Targa Resources Corp. Reports Third Quarter 2023 Financial Results and Announces Expectations for a 50% Year-Over-Year Increase to 2024 Common Dividend
- Net income for Q3 2023 increased by 14% YoY, reaching $220.0 million.
- Adjusted EBITDA for Q3 is $840 million, showing a 6% increase compared to the previous quarter.
- The company completed its 1 million barrel per month LPG export expansion at Galena Park.
- Targa also completed its new 275 million cubic feet per day Greenwood plant in Permian Midland.
- During Q3, the company repurchased $132 million of common stock and $333 million for the nine months ended September 30, 2023.
- The company maintains its 2023 adjusted EBITDA estimate between $3.5 billion and $3.7 billion.
- The company expects to recommend an annual common dividend per share of $3.00 in 2024, a 50% increase to 2023.
- Targa's Permian inlet gas volumes in Q4 are currently 150 MMcf/d higher compared to average Q3 volumes.
- None.
HOUSTON, Nov. 02, 2023 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported third quarter 2023 results.
Third quarter 2023 net income attributable to Targa Resources Corp. was
Highlights
- Reported adjusted EBITDA(1) for the third quarter of
$840 million , a6% sequential increase - Reported record NGL transportation volumes during the third quarter
- Completed its 1 million barrel per month LPG export expansion at Galena Park
- Completed its new 275 million cubic feet per day (“MMcf/d”) Greenwood plant in Permian Midland
- Repurchased
$132 million of common stock during the third quarter and$333 million for the nine months ended September 30, 2023 at a weighted average price of$75.77 - Maintains 2023 adjusted EBITDA estimate between
$3.5 billion and$3.7 billion , with current expectations trending to the lower end of the range - No change to 2023 net growth capital expenditure estimate of
$2.0 t o$2.2 billion , with current expectations trending to the higher end of the range - Strong start to the fourth quarter with Permian inlet gas volumes currently 150 MMcf/d higher when compared to average third quarter volumes
- Expect to recommend to Targa’s Board of Directors an annual common dividend per share of
$3.00 in 2024, a50% increase to 2023, reflective of a continued commitment to return additional capital to shareholders and the strength of Targa’s outlook
The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) of
On October 12, 2023, the Company declared a quarterly cash dividend of
Targa repurchased 1,583,317 shares of its common stock during the third quarter of 2023 at a weighted average per share price of
Third Quarter 2023 - Sequential Quarter over Quarter Commentary
Targa reported third quarter adjusted EBITDA of
Capitalization and Liquidity
The Company’s total consolidated debt as of September 30, 2023 was
Total consolidated liquidity as of September 30, 2023 was approximately
Growth Projects Update
In early fourth quarter, Targa commenced operations at its new 275 MMcf/d Greenwood plant in Permian Midland ahead of schedule and on-budget. Construction continues on its 275 MMcf/d Greenwood II plant in Permian Midland. In Permian Delaware, construction continues on the 275 MMcf/d Wildcat II, 230 MMcf/d Roadrunner II and 275 MMcf/d Bull Moose plants. In its L&T segment, Targa completed its 1 million barrel per month LPG export expansion at Galena Park late in the third quarter. Construction continues on Targa’s 120 thousand barrel per day (“MBbl/d”) Train 9 fractionator and its 120 MBbl/d Train 10 fractionator in Mont Belvieu, Texas, and its Daytona NGL Pipeline. Targa remains on-track to complete these expansions as previously disclosed.
2023 Outlook
Targa maintains its 2023 adjusted EBITDA between
Targa’s estimate for 2023 total net growth capital expenditures remains unchanged at between
Capital Allocation Update
For the first quarter of 2024, Targa intends to recommend to its Board of Directors an increase to its common dividend to
For the nine months ended September 30, 2023, Targa has repurchased 4,395,519 shares of common stock at a weighted average per share price of
An earnings supplement presentation and an updated investor presentation are available under Events and Presentations in the Investors section of the Company’s website at www.targaresources.com/investors/events.
Conference Call
The Company will host a conference call for the investment community at 11:00 a.m. Eastern time (10:00 a.m. Central time) on November 2, 2023 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/vrp8beac. A webcast replay will be available at the link above approximately two hours after the conclusion of the event.
(1) Adjusted EBITDA is a non-GAAP financial measure and is discussed under “Non-GAAP Financial Measures.”
