 2019, Train 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of the Company’s LPG export capabilities. Marketing margin decreased due to less optimization margin realized in the Company’s marketing businesses.
Operating expenses were higher primarily due to the inclusion of the Company’s share of operating expenses associated with GCF, increased costs attributable to the Company’s fractionation and LPG export expansions, higher taxes primarily attributable to Grand Prix and to additional incremental fractionation capacity, and higher maintenance primarily attributable to Grand Prix, partially offset by lower fuel and power costs.
Other
|
|
Three Months Ended September 30, |
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
2020 |
|
|
2019 |
|
|
2020 vs. 2019 |
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
(In millions) |
|
| Gross margin |
|
$ |
88.6 |
|
|
$ |
(101.2 |
) |
|
$ |
189.8 |
|
|
$ |
215.9 |
|
|
$ |
(101.1 |
) |
|
$ |
317.0 |
|
| Operating margin |
|
$ |
88.6 |
|
|
$ |
(101.2 |
) |
|
$ |
189.8 |
|
|
$ |
215.9 |
|
|
$ |
(101.1 |
) |
|
$ |
317.0 |
|
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. 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, 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
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 and Free 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). The Company defines free cash flow 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 or retirement of debt.
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 September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
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 |
|
$ |
|
69.3 |
|
|
$ |
|
(47.3 |
) |
|
$ |
|
(1,587.5 |
) |
|
$ |
|
(96.4 |
) |
| Income attributable to TRP preferred limited partners |
|
|
|
2.8 |
|
|
|
|
2.8 |
|
|
|
|
8.4 |
|
|
|
|
8.4 |
|
| Interest (income) expense, net |
|
|
|
97.7 |
|
|
|
|
89.1 |
|
|
|
|
292.4 |
|
|
|
|
241.8 |
|
| Income tax expense (benefit) |
|
|
|
31.9 |
|
|
|
|
(3.8 |
) |
|
|
|
(286.6 |
) |
|
|
|
(10.0 |
) |
| Depreciation and amortization expense |
|
|
|
203.7 |
|
|
|
|
244.3 |
|
|
|
|
647.3 |
|
|
|
|
718.9 |
|
| Impairment of long-lived assets |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
2,442.8 |
|
|
|
|
— |
|
| (Gain) loss on sale or disposition of business and assets |
|
|
|
58.0 |
|
|
|
|
0.5 |
|
|
|
|
58.0 |
|
|
|
|
3.6 |
|
| Write-down of assets |
|
|
|
13.5 |
|
|
|
|
17.9 |
|
|
|
|
13.5 |
|
|
|
|
17.9 |
|
| (Gain) loss from sale of equity-method investment |
|
|
|
— |
|
|
|
|
(65.8 |
) |
|
|
|
— |
|
|
|
|
(65.8 |
) |
| (Gain) loss from financing activities (1) |
|
|
|
13.7 |
|
|
|
|
— |
|
|
|
|
(47.4 |
) |
|
|
|
1.4 |
|
| Equity (earnings) loss |
|
|
|
(18.6 |
) |
|
|
|
(10.0 |
) |
|
|
|
(54.1 |
) |
|
|
|
(15.9 |
) |
| Distributions from unconsolidated affiliates and preferred partner interests, net |
|
|
|
28.2 |
|
|
|
|
14.0 |
|
|
|
|
81.6 |
|
|
|
|
33.4 |
|
| Change in contingent considerations |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
— |
|
|
|
|
8.8 |
|
| Compensation on equity grants |
|
|
|
16.4 |
|
|
|
|
16.1 |
|
|
|
|
49.5 |
|
|
|
|
49.0 |
|
| Risk management activities |
|
|
|
(88.3 |
) |
|
|
|
100.7 |
|
|
|
|
(214.2 |
) |
|
|
|
100.8 |
|
| Severance and related benefits (2) |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
6.5 |
|
|
|
|
— |
|
| Noncontrolling interests adjustments (3) |
|
|
|
(9.2 |
) |
|
|
|
(8.9 |
) |
|
|
|
(211.7 |
) |
|
|
|
(25.6 |
) |
| TRC Adjusted EBITDA |
|
$ |
|
419.1 |
|
|
$ |
|
349.6 |
|
|
$ |
|
1,198.5 |
|
|
$ |
|
970.3 |
|
| Distributions to TRP preferred limited partners |
|
|
|
(2.8 |
) |
|
|
|
(2.8 |
) |
|
|
|
(8.4 |
) |
|
|
|
(8.4 |
) |
| Interest expense on debt obligations (4) |
|
|
|
(98.2 |
) |
|
|
|
(88.0 |
) |
|
|
|
(289.5 |
) |
|
|
|
(247.0 |
) |
| Cash tax refund |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
44.4 |
|
|
|
|
— |
|
| Maintenance capital expenditures |
|
|
|
(27.3 |
) |
|
|
|
(31.0 |
) |
|
|
|
(67.7 |
) |
|
|
|
(101.5 |
) |
| Noncontrolling interests adjustments of maintenance capital expenditures |
|
|
|
3.9 |
|
|
|
|
2.1 |
|
|
|
|
1.6 |
|
|
|
|
6.0 |
|
| Distributable Cash Flow |
|
$ |
|
294.7 |
|
|
$ |
|
229.9 |
|
|
$ |
|
878.9 |
|
|
$ |
|
619.4 |
|
| Growth capital expenditures, net (5) |
|
|
|
(105.4 |
) |
|
|
|
(448.4 |
) |
|
|
|
(518.5 |
) |
|
|
|
(1,946.2 |
) |
| Free Cash Flow |
|
$ |
|
189.3 |
|
|
$ |
|
(218.5 |
) |
|
$ |
|
360.4 |
|
|
$ |
|
(1,326.8 |
) |
_____________________
(1) Gains or losses on debt repurchases, amendments, exchanges 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 |
| 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 |
(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.
