Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or
“Targa”) today reported second quarter 2022 results.
Second Quarter 2022 Financial
Results
Second quarter 2022 net income attributable to
Targa Resources Corp. was $596.4 million (including a $435.9
million gain on the sale of an equity method investment
attributable to the sale of Targa GCX Pipeline LLC) compared to
$56.2 million for the second quarter of 2021.
The Company reported adjusted earnings before
interest, income taxes, depreciation and amortization, and other
non-cash items (“adjusted EBITDA”) of $666.4 million for the second
quarter of 2022 compared to $460.0 million for the second
quarter of 2021.
On July 14, 2022, Targa declared a quarterly
dividend of $0.35 per share of its common stock for the second
quarter of 2022, or $1.40 per share on an annualized basis. Total
cash dividends of approximately $79 million will be paid on
August 15, 2022 on all outstanding shares of common stock
to holders of record as of the close of business on July 29,
2022.
The Company reported distributable cash flow and
adjusted free cash flow for the second quarter of 2022 of $533.4
million and $334.1 million, respectively.
Second Quarter 2022 - Sequential Quarter over Quarter
Commentary
Targa reported second quarter 2022 adjusted
EBITDA of $666.4 million, representing a 6 percent increase when
compared to the first quarter of 2022. The sequential increase in
adjusted EBITDA was primarily attributable to higher realized
commodity prices and higher Permian volumes across Targa’s
Gathering and Processing (“G&P”) and Logistics and
Transportation (“L&T”) systems, partially offset by lower
marketing margin and higher operating expenses. Higher sequential
adjusted operating margin in the G&P segment was driven by
higher realized commodity prices and natural gas inlet volumes
across Permian and Central. Permian natural gas inlet volumes
averaged a record 3.1 billion cubic feet per day (“Bcf/d”) in the
second quarter. In the L&T segment, the sequential decrease in
segment adjusted operating margin was attributable to lower
marketing and LPG export margin, offset by higher pipeline
transportation and fractionation volumes. Marketing margin was
lower due to fewer optimization opportunities and seasonality in
the Company’s wholesale propane business while the decrease in LPG
export margin was driven by higher fuel and power costs. NGL
pipeline transportation and fractionation volumes achieved record
levels during the second quarter primarily due to higher supply
volumes from Targa’s Permian G&P systems and third parties.
Higher operating expenses were attributable to increased activity
levels and the acquisition of certain assets in South Texas in the
second quarter, which resulted in increased labor costs, materials
and chemicals.
Capitalization and Liquidity
The Company’s total consolidated debt as of June
30, 2022 was $7,460.8 million, net of $51.4 million of debt
issuance costs and $6.4 million of unamortized discount, with
$5,034.4 million of outstanding Targa Resources Partners LP’s (the
“Partnership”) senior notes, $1.5 billion of outstanding TRGP
senior notes, $550.0 million outstanding under the Company’s $2.75
billion senior revolving credit facility (the “TRGP Revolver”),
$400.0 million outstanding under the Partnership’s accounts
receivable securitization facility (the “Securitization Facility”),
and $34.2 million of finance lease liabilities.
Total consolidated liquidity as of June 30, 2022 was
approximately $2.3 billion, including $2.2 billion available under
the TRGP Revolver and $154.0 million of cash.
Acquisition and Financing Update
In July 2022, Targa completed the acquisition of
Lucid Energy Delaware, LLC (“Lucid”) for $3.55 billion. Lucid
provides natural gas gathering, treating, and processing services
in the Delaware Basin, and owns and operates 1,050 miles of natural
gas pipelines and approximately 1.4 Bcf/d of cryogenic natural gas
processing capacity in service or under construction located
primarily in Eddy and Lea counties of New Mexico. Lucid’s Delaware
Basin assets are integrated into Targa’s Permian Delaware
operations.
Targa funded the acquisition with i) $1.5
billion in proceeds drawn under its 3-year term loan facility; ii)
$1.25 billion from the Company’s underwritten public offering of
senior notes that closed in July 2022; and iii) $800 million drawn
on its $2.75 billion revolving credit facility.
In July 2022, the Company established an
unsecured commercial paper note program (the “Commercial Paper
Program”). Under the terms of the Commercial Paper Program, Targa
may issue, from time to time, unsecured commercial paper notes with
varying maturities of less than one year. Amounts available under
the Commercial Paper Program may be issued, repaid and re-issued
from time to time, with the maximum aggregate face or principal
amount outstanding at any one time not to exceed $2.75 billion.