Targa Resources Corp. – Consolidated Financial Results of Operations
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||||||
| Sales of commodities | $ | 3,374.3 | $ | 4,800.3 | $ | (1,426.0 | ) | (30 | %) | $ | 10,314.0 | $ | 14,990.7 | $ | (4,676.7 | ) | (31 | %) | ||||||||||||
| Fees from midstream services | 522.3 | 559.8 | (37.5 | ) | (7 | %) | 1,506.8 | 1,384.3 | 122.5 | 9 | % | |||||||||||||||||||
| Total revenues | 3,896.6 | 5,360.1 | (1,463.5 | ) | (27 | %) | 11,820.8 | 16,375.0 | (4,554.2 | ) | (28 | %) | ||||||||||||||||||
| Product purchases and fuel | 2,690.0 | 4,306.3 | (1,616.3 | ) | (38 | %) | 7,777.9 | 13,557.8 | (5,779.9 | ) | (43 | %) | ||||||||||||||||||
| Operating expenses | 277.7 | 261.3 | 16.4 | 6 | % | 808.4 | 660.6 | 147.8 | 22 | % | ||||||||||||||||||||
| Depreciation and amortization expense | 331.3 | 287.2 | 44.1 | 15 | % | 988.2 | 766.2 | 222.0 | 29 | % | ||||||||||||||||||||
| General and administrative expense | 90.0 | 79.1 | 10.9 | 14 | % | 253.4 | 217.2 | 36.2 | 17 | % | ||||||||||||||||||||
| Other operating (income) expense | 2.5 | (3.8 | ) | 6.3 | 166 | % | 2.0 | (4.4 | ) | 6.4 | 145 | % | ||||||||||||||||||
| Income (loss) from operations | 505.1 | 430.0 | 75.1 | 17 | % | 1,990.9 | 1,177.6 | 813.3 | 69 | % | ||||||||||||||||||||
| Interest expense, net | (175.1 | ) | (125.8 | ) | (49.3 | ) | 39 | % | (509.8 | ) | (300.5 | ) | (209.3 | ) | 70 | % | ||||||||||||||
| Equity earnings (loss) | 3.0 | 1.7 | 1.3 | 76 | % | 6.2 | 8.7 | (2.5 | ) | (29 | %) | |||||||||||||||||||
| Gain (loss) from financing activities | — | — | — | — | — | (49.6 | ) | 49.6 | 100 | % | ||||||||||||||||||||
| Gain (loss) from sale of equity method investment | — | — | — | — | — | 435.9 | (435.9 | ) | (100 | %) | ||||||||||||||||||||
| Other, net | (0.1 | ) | (14.6 | ) | 14.5 | 99 | % | (4.9 | ) | (14.6 | ) | 9.7 | 66 | % | ||||||||||||||||
| Income tax (expense) benefit | (53.9 | ) | (12.0 | ) | (41.9 | ) | NM | (260.7 | ) | (122.0 | ) | (138.7 | ) | 114 | % | |||||||||||||||
| Net income (loss) | 279.0 | 279.3 | (0.3 | ) | — | 1,221.7 | 1,135.5 | 86.2 | 8 | % | ||||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 59.0 | 86.2 | (27.2 | ) | (32 | %) | 175.4 | 258.0 | (82.6 | ) | (32 | %) | ||||||||||||||||||
| Net income (loss) attributable to Targa Resources Corp. | 220.0 | 193.1 | 26.9 | 14 | % | 1,046.3 | 877.5 | 168.8 | 19 | % | ||||||||||||||||||||
| Premium on repurchase of noncontrolling interests, net of tax | — | — | — | — | 490.7 | 53.1 | 437.6 | NM | ||||||||||||||||||||||
| Dividends on Series A Preferred Stock | — | — | — | — | — | 30.0 | (30.0 | ) | (100 | %) | ||||||||||||||||||||
| Deemed dividends on Series A Preferred Stock | — | — | — | — | — | 215.5 | (215.5 | ) | (100 | %) | ||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | 220.0 | $ | 193.1 | $ | 26.9 | 14 | % | $ | 555.6 | $ | 578.9 | $ | (23.3 | ) | (4 | %) | |||||||||||||
| Financial data: | ||||||||||||||||||||||||||||||
| Adjusted EBITDA (1) | $ | 840.2 | $ | 768.6 | $ | 71.6 | 9 | % | $ | 2,570.1 | $ | 2,060.8 | $ | 509.3 | 25 | % | ||||||||||||||
| Distributable cash flow (1) | 602.2 | 594.9 | 7.3 | 1 | % | 1,907.6 | 1,623.2 | 284.4 | 18 | % | ||||||||||||||||||||
| Adjusted free cash flow (1) | 8.6 | 290.8 | (282.2 | ) | (97 | %) | 319.1 | 998.4 | (679.3 | ) | (68 | %) | ||||||||||||||||||
(1) Adjusted EBITDA, distributable cash flow and adjusted free cash flow are non-GAAP financial measures and are discussed under “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, 2023 Compared to Three Months Ended September 30, 2022
The decrease in commodity sales reflects lower natural gas, NGL and condensate prices (
The decrease in fees from midstream services is primarily due to lower gas gathering and processing fees and transportation and fractionation volumes, partially offset by higher export volumes.