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, 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 September 30, |
|
|
Nine Months Ended September 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 |
|
$ |
|
69.3 |
|
|
$ |
|
(47.3 |
) |
|
$ |
|
(1,587.5 |
) |
|
$ |
|
(96.4 |
) |
| Net income (loss) attributable to noncontrolling interests |
|
|
|
102.9 |
|
|
|
|
79.4 |
|
|
|
|
116.5 |
|
|
|
|
152.7 |
|
| Net income (loss) |
|
|
|
172.2 |
|
|
|
|
32.1 |
|
|
|
|
(1,471.0 |
) |
|
|
|
56.3 |
|
| Depreciation and amortization expense |
|
|
|
203.7 |
|
|
|
|
244.3 |
|
|
|
|
647.3 |
|
|
|
|
718.9 |
|
| General and administrative expense |
|
|
|
58.6 |
|
|
|
|
69.9 |
|
|
|
|
180.6 |
|
|
|
|
223.5 |
|
| Impairment of long-lived assets |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
2,442.8 |
|
|
|
|
— |
|
| Interest (income) expense, net |
|
|
|
97.7 |
|
|
|
|
89.1 |
|
|
|
|
292.4 |
|
|
|
|
241.8 |
|
| Equity (earnings) loss |
|
|
|
(18.6 |
) |
|
|
|
(10.0 |
) |
|
|
|
(54.1 |
) |
|
|
|
(15.9 |
) |
| Income tax expense (benefit) |
|
|
|
31.9 |
|
|
|
|
(3.8 |
) |
|
|
|
(286.6 |
) |
|
|
|
(10.0 |
) |
| (Gain) loss on sale or disposition of business and assets |
|
|
|
58.0 |
|
|
|
|
0.5 |
|
|
|
|
58.0 |
|
|
|
|
3.6 |
|
| Write-down of assets |
|
|
|
13.5 |
|
|
|
|
17.9 |
|
|
|
|
13.5 |
|
|
|
|
17.9 |
|
| (Gain) loss from sale of equity-method investment |
|
|
|
— |
|
|
|
|
(65.8 |
) |
|
|
|
— |
|
|
|
|
(65.8 |
) |
| (Gain) loss from financing activities |
|
|
|
13.7 |
|
|
|
|
— |
|
|
|
|
(47.4 |
) |
|
|
|
1.4 |
|
| Change in contingent considerations |
|
|
|
— |
|
|
|
|
— |
|
|
|
|
— |
|
|
|
|
8.8 |
|
| Other, net |
|
|
|
(0.7 |
) |
|
|
|
— |
|
|
|
|
0.1 |
|
|
|
|
0.2 |
|
| Operating margin |
|
|
|
630.0 |
|
|
|
|
374.2 |
|
|
|
|
1,775.6 |
|
|
|
|
1,180.7 |
|
| Operating expenses |
|
|
|
181.9 |
|
|
|
|
200.2 |
|
|
|
|
565.1 |
|
|
|
|
600.8 |
|
| Gross margin |
|
$ |
|
811.9 |
|
|
$ |
|
574.4 |
|
|
$ |
|
2,340.7 |
|
|
$ |
|
1,781.5 |
|
Targa currently estimates its full-year 2020 Adjusted EBITDA to be at or around the high end of its previously provided outlook of $1.5 billion to $1.625 billion. 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 |
|
$ |
|
(1,480.5 |
) |
| Impairment of long-lived assets |
|
|
|
2,443.0 |
|
| Income attributable to TRP preferred limited partners |
|
|
|
11.0 |
|
| Interest expense, net |
|
|
|
385.0 |
|
| Income tax expense (benefit) |
|
|
(295.0 |
) |
| Depreciation and amortization expense |
|
|
|
870.0 |
|
| Equity (earnings) loss |
|
|
|
(70.0 |
) |
| Distributions from unconsolidated affiliates and preferred partner interests, net |
|
|
|
110.0 |
|
| Compensation on equity grants |
|
|
|
70.0 |
|
| Risk management activities and other |
|
|
|
(195.0 |
) |
| Severance and related benefits (1) |
|
|
|
6.5 |
|
| Noncontrolling interests adjustments (2) |
|
|
|
(230.0 |
) |
| TRC Estimated Adjusted EBITDA |
|
$ |
|
1,625.0 |
|
(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
Vice President, Finance & Investor Relations
Jennifer Kneale
Chief Financial Officer