Common Share Repurchases
During the second quarter of 2022, Targa
repurchased 1,121,925 shares of its common stock at a weighted
average price of $66.07 for a total net cost of $74.1 million. From
July 1 through July 29, 2022, Targa repurchased 512,336 shares of
its common stock at a weighted average price of $58.57 for a total
net cost of $30.0 million. There was $214.7 million remaining under
the Company’s $500 million common share repurchase program as of
July 29, 2022.
Growth Projects Update
Construction continues on Targa’s 275 million
cubic feet per day (“MMcf/d”) Legacy I and Legacy II plants in
Permian Midland and its 230 MMcf/d Red Hills VI plant and 275
MMcf/d Midway plant in Permian Delaware. Targa expects to complete
Legacy I ahead of schedule and given the plant will be highly
utilized when it begins full operations in late third quarter 2022,
Targa announced today its plans to construct a new 275 MMcf/d plant
in the Permian Midland (the “Greenwood plant”), which is expected
to begin operations late in the fourth quarter of 2023.
To handle continued supply growth anticipated
from Targa’s Permian G&P systems and third parties, Targa also
announced today its plans to construct a new 120 thousand barrels
per day (“MBbl/d”) fractionation train in Mont Belvieu, Texas
(“Train 9”). Train 9 is expected to begin operations in the second
quarter of 2024.
2022 Updated Financial Estimates
For full year 2022, Targa is increasing its
estimated adjusted EBITDA range to between $2.85 billion and $2.95
billion to account for a partial year contribution from its
recently completed Delaware Basin acquisition. Targa’s updated full
year 2022 adjusted EBITDA outlook assumes NGL composite barrel
prices average $1.05 per gallon, crude oil prices average $100 per
barrel, and Waha natural gas prices average $6.00 per million
British Thermal Units (“MMBtu”) for the second half of 2022.
Targa now estimates net growth capital
expenditures for 2022 to be between $1.0 billion and $1.1 billion
to account for today’s announcements of construction of the new
Greenwood plant in Permian Midland and Train 9 in Mont Belvieu,
coupled with incremental gathering and related infrastructure spend
to support growth across the recently acquired Delaware Basin
assets. Targa’s estimate for 2022 net maintenance capital
expenditures remains unchanged at approximately $150 million.
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 August 4, 2022 to discuss its second 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/f6xgoadz. A webcast replay will
be available at the link above approximately two hours after the
conclusion of the event.
Targa Resources Corp. – Consolidated
Financial Results of Operations
|
Three Months Ended June 30, |
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
5,624.2 |
|
|
$ |
3,091.6 |
|
|
$ |
2,532.6 |
|
|
|
82 |
% |
|
$ |
10,190.3 |
|
|
$ |
6,459.3 |
|
|
$ |
3,731.0 |
|
|
58 |
% |
Fees from midstream services |
|
431.6 |
|
|
|
324.3 |
|
|
|
107.3 |
|
|
|
33 |
% |
|
|
824.6 |
|
|
|
589.4 |
|
|
|
235.2 |
|
|
40 |
% |
Total revenues |
|
6,055.8 |
|
|
|
3,415.9 |
|
|
|
2,639.9 |
|
|
|
77 |
% |
|
|
11,014.9 |
|
|
|
7,048.7 |
|
|
|
3,966.2 |
|
|
56 |
% |
Product purchases and
fuel |
|
5,047.3 |
|
|
|
2,709.0 |
|
|
|
2,338.3 |
|
|
|
86 |
% |
|
|
9,251.5 |
|
|
|
5,545.3 |
|
|
|
3,706.2 |
|
|
67 |
% |
Operating expenses |
|
215.8 |
|
|
|
184.8 |