The decrease in product purchases and fuel reflects lower natural gas, NGL and condensate prices, partially offset by higher NGL and natural gas volumes.
The increase in operating expenses is primarily due to higher labor and maintenance costs due to increased activity and system expansions, the acquisition of certain assets in the Delaware Basin and inflation.
See “—Review of Segment Performance” for additional information on a segment basis.
The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the Delaware Basin and the impact of system expansions on the Company’s asset base, partially offset by the shortening of the depreciable lives of certain assets that were idled in 2022.
The increase in general and administrative expense is primarily due to higher compensation and benefits and insurance costs.
The increase in interest expense, net is due to higher net borrowings primarily for the acquisition of certain assets in the Delaware Basin and the Grand Prix Transaction, and higher interest rates, partially offset by higher capitalized interest resulting from higher growth capital investments.
The increase in income tax expense is primarily due to an increase in pre-tax book income and a smaller release of the valuation allowance in 2023 compared to 2022.
The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the Grand Prix Transaction and lower earnings allocated to the Company’s joint venture partner in WestTX.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022
The decrease in commodity sales reflects lower NGL, natural gas and condensate prices (
The increase in fees from midstream services is primarily due to higher gas gathering and processing fees including the impact of the acquisition of certain assets in the Delaware Basin and South Texas, and higher export fees, partially offset by lower transportation and fractionation fees.
The decrease in product purchases and fuel reflects lower NGL, natural gas and condensate prices, partially offset by higher NGL, natural gas and condensate volumes.
The increase in operating expenses is primarily due to higher labor and maintenance costs due to increased activity and system expansions, the acquisition of certain assets in the Delaware Basin and South Texas, and inflation.
See “—Review of Segment Performance” for additional information on a segment basis.
The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the Delaware Basin and the impact of system expansions on our asset base, partially offset by the shortening of depreciable lives of certain assets that were idled in 2022.
The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and professional fees.
The increase in interest expense, net is due to higher net borrowings primarily for the acquisition of certain assets in the Delaware Basin and the Grand Prix Transaction, and higher interest rates, partially offset by higher capitalized interest resulting from higher growth capital investments.
During 2022, the Company terminated the previous TRGP senior secured revolving credit facility and the Partnership’s senior secured revolving credit facility. In addition, the Partnership redeemed its
During 2022, the Company completed the sale of Targa GCX Pipeline LLC to a third party resulting in a gain from sale of an equity method investment.
The increase in income tax expense is primarily due to an increase in pre-tax book income and a smaller release of the valuation allowance in 2023 compared to 2022.
The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the Grand Prix Transaction and lower earnings allocated to the Company’s joint venture partner in WestTX and Venice Energy Services Company, L.L.C.
The premium on repurchase of noncontrolling interests, net of tax is due to the Grand Prix Transaction in 2023 and the purchase of all of Stonepeak Infrastructure Partners’ interests in the Company’s development company joint ventures in 2022.
The decrease in dividends on Series A Preferred Stock (“Series A Preferred”) is due to the full redemption of all of the Company’s issued and outstanding shares of Series A Preferred in May 2022.
Review of Segment Performance
The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin and adjusted operating 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 adjusted operating margin, see “Non-GAAP Financial Measures ― Adjusted Operating Margin.” Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation.
The Company operates in two primary segments: (i) Gathering and Processing; and (ii) Logistics and Transportation.
Gathering and Processing Segment
The Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
The following table provides summary data regarding results of operations of this segment for the periods indicated:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | 2023 | 2022 | 2023 vs. 2022 | ||||||||||||||||||||||||||||||||
| (In millions, except operating statistics and price amounts) | |||||||||||||||||||||||||||||||||||||
| Operating margin | $ | 505.0 | $ | 564.6 | $ | (59.6 | ) | (11 | %) | $ | 1,545.9 | $ | 1,437.0 | $ | 108.9 | 8 | % | ||||||||||||||||||||
| Operating expenses | 189.6 | 176.6 | 13.0 | 7 | % | 560.8 | 434.5 | 126.3 | 29 | % | |||||||||||||||||||||||||||
| Adjusted operating margin | $ | 694.6 | $ | 741.2 | $ | (46.6 | ) | (6 | %) | $ | 2,106.7 | $ | 1,871.5 | $ | 235.2 | 13 | % | ||||||||||||||||||||
| Operating statistics (1): | |||||||||||||||||||||||||||||||||||||
| Plant natural gas inlet, MMcf/d (2) (3) | |||||||||||||||||||||||||||||||||||||
| Permian Midland (4) | 2,566.9 | 2,307.2 | 259.7 | 11 | % | 2,474.1 | 2,172.3 | 301.8 | 14 | % | |||||||||||||||||||||||||||
| Permian Delaware (5) | 2,485.4 | 1,784.8 | 700.6 | 39 | % | 2,513.7 | 1,254.6 | 1,259.1 | 100 | % | |||||||||||||||||||||||||||
| Total Permian | 5,052.3 | 4,092.0 | 960.3 | 23 | % | 4,987.8 | 3,426.9 | 1,560.9 | 46 | % | |||||||||||||||||||||||||||
| SouthTX (6) | 394.4 | 335.5 | 58.9 | 18 | % | 373.9 | 256.9 | 117.0 | 46 | % | |||||||||||||||||||||||||||
| North Texas | 212.0 | 177.7 | 34.3 | 19 | % | 205.2 | 176.1 | 29.1 | 17 | % | |||||||||||||||||||||||||||
| SouthOK (6) | 394.6 | 400.4 | (5.8 | ) | (1 | %) | 391.2 | 422.7 | (31.5 | ) | (7 | %) | |||||||||||||||||||||||||
| WestOK | 206.2 | 212.8 | (6.6 | ) | (3 | %) | 207.1 | 209.1 | (2.0 | ) | (1 | %) | |||||||||||||||||||||||||
| Total Central | 1,207.2 | 1,126.4 | 80.8 | 7 | % | 1,177.4 | 1,064.8 | 112.6 | 11 | % | |||||||||||||||||||||||||||
| Badlands (6) (7) | 128.3 | 144.8 | (16.5 | ) | (11 | %) | 129.6 | 133.1 | (3.5 | ) | (3 | %) | |||||||||||||||||||||||||
| Total Field | 6,387.8 | 5,363.2 | 1,024.6 | 19 | % | 6,294.8 | 4,624.8 | 1,670.0 | 36 | % | |||||||||||||||||||||||||||
| Coastal | 535.6 | 539.1 | (3.5 | ) | (1 | %) | 532.4 | 564.7 | (32.3 | ) | (6 | %) | |||||||||||||||||||||||||
| Total | 6,923.4 | 5,902.3 | 1,021.1 | 17 | % | 6,827.2 | 5,189.5 | 1,637.7 | 32 | % | |||||||||||||||||||||||||||
| NGL production, MBbl/d (3) | |||||||||||||||||||||||||||||||||||||
| Permian Midland (4) | 373.1 | 332.6 | 40.5 | 12 | % | 357.4 | 314.8 | 42.6 | 14 | % | |||||||||||||||||||||||||||
| Permian Delaware (5) | 322.5 | 210.9 | 111.6 | 53 | % | 325.3 | 159.1 | 166.2 | 104 | % | |||||||||||||||||||||||||||
| Total Permian | 695.6 | 543.5 | 152.1 | 28 | % | 682.7 | 473.9 | 208.8 | 44 | % | |||||||||||||||||||||||||||
| SouthTX (6) | 42.3 | 36.4 | 5.9 | 16 | % | 42.1 | 30.1 | 12.0 | 40 | % | |||||||||||||||||||||||||||
| North Texas | 24.2 | 20.5 | 3.7 | 18 | % | 23.8 | 19.8 | 4.0 | 20 | % | |||||||||||||||||||||||||||
| SouthOK (6) | 46.4 | 48.1 | (1.7 | ) | (4 | %) | 44.2 | 51.4 | (7.2 | ) | (14 | %) | |||||||||||||||||||||||||
| WestOK | 12.3 | 14.8 | (2.5 | ) | (17 | %) | 12.6 | 15.4 | (2.8 | ) | (18 | %) | |||||||||||||||||||||||||
| Total Central | 125.2 | 119.8 | 5.4 | 5 | % | 122.7 | 116.7 | 6.0 | 5 | % | |||||||||||||||||||||||||||
| Badlands (6) | 15.5 | 18.0 | (2.5 | ) | (14 | %) | 15.5 | 15.8 | (0.3 | ) | (2 | %) | |||||||||||||||||||||||||
| Total Field | 836.3 | 681.3 | 155.0 | 23 | % | 820.9 | 606.4 | 214.5 | 35 | % | |||||||||||||||||||||||||||
| Coastal | 40.6 | 31.7 | 8.9 | 28 | % | 37.9 | 35.1 | 2.8 | 8 | % | |||||||||||||||||||||||||||
| Total | 876.9 | 713.0 | 163.9 | 23 | % | 858.8 | 641.5 | 217.3 | 34 | % | |||||||||||||||||||||||||||