|
|
|
31.0 |
|
|
|
17 |
% |
|
|
399.3 |
|
|
|
355.8 |
|
|
|
43.5 |
|
|
12 |
% |
Depreciation and amortization
expense |
|
269.9 |
|
|
|
211.9 |
|
|
|
58.0 |
|
|
|
27 |
% |
|
|
479.0 |
|
|
|
428.0 |
|
|
|
51.0 |
|
|
12 |
% |
General and administrative
expense |
|
71.0 |
|
|
|
63.7 |
|
|
|
7.3 |
|
|
|
11 |
% |
|
|
138.0 |
|
|
|
125.1 |
|
|
|
12.9 |
|
|
10 |
% |
Other operating (income)
expense |
|
(0.1 |
) |
|
|
0.7 |
|
|
|
(0.8 |
) |
|
|
(114 |
%) |
|
|
(0.6 |
) |
|
|
4.6 |
|
|
|
(5.2 |
) |
|
(113 |
%) |
Income (loss) from
operations |
|
451.9 |
|
|
|
245.8 |
|
|
|
206.1 |
|
|
|
84 |
% |
|
|
747.7 |
|
|
|
589.9 |
|
|
|
157.8 |
|
|
27 |
% |
Interest expense, net |
|
(81.2 |
) |
|
|
(94.8 |
) |
|
|
13.6 |
|
|
|
14 |
% |
|
|
(174.7 |
) |
|
|
(193.2 |
) |
|
|
18.5 |
|
|
10 |
% |
Equity earnings (loss) |
|
1.4 |
|
|
|
12.8 |
|
|
|
(11.4 |
) |
|
|
(89 |
%) |
|
|
7.0 |
|
|
|
24.6 |
|
|
|
(17.6 |
) |
|
(72 |
%) |
Gain (loss) from financing
activities |
|
(33.8 |
) |
|
|
(1.9 |
) |
|
|
(31.9 |
) |
|
NM |
|
|
|
(49.6 |
) |
|
|
(16.6 |
) |
|
|
(33.0 |
) |
|
199 |
% |
Gain (loss) from sale of
equity method investment |
|
435.9 |
|
|
|
— |
|
|
|
435.9 |
|
|
|
100 |
% |
|
|
435.9 |
|
|
|
— |
|
|
|
435.9 |
|
|
100 |
% |
Other, net |
|
0.5 |
|
|
|
0.1 |
|
|
|
0.4 |
|
|
NM |
|
|
|
— |
|
|
|
0.2 |
|
|
|
(0.2 |
) |
|
(100 |
%) |
Income tax (expense)
benefit |
|
(87.1 |
) |
|
|
(6.6 |
) |
|
|
(80.5 |
) |
|
NM |
|
|
|
(110.1 |
) |
|
|
(21.6 |
) |
|
|
(88.5 |
) |
NM |
|
Net income (loss) |
|
687.6 |
|
|
|
155.4 |
|
|
|
532.2 |
|
|
NM |
|
|
|
856.2 |
|
|
|
383.3 |
|
|
|
472.9 |
|
|
123 |
% |
Less: Net income (loss)
attributable to noncontrolling interests |
|
91.2 |
|
|
|
99.2 |
|
|
|
(8.0 |
) |
|
|
(8 |
%) |
|
|
171.8 |
|
|
|
180.7 |
|
|
|
(8.9 |
) |
|
(5 |
%) |
Net income (loss) attributable
to Targa Resources Corp. |
|
596.4 |
|
|
|
56.2 |
|
|
|
540.2 |
|
|
NM |
|
|
|
684.4 |
|
|
|
202.6 |
|
|
|
481.8 |
|
|
238 |
% |
Premium on repurchase of
noncontrolling interests, net of tax |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
53.1 |
|
|
|
— |
|
|
|
53.1 |
|
|
100 |
% |
Dividends on Series A
Preferred Stock |
|
8.2 |
|
|
|
21.8 |
|
|
|
(13.6 |
) |
|
|
(62 |
%) |
|
|
30.0 |
|
|
|
43.7 |
|
|
|
(13.7 |
) |
|
(31 |
%) |
Deemed dividends on Series A
Preferred Stock |
|
215.5 |
|
|
|
— |
|
|
|
215.5 |
|
|
|
100 |
% |
|
|
215.5 |
|
|
|
— |
|
|
|
215.5 |
|
|
100 |
% |
Net income (loss) attributable
to common shareholders |
$ |
372.7 |
|
|
$ |
34.4 |
|
|
$ |
338.3 |
|
|
NM |
|
|
$ |
385.8 |
|
|
$ |
158.9 |
|
|
$ |
226.9 |
|
|
143 |
% |
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
666.4 |
|
|
$ |
460.0 |
|
|
$ |
206.4 |
|
|
|
45 |
% |
|
$ |
1,292.1 |
|
|
$ |
975.7 |
|
|
$ |
316.4 |
|
|
32 |
% |
Distributable cash flow
(1) |
|
533.4 |
|
|
|
339.5 |
|
|
|
193.9 |
|
|
|
57 |
% |
|
|
1,028.2 |
|
|
|
737.0 |
|
|
|
291.2 |
|
|
40 |
% |
Adjusted free cash flow
(1) |
|
334.1 |
|
|
|
256.1 |
|
|
|
78.0 |
|
|
|
30 |
% |
|
|
707.5 |
|
|
|
592.6 |
|
|
|
114.9 |
|
|
19 |
% |
________________
(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
or material.
Three Months Ended June 30, 2022 Compared to Three Months
Ended June 30, 2021
The increase in commodity sales reflects higher
NGL, natural gas and condensate prices ($2,506.1 million) and
higher NGL and natural gas volumes ($98.0 million), partially
offset by the unfavorable impact of hedges ($66.5 million).