| Crude oil, Badlands, MBbl/d | 101.6 | 122.2 | (20.6 | ) | (17 | %) | 105.6 | 118.9 | (13.3 | ) | (11 | %) | |||||||||||||||||||||||||
| Crude oil, Permian, MBbl/d | 27.2 | 30.3 | (3.1 | ) | (10 | %) | 27.4 | 29.9 | (2.5 | ) | (8 | %) | |||||||||||||||||||||||||
| Natural gas sales, BBtu/d (3) | 2,758.2 | 2,458.1 | 300.1 | 12 | % | 2,668.4 | 2,288.4 | 380.0 | 17 | % | |||||||||||||||||||||||||||
| NGL sales, MBbl/d (3) | 508.8 | 436.1 | 72.7 | 17 | % | 487.4 | 433.8 | 53.6 | 12 | % | |||||||||||||||||||||||||||
| Condensate sales, MBbl/d | 17.0 | 15.5 | 1.5 | 10 | % | 18.7 | 15.2 | 3.5 | 23 | % | |||||||||||||||||||||||||||
| Average realized prices (8): | |||||||||||||||||||||||||||||||||||||
| Natural gas, $/MMBtu | 2.03 | 6.71 | (4.68 | ) | (70 | %) | 1.97 | 5.71 | (3.74 | ) | (65 | %) | |||||||||||||||||||||||||
| NGL, $/gal | 0.46 | 0.77 | (0.31 | ) | (40 | %) | 0.46 | 0.82 | (0.36 | ) | (44 | %) | |||||||||||||||||||||||||
| Condensate, $/Bbl | 70.07 | 96.41 | (26.34 | ) | (27 | %) | 74.20 | 92.25 | (18.05 | ) | (20 | %) | |||||||||||||||||||||||||
(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 period and the denominator is the number of calendar days during the period.
(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 a
(5) Includes operations from the acquisition of certain assets in the Delaware Basin for the period effective August 1, 2022.
(6) Operations include facilities that are not wholly owned by the Company. SouthTX operating statistics include the impact of the acquisition of certain assets in South Texas for the period effective April 21, 2022.
(7) Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.
(8) Average realized prices, net of fees, include the effect of realized commodity hedge gain/loss attributable to the Company’s equity volumes. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator, net of fees.
The following table presents the realized commodity hedge gain (loss) attributable to the Company’s equity volumes that are included in the adjusted operating margin of the Gathering and Processing segment:
| Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 | |||||||||||||||||||||||
| (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) | 15.0 | $ | 0.62 | $ | 9.3 | 20.3 | $ | (3.58 | ) | $ | (72.7 | ) | ||||||||||||
| NGL (MMgal) | 166.0 | 0.04 | 7.2 | 194.9 | (0.25 | ) | (49.4 | ) | ||||||||||||||||
| Crude oil (MBbl) | 0.6 | (13.17 | ) | (7.9 | ) | 0.6 | (26.83 | ) | (16.1 | ) | ||||||||||||||
| $ | 8.6 | $ | (138.2 | ) | ||||||||||||||||||||
| Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | |||||||||||||||||||||||
| (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) | 50.0 | $ | 1.24 | $ | 62.2 | 54.5 | $ | (2.91 | ) | $ | (158.8 | ) | ||||||||||||
| NGL (MMgal) | 515.0 | 0.07 | 34.4 | 529.7 | (0.39 | ) | (205.2 | ) | ||||||||||||||||
| Crude oil (MBbl) | 1.8 | (7.17 | ) | (12.9 | ) | 1.6 | (38.31 | ) | (61.3 | ) | ||||||||||||||
| $ | 83.7 | $ | (425.3 | ) | ||||||||||||||||||||
(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, 2023 Compared to Three Months Ended September 30, 2022
The decrease in adjusted operating margin was due to lower commodity prices, partially offset by higher natural gas inlet volumes and higher fees predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to the acquisition of certain assets in the Delaware Basin during the third quarter of 2022, the addition of the Legacy I and Red Hills VI plants during the third quarter of 2022 and the Legacy II plant late in the first quarter of 2023, and continued strong producer activity. The natural gas inlet volumes in the Central region increased primarily due to increased producer activity during the third quarter of 2023.