The increase in fees from midstream services is
primarily due to higher gas gathering and processing fees, and
transportation and fractionation fees.
The increase in product purchases and fuel
reflects higher NGL, natural gas and condensate prices and higher
NGL and natural gas volumes.
The increase in operating expenses was due to
higher labor and maintenance costs primarily due to increased
activity, system expansions 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 impact of system expansions on the
Company’s asset base and the shortening of the depreciable lives of
certain assets that have been, or will be, idled.
The increase in general and administrative
expense is primarily due to higher compensation and benefits,
insurance costs and professional fees.
The decrease in interest expense, net is
primarily due to higher non-cash interest income related to a
decrease in the mandatorily redeemable preferred interest
liability.
The decrease in equity earnings is primarily due
to the sale of Targa GCX Pipeline LLC to a third party (the “GCX
Sale”) and lower earnings from the Company’s investment in Little
Missouri 4 LLC, partially offset by lower losses from the Company’s
investments in T2 Eagle Ford Gathering Company L.L.C., Gulf Coast
Fractionators and T2 LaSalle Gathering Company L.L.C.
During 2022, the Partnership redeemed the 5.875%
Senior Notes due 2026 (the “5.875% Notes”), resulting in a net loss
from financing activities. During 2021, the Partnership redeemed
the 4.250% Senior Notes due 2023 (the “4.250% Notes”), resulting in
a net loss from financing activities.
During 2022, the Company completed the GCX Sale
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, partially offset by a
larger release of the valuation allowance in 2022 compared to
2021.
During 2022, Targa redeemed in full all of the
Company’s issued and outstanding shares of Series A Preferred Stock
(“Series A Preferred”). The difference between the consideration
paid of $973.4 million (including unpaid dividends of $8.2 million)
and the net carrying value of the shares redeemed was $223.7
million, of which $215.5 million was recorded as deemed dividends.
Dividends on Series A Preferred decreased as a result of the
redemption.
Six Months Ended June 30, 2022 Compared to Six Months Ended June
30, 2021
The increase in commodity sales reflects higher
NGL, natural gas and condensate prices ($3,890.3 million) and
higher NGL and natural gas volumes ($100.0 million), partially
offset by the unfavorable impact of hedges ($254.5 million).
The increase in fees from midstream services is
primarily due to higher gas gathering and processing fees,
transportation and fractionation fees and export volumes.
The increase in product purchases and fuel
reflects higher NGL, natural gas and condensate prices and higher
NGL and natural gas volumes.
The increase in operating expenses was due to
higher labor and maintenance costs primarily due to increased
activity, system expansions and inflation, partially offset by
lower taxes and the impact of a major winter storm that affected
regions across Texas, New Mexico, Oklahoma and Louisiana during the
first quarter of 2021.
See “—Review of Segment Performance” for
additional information on a segment basis.
The increase in depreciation and amortization
expense is primarily due to system expansions on the Company’s
asset base and the shortening of the depreciable lives of certain
assets that have been, or will be, idled, partially offset by a
lower depreciable base associated with assets that were impaired
during the fourth quarter of 2021.
The increase in general and administrative
expense is primarily due to higher compensation and benefits,
insurance costs and professional fees.
The decrease in interest expense, net is
primarily due to higher non-cash interest income related to a
decrease in the mandatorily redeemable preferred interest
liability, lower interest rates on debt and higher capitalized
interest.
The decrease in equity earnings is primarily due
to the GCX Sale and lower earnings from the Company’s investment in
Little Missouri 4 LLC, partially offset by lower losses from the
Company’s investments in T2 Eagle Ford Gathering Company L.L.C.,
Gulf Coast Fractionators and T2 LaSalle Gathering Company
L.L.C.
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 the 5.375% Senior Notes due 2027 and 5.875%
Notes. These transactions resulted in a net loss from financing
activities. During 2021, the Partnership redeemed its 5.125% Senior
Notes due 2025 and the 4.250% Notes. In addition, Targa Pipeline
Partners LP redeemed its 4.750% Senior Notes due 2021 and the
5.875% Senior Notes due 2023. These transactions resulted in a net
loss from financing activities.
During 2022, the Company completed the GCX Sale
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, partially offset by a
larger release of the valuation allowance in 2022 compared to
2021.
During 2022, Targa redeemed in full all of the
Company’s issued and outstanding shares of Series A Preferred. The
difference between the consideration paid of $973.4 million
(including unpaid dividends of $8.2 million) and the net carrying
value of the shares redeemed was $223.7 million, of which $215.5
million was recorded as deemed dividends. Dividends on Series A
Preferred decreased as a result of the redemption.