The increase in operating expenses was predominantly due to the acquisition of certain assets in the Delaware Basin. Additionally, higher volumes in the Permian, the addition of the Legacy I, Red Hills VI, Legacy II and Midway plants, and inflation impacts resulted in increased costs.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022
The increase in adjusted operating margin was due to higher natural gas inlet volumes and higher fees resulting in increased margin predominantly in the Permian, partially offset by lower commodity prices. The increase in natural gas inlet volumes in the Permian was attributable to the acquisition of certain assets in the Delaware Basin during the third quarter of 2022, the addition of the Legacy I and Red Hills VI plants during the third quarter of 2022 and the Legacy II plant late in the first quarter of 2023, and continued strong producer activity. Natural gas inlet volumes in the Central region increased due to the acquisition of certain assets in South Texas during the second quarter of 2022 and increased producer activity.
The increase in operating expenses was predominantly due to the acquisition of certain assets in the Delaware Basin and South Texas. Additionally, higher volumes in the Permian, the addition of the Legacy I, Red Hills VI, Legacy II and Midway plants, and inflation impacts resulted in increased costs.
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 NGL Pipeline, 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 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, | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | 2023 | 2022 | 2023 vs. 2022 | ||||||||||||||||||||||||||||||
| (In millions, except operating statistics) | |||||||||||||||||||||||||||||||||||
| Operating margin | $ | 457.4 | $ | 340.2 | $ | 117.2 | 34 | % | $ | 1,394.4 | $ | 1,014.6 | $ | 379.8 | 37 | % | |||||||||||||||||||
| Operating expenses | 88.8 | 84.5 | 4.3 | 5 | % | 247.9 | 225.8 | 22.1 | 10 | % | |||||||||||||||||||||||||
| Adjusted operating margin | $ | 546.2 | $ | 424.7 | $ | 121.5 | 29 | % | $ | 1,642.3 | $ | 1,240.4 | $ | 401.9 | 32 | % | |||||||||||||||||||
| Operating statistics MBbl/d (1): | |||||||||||||||||||||||||||||||||||
| NGL pipeline transportation volumes (2) | 660.2 | 499.5 | 160.7 | 32 | % | 606.4 | 484.0 | 122.4 | 25 | % | |||||||||||||||||||||||||
| Fractionation volumes | 793.4 | 742.1 | 51.3 | 7 | % | 782.3 | 727.5 | 54.8 | 8 | % | |||||||||||||||||||||||||
| Export volumes (3) | 349.3 | 276.1 | 73.2 | 27 | % | 341.9 | 319.6 | 22.3 | 7 | % | |||||||||||||||||||||||||
| NGL sales | 997.9 | 825.0 | 172.9 | 21 | % | 984.1 | 868.1 | 116.0 | 13 | % | |||||||||||||||||||||||||
(1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
(2) Represents the total quantity of mixed NGLs that earn a transportation margin.
(3) Export volumes represent the quantity of NGL products delivered to third-party customers at the Company’s Galena Park Marine Terminal that are destined for international markets.
Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, higher LPG export margin and higher marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems and higher fees. LPG export margin increased due to higher volumes. Marketing margin increased due to greater optimization opportunities.
The increase in operating expenses was primarily due to higher compensation and benefits, and higher costs attributable to inflation.
Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, higher marketing margin and higher LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems and higher fees. Marketing margin increased due to greater optimization opportunities. LPG Export margin increased primarily due to higher volumes and lower fuel and power costs.
The increase in operating expenses was due to higher compensation and benefits, taxes, repairs and maintenance, and higher costs attributable to inflation.
Other
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Operating margin | $ | (33.5 | ) | $ | (112.2 | ) | $ | 78.7 | $ | 294.3 | $ | (294.9 | ) | $ | 589.2 | |||||||||
| Adjusted operating margin | $ | (33.5 | ) | $ | (112.2 | ) | $ | 78.7 | $ | 294.3 | $ | (294.9 | ) | $ | 589.2 | |||||||||
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 domestic midstream infrastructure assets and its operations are critical to the efficient, safe and reliable delivery of energy across the United States and increasingly to the world. The Company’s assets connect natural gas and NGLs to domestic and international markets with growing demand for cleaner fuels and feedstocks. 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.
Targa is a FORTUNE 500 company and is included in the S&P 500.
For more information, please visit the Company’s website at www.targaresources.com.
Non-GAAP Financial Measures
This press release includes the Company’s non-GAAP financial measures: adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment). The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures.
The Company utilizes non-GAAP measures to analyze the Company’s performance. Adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures 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 income and segment operating margin, 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 Operating Margin
The Company defines adjusted operating margin for the Company’s segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by the Company’s contract mix and commodity hedging program.
Gathering and Processing adjusted operating 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 settlements, fuel and transport and the Company’s equity volume hedge settlements.
Logistics and Transportation adjusted operating margin consists primarily of:
- service fees (including the pass-through of energy costs included in certain fee rates);
- system product gains and losses; and
- NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.
The adjusted operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.
Adjusted operating margin for the Company’s segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of the Company’s financial statements, including investors and commercial banks, to assess:
- the financial performance of the Company’s assets without regard to financing methods, capital structure or historical cost basis;
- the Company’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
- the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.
Management reviews adjusted operating margin and operating margin for the Company’s segments 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 the Company’s operating results. The reconciliation of the Company’s adjusted operating margin to the most directly comparable GAAP measure is presented under “Review of Segment Performance.”
Adjusted EBITDA
The Company defines adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp. 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 Adjusted Free Cash Flow
The Company defines distributable cash flow as adjusted EBITDA less cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). The Company defines adjusted 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 adjusted free cash flow are performance measures used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to assess the Company’s ability to generate cash earnings (after servicing the Company’s debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.
The following table presents a reconciliation of Net income (loss) attributable to Targa Resources Corp. to adjusted EBITDA, distributable cash flow and adjusted free cash flow for the periods indicated:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||
| (In millions) | |||||||||||||||
| Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow | |||||||||||||||
| Net income (loss) attributable to Targa Resources Corp. | $ | 220.0 | $ | 193.1 | $ | 1,046.3 | $ | 877.5 | |||||||
| Interest (income) expense, net | 175.1 | 125.8 | 509.8 | 300.5 | |||||||||||
| Income tax expense (benefit) | 53.9 | 12.0 | 260.7 | 122.0 | |||||||||||
| Depreciation and amortization expense | 331.3 | 287.2 | 988.2 | 766.2 | |||||||||||
| (Gain) loss on sale or disposition of assets | (0.9 | ) | (6.5 | ) | (3.9 | ) | (8.1 | ) | |||||||
| Write-down of assets | 3.4 | 2.7 | 6.0 | 3.7 | |||||||||||
| (Gain) loss from financing activities (1) | — | — | — | 49.6 | |||||||||||
| (Gain) loss from sale of equity method investment | — | — | — | (435.9 | ) | ||||||||||
| Transaction costs related to business acquisition (2) | — | 20.3 | — | 20.3 | |||||||||||
| Equity (earnings) loss | (3.0 | ) | (1.7 | ) | (6.2 | ) | (8.7 | ) | |||||||
| Distributions from unconsolidated affiliates and preferred partner interests, net | 5.3 | 2.4 | 14.1 | 21.7 | |||||||||||
| Compensation on equity grants | 15.7 | 14.4 | 45.7 | 41.8 | |||||||||||
| Risk management activities | 33.5 | 112.2 | (294.3 | ) | 295.0 | ||||||||||
| Noncontrolling interests adjustments (3) | (1.0 | ) | 6.7 | (3.2 | ) | 15.2 | |||||||||
| Litigation expense (4) | 6.9 | — | 6.9 | — | |||||||||||
| Adjusted EBITDA | $ | 840.2 | $ | 768.6 | $ | 2,570.1 | $ | 2,060.8 | |||||||
| Interest expense on debt obligations (5) | (172.1 | ) | (123.0 | ) | (500.9 | ) | (305.2 | ) | |||||||
| Maintenance capital expenditures, net (6) | (65.0 | ) | (49.4 | ) | (153.0 | ) | (126.8 | ) | |||||||
| Cash taxes | (0.9 | ) | (1.3 | ) | (8.6 | ) | (5.6 | ) | |||||||
| Distributable Cash Flow | $ | 602.2 | $ | 594.9 | $ | 1,907.6 | $ | 1,623.2 | |||||||
| Growth capital expenditures, net (6) | (593.6 | ) | (304.1 | ) | (1,588.5 | ) | (624.8 | ) | |||||||
| Adjusted Free Cash Flow | $ | 8.6 | $ | 290.8 | $ | 319.1 | $ | 998.4 | |||||||
(1) Gains or losses on debt repurchases or early debt extinguishments.