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 June 30, |
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
|
(In millions, except operating statistics and price
amounts) |
|
Operating margin |
$ |
|
474.7 |
|
|
$ |
|
301.2 |
|
|
$ |
|
173.5 |
|
|
|
58 |
% |
|
$ |
|
872.3 |
|
|
$ |
|
576.6 |
|
|
$ |
|
295.7 |
|
|
|
51 |
% |
Operating expenses |
|
|
141.4 |
|
|
|
|
115.1 |
|
|
|
|
26.3 |
|
|
|
23 |
% |
|
|
|
258.0 |
|
|
|
|
220.5 |
|
|
|
|
37.5 |
|
|
|
17 |
% |
Adjusted operating margin |
$ |
|
616.1 |
|
|
$ |
|
416.3 |
|
|
$ |
|
199.8 |
|
|
|
48 |
% |
|
$ |
|
1,130.3 |
|
|
$ |
|
797.1 |
|
|
$ |
|
333.2 |
|
|
|
42 |
% |
Operating statistics
(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
2,132.0 |
|
|
|
|
1,929.7 |
|
|
|
|
202.3 |
|
|
|
10 |
% |
|
|
|
2,103.7 |
|
|
|
|
1,794.7 |
|
|
|
|
309.0 |
|
|
|
17 |
% |
Permian Delaware |
|
|
993.3 |
|
|
|
|
836.2 |
|
|
|
|
157.1 |
|
|
|
19 |
% |
|
|
|
985.1 |
|
|
|
|
787.2 |
|
|
|
|
197.9 |
|
|
|
25 |
% |
Total Permian |
|
|
3,125.3 |
|
|
|
|
2,765.9 |
|
|
|
|
359.4 |
|
|
|
|
|
|
|
|
3,088.8 |
|
|
|
|
2,581.9 |
|
|
|
|
506.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
|
271.2 |
|
|
|
|
194.9 |
|
|
|
|
76.3 |
|
|
|
39 |
% |
|
|
|
216.9 |
|
|
|
|
185.7 |
|
|
|
|
31.2 |
|
|
|
17 |
% |
North Texas |
|
|
175.3 |
|
|
|
|
181.4 |
|
|
|
|
(6.1 |
) |
|
|
(3 |
%) |
|
|
|
175.3 |
|
|
|
|
178.4 |
|
|
|
|
(3.1 |
) |
|
|
(2 |
%) |
SouthOK (5) |
|
|
460.4 |
|
|
|
|
411.4 |
|
|
|
|
49.0 |
|
|
|
12 |
% |
|
|
|
434.0 |
|
|
|
|
393.4 |
|
|
|
|
40.6 |
|
|
|
10 |
% |
WestOK |
|
|
212.0 |
|
|
|
|
212.5 |
|
|
|
|
(0.5 |
) |
|
|
— |
|
|
|
|
207.2 |
|
|
|
|
207.6 |
|
|
|
|
(0.4 |
) |
|
|
— |
|
Total Central |
|
|
1,118.9 |
|
|
|
|
1,000.2 |
|
|
|
|
118.7 |
|
|
|
|
|
|
|
|
1,033.4 |
|
|
|
|
965.1 |
|
|
|
|
68.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (5) (6) |
|
|
129.4 |
|
|
|
|
143.4 |
|
|
|
|
(14.0 |
) |
|
|
(10 |
%) |
|
|
|
127.2 |
|
|
|
|
139.1 |
|
|
|
|
(11.9 |
) |
|
|
(9 |
%) |
Total Field |
|
|
4,373.6 |
|
|
|
|
3,909.5 |
|
|
|
|
464.1 |
|
|
|
|
|
|
|
|
4,249.4 |
|
|
|
|
3,686.1 |
|
|
|
|
563.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
553.6 |
|
|
|
|
616.6 |
|
|
|
|
(63.0 |
) |
|
|
(10 |
%) |
|
|
|
577.7 |
|
|
|
|
634.5 |
|
|
|
|
(56.8 |
) |
|
|
(9 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
4,927.2 |
|
|
|
|
4,526.1 |
|
|
|
|
401.1 |
|
|
|
9 |
% |
|
|
|
4,827.1 |
|
|
|
|
4,320.6 |
|
|
|
|
506.5 |
|
|
|
12 |
% |
NGL production, MBbl/d
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
310.6 |
|
|
|
|
279.4 |
|
|
|
|
31.2 |
|
|
|
11 |
% |
|
|
|
305.7 |
|
|
|
|
258.4 |
|
|
|
|
47.3 |
|
|
|
18 |
% |
Permian Delaware |
|
|
135.8 |
|
|
|
|
111.7 |
|
|
|
|
24.1 |
|
|
|
22 |
% |
|
|
|
132.8 |
|
|
|
|
104.1 |
|
|
|
|
28.7 |
|
|
|
28 |
% |
Total Permian |
|
|
446.4 |
|
|
|
|
391.1 |
|
|
|
|
55.3 |
|
|
|
|
|
|
|
|
438.5 |
|
|
|
|
362.5 |
|
|
|
|
76.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX (5) |
|
|
33.5 |
|
|
|
|
25.8 |
|
|
|
|
7.7 |
|
|
|
30 |
% |
|
|
|
26.9 |
|
|
|
|
21.7 |
|
|
|
|
5.2 |
|
|
|
24 |
% |
North Texas |
|
|
19.6 |
|
|
|
|
20.4 |
|
|
|
|
(0.8 |
) |
|
|
(4 |
%) |
|
|
|
19.4 |
|
|
|
|
19.8 |
|
|
|
|
(0.4 |
) |
|
|
(2 |
%) |
SouthOK (5) |
|
|
55.8 |
|
|
|
|
50.4 |
|
|
|
|
5.4 |
|
|
|
11 |
% |
|
|
|
53.1 |
|
|
|
|
47.1 |
|
|
|
|
6.0 |
|
|
|
13 |
% |
WestOK |
|
|
16.6 |
|
|
|
|
17.0 |
|
|
|
|
(0.4 |
) |
|
|
(2 |
%) |
|
|
|
15.8 |
|
|
|
|
16.5 |
|
|
|
|
(0.7 |
) |
|
|
(4 |
%) |
Total Central |
|
|
125.5 |
|
|
|
|
113.6 |
|
|
|
|
11.9 |
|
|
|
|
|
|
|
|
115.2 |
|
|
|
|
105.1 |
|
|
|
|
10.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (5) |
|
|
14.7 |
|
|
|
|
16.2 |
|
|
|
|
(1.5 |
) |
|
|
(9 |
%) |
|
|
|
14.7 |
|
|
|
|
15.9 |
|
|
|
|
(1.2 |
) |
|
|
(8 |
%) |
Total Field |
|
|
586.6 |
|
|
|
|
520.9 |
|
|
|
|
65.7 |
|
|
|
|
|
|
|
|
568.4 |
|
|
|
|
483.5 |
|
|
|
|
84.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
36.7 |
|
|
|
|
35.7 |
|
|
|
|
1.0 |
|
|
|
3 |
% |
|
|
|
36.9 |
|
|
|
|
37.8 |
|
|
|
|
(0.9 |
) |
|
|
(2 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
623.3 |
|
|
|
|
556.6 |
|
|
|
|
66.7 |
|
|
|
12 |
% |
|
|
|
605.3 |
|
|
|
|
521.3 |
|
|
|
|
84.0 |
|
|
|
16 |
% |
Crude oil, Badlands,
MBbl/d |
|
|
111.8 |
|
|
|
|
138.9 |
|
|
|
|
(27.1 |
) |
|
|
(20 |
%) |
|
|
|
117.2 |
|
|
|
|
137.6 |
|
|
|
|
(20.4 |
) |
|
|
(15 |
%) |
Crude oil, Permian,
MBbl/d |
|
|
28.8 |
|
|
|
|
36.7 |
|
|
|
|
(7.9 |
) |
|
|
(22 |
%) |
|
|
|
29.7 |
|
|
|
|
35.8 |
|
|
|
|
(6.1 |
) |
|
|
(17 |
%) |
Natural gas sales, BBtu/d
(3) |
|
|
2,277.1 |
|
|
|
|
2,207.5 |
|
|
|
|
69.6 |
|
|
|
3 |
% |
|
|
|
2,202.1 |
|
|
|
|
2,082.4 |
|
|
|
|
119.7 |
|
|
|
6 |
% |
NGL sales, MBbl/d (3) |
|
|
440.4 |
|
|
|
|
391.9 |
|
|
|
|
48.5 |
|
|
|
12 |
% |
|
|
|
432.7 |
|
|
|
|
370.5 |
|
|
|
|
62.2 |
|
|
|
17 |
% |
Condensate sales, MBbl/d |
|
|
15.7 |
|
|
|
|
15.2 |
|
|
|
|
0.5 |
|
|
|
3 |
% |
|
|
|
15.0 |
|
|
|
|
15.2 |
|
|
|
|
(0.2 |
) |
|
|
(1 |
%) |
Average realized
prices - inclusive of hedges (7): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
|
6.12 |
|
|
|
|
2.45 |
|
|
|
|
3.67 |
|
|
|
150 |
% |
|
|
|
5.15 |
|
|
|
|
2.48 |
|
|
|
|
2.67 |
|
|
|
108 |
% |
NGL, $/gal |
|
|
0.89 |
|
|
|
|
0.51 |
|
|
|
|
0.38 |
|
|
|
75 |
% |
|
|
|
0.84 |
|
|
|
|
0.49 |
|
|
|
|
0.35 |
|
|
|
71 |
% |
Condensate, $/Bbl |
|
|
103.10 |
|
|
|
|
59.06 |
|
|
|
|
44.04 |
|
|
|
75 |
% |
|
|
|
90.06 |
|
|
|
|
52.97 |
|
|
|
|
37.09 |
|
|
|
70 |
% |
____________________
(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 72.8% undivided
interest, 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) Operations include facilities
that are not wholly owned by the Company.(6)
Badlands natural gas inlet represents the total wellhead
volume and includes the Targa volumes processed at the Little
Missouri 4 plant.(7) Average realized prices 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.