(2) Includes financial advisory, legal and other professional fees, and other one-time transaction costs.
(3) Noncontrolling interest portion of depreciation and amortization expense.
(4) Litigation expense includes charges related to litigation resulting from the major winter storm in February 2021 that the Company considers outside the ordinary course of its business and/or not reflective of its ongoing core operations. The Company may incur such charges from time to time, and the Company believes it is useful to exclude such charges because it does not consider them reflective of its ongoing core operations and because of the generally singular nature of the claims underlying such litigation.
(5) Excludes amortization of debt issuance costs.
(6) Represents capital expenditures, net of contributions from noncontrolling interests and includes net contributions to investments in unconsolidated affiliates.
The following table presents a reconciliation of estimated net income of the Company to estimated adjusted EBITDA for 2023:
| 2023E | |||
| (In millions) | |||
| Reconciliation of Estimated Net Income Attributable to Targa Resources Corp. to | |||
| Estimated Adjusted EBITDA | |||
| Net income attributable to Targa Resources Corp. | $ | 1,403.0 | |
| Interest expense, net | 700.0 | ||
| Income tax expense | 400.0 | ||
| Depreciation and amortization expense | 1,320.0 | ||
| Equity earnings | (10.0 | ) | |
| Distributions from unconsolidated affiliates | 25.0 | ||
| Compensation on equity grants | 60.0 | ||
| Risk management and other (1) | (293.0 | ) | |
| Noncontrolling interests adjustments (2) | (5.0 | ) | |
| Estimated Adjusted EBITDA | $ | 3,600.0 | |
(1) Other includes litigation charges related to litigation resulting from the major winter storm in February 2021 that the Company considers outside the ordinary course of its business and/or not reflective of its ongoing core operations. The Company may incur such charges from time to time, and the Company believes it is useful to exclude such charges because it does not consider them reflective of its ongoing core operations and because of the generally singular nature of the claims underlying such litigation.
(2) Noncontrolling interest portion of depreciation and amortization expense.
Regulation FD Disclosures
The Company uses any of the following to comply with its disclosure obligations under Regulation FD: press releases, SEC filings, public conference calls, or our website. The Company routinely posts important information on its website at www.targaresources.com, including information that may be deemed to be material. The Company encourages investors and others interested in the company to monitor these distribution channels for material disclosures.
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, including statements regarding our projected financial performance, capital spending and payment of future dividends. 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 or any other public health crises, commodity price volatility due to ongoing or new global conflicts, actions by the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC oil producing countries, the impact of disruptions in the bank and capital markets, including those resulting from lack of access to liquidity for banking and financial services firms, the timing and success of business development efforts and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Company’s filings with the Securities and Exchange Commission, including its most recent Annual Report on Form 10-K, and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
Contact the Company’s investor relations department by email at InvestorRelations@targaresources.com or by phone at (713) 584-1133.
Sanjay Lad
Vice President, Finance & Investor Relations
Jennifer Kneale
Chief Financial Officer
FAQ
What is Targa Resources Corp.'s net income for Q3 2023?
What is Targa Resources Corp.'s adjusted EBITDA for Q3?
What expansions did Targa complete in Q3 2023?
How much common stock did Targa repurchase in Q3?
What is Targa's 2023 adjusted EBITDA estimate?
What is Targa's expected annual common dividend per share in 2024?
How do Targa's Permian inlet gas volumes in Q4 compare to Q3?