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 June 30, 2022 |
|
|
Three Months Ended June 30, 2021 |
|
|
|
(In millions, except volumetric data and price
amounts) |
|
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
|
|
16.7 |
|
|
$ |
(3.29 |
) |
|
$ |
(54.9 |
) |
|
|
18.1 |
|
|
$ |
(0.71 |
) |
|
$ |
(12.8 |
) |
NGL (MMgal) |
|
|
164.4 |
|
|
|
(0.47 |
) |
|
|
(77.9 |
) |
|
|
133.8 |
|
|
|
(0.18 |
) |
|
|
(24.4 |
) |
Crude oil (MBbl) |
|
|
0.5 |
|
|
|
(51.00 |
) |
|
|
(25.5 |
) |
|
|
0.5 |
|
|
|
(12.69 |
) |
|
|
(6.7 |
) |
|
|
|
|
|
|
|
|
|
|
$ |
(158.3 |
) |
|
|
|
|
|
|
|
|
|
$ |
(43.9 |
) |
_____________________
(1) The price spread is
the differential between the contracted derivative instrument
pricing and the price of the corresponding settled commodity
transaction.
|
|
Six Months Ended June 30, 2022 |
|
|
Six Months Ended June 30, 2021 |
|
|
|
(In millions, except volumetric data and price
amounts) |
|
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
Natural gas (BBtu) |
|
|
34.2 |
|
|
$ |
(2.52 |
) |
|
$ |
(86.1 |
) |
|
|
36.1 |
|
|
$ |
(0.72 |
) |
|
$ |
(26.0 |
) |
NGL (MMgal) |
|
|
334.8 |
|
|
|
(0.47 |
) |
|
|
(155.8 |
) |
|
|
269.6 |
|
|
|
(0.17 |
) |
|
|
(46.9 |
) |
Crude oil (MBbl) |
|
|
1.0 |
|
|
|
(45.20 |
) |
|
|
(45.2 |
) |
|
|
1.1 |
|
|
|
(8.32 |
) |
|
|
(8.9 |
) |
|
|
|
|
|
|
|
|
|
|
$ |
(287.1 |
) |
|
|
|
|
|
|
|
|
|
$ |
(81.8 |
) |
____________________
(1) The price spread is
the differential between the contracted derivative instrument
pricing and the price of the corresponding settled commodity
transaction.
Three Months Ended June 30, 2022 Compared
to Three Months Ended June 30, 2021
The increase in adjusted operating margin was
due to higher realized commodity prices, natural gas inlet volumes
and fees resulting in increased margin predominantly in the
Permian. The increase in natural gas inlet volumes in the Permian
was attributable to increased producer activity and the addition of
a new 200 MMcf/d cryogenic natural gas processing plant in Permian
Midland (the “Heim Plant”) during the third quarter of 2021.
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 decrease in
volumes in the Badlands was attributable to the impacts of winter
weather, while lower volumes in the Coastal region were due to
continued low producer activity.
The increase in operating expenses was due to
higher activity levels in the Permian, the addition of the Heim
Plant in the third quarter of 2021, the acquisition of certain
assets in South Texas in the second quarter of 2022 and inflation
impacts, which resulted in increased labor costs, materials and
chemicals.
Six Months Ended June 30, 2022 Compared to Six
Months Ended June 30, 2021
The increase in adjusted operating margin was
due to higher realized commodity prices, natural gas inlet volumes
and fees resulting in increased margin predominantly in the
Permian. The increase in natural gas inlet volumes in the Permian
was attributable to increased producer activity and the addition of
the Heim Plant during the third quarter of 2021. 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 decrease in volumes in the
Badlands was attributable to the impacts of winter weather, while
lower volumes in the Coastal region were due to continued low
producer activity.
The increase in operating expenses was due to
higher activity levels in the Permian, the addition of the Heim
Plant in the third quarter of 2021, the acquisition of certain
assets in South Texas in the second quarter of 2022 and inflation
impacts, which resulted in increased labor costs, materials and
chemicals.
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 June 30, |
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
(In millions, except operating statistics) |
|
Operating margin |
$ |
|
322.3 |
|
|
$ |
|
291.4 |
|
|
$ |
|
30.9 |
|
|
11 |
% |
|
|
$ |
|
674.5 |
|
|
$ |
|
640.1 |
|
|
$ |
|
34.4 |
|
|
5 |
% |
|
Operating expenses |
|
|
74.4 |
|
|
|
|
70.7 |
|
|
|
|
3.7 |
|
|
5 |
% |
|
|
|
|
141.3 |
|
|
|
|
136.5 |
|
|
|
|
4.8 |
|
|
4 |
% |
|
Adjusted operating margin |
$ |
|
396.7 |
|
|
$ |
|
362.1 |
|
|
$ |
|
34.6 |
|
|
10 |
% |
|
|
$ |
|
815.8 |
|
|
$ |
|
776.6 |
|
|
$ |
|
39.2 |
|
|
5 |
% |
|
Operating statistics
MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL pipeline transportation
volumes (2) |
|
|
492.3 |
|
|
|
|
391.7 |
|
|
|
|
100.6 |
|
|
26 |
% |
|
|
|
|
476.1 |
|
|
|
|
367.2 |
|
|
|
|
108.9 |
|
|
30 |
% |
|
Fractionation volumes |
|
|
737.2 |
|
|
|
|
643.7 |
|
|
|
|
93.5 |
|
|
15 |
% |
|
|
|
|
720.1 |
|
|
|
|
595.0 |
|
|
|
|
125.1 |
|
|
21 |
% |
|
Export volumes (3) |
|
|
342.6 |
|
|
|
|
340.6 |
|
|
|
|
2.0 |
|
|
1 |
% |
|
|
|
|
341.7 |
|
|
|
|
312.1 |
|
|
|
|
29.6 |
|
|
9 |
% |
|
NGL sales |
|
|
906.9 |
|
|
|
|
833.8 |
|
|
|
|
73.1 |
|
|
9 |
% |
|
|
|
|
890.0 |
|
|
|
|
830.6 |
|
|
|
|
59.4 |
|
|
7 |
% |
|
_______________________
(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 June 30, 2022 Compared
to Three Months Ended June 30, 2021
The increase in adjusted operating margin was
due to higher pipeline transportation and fractionation volumes,
partially offset by lower marketing margin and lower LPG export
margin. Pipeline transportation and fractionation volumes benefited
from higher supply volumes primarily from the Company’s Permian
Gathering and Processing systems. Marketing margin decreased due to
fewer optimization opportunities. LPG export margin decreased
primarily due to higher fuel and power costs, partially offset by
higher fees.
The increase in operating expenses was due to
higher repairs and maintenance.
Six Months Ended June 30, 2022 Compared to
Six Months Ended June 30, 2021
The increase in adjusted operating margin was
due to higher pipeline transportation and fractionation volumes and
higher LPG export margin, partially offset by lower marketing
margin. Pipeline transportation and fractionation volumes benefited
from higher supply volumes primarily from the Company’s Permian
Gathering and Processing systems. LPG export margin increased due
to higher volumes and fees, partially offset by higher fuel and
power costs. Higher optimization margin attributable to the winter
storm resulted in higher marketing margin in 2021.
The increase in operating expenses was primarily
due to higher repairs and maintenance partially offset by lower
taxes.
Other
|
|
Three Months Ended June 30, |
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
2022 |
|
|
2021 |
|
|
2022 vs. 2021 |
|
|
|
(In millions) |
|
Operating margin |
|
$ |
(4.5 |
) |
|
$ |
(70.5 |
) |
|
$ |
66.0 |
|
|
$ |
(182.7 |
) |
|
$ |
(69.1 |
) |
|
$ |
(113.6 |
) |
Adjusted operating margin |
|
$ |
(4.5 |
) |
|
$ |
(70.5 |
) |
|
$ |
66.0 |
|
|
$ |
(182.7 |
) |
|
$ |
(69.1 |
) |
|
$ |
(113.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other contains the results of commodity
derivative activity mark-to-market gains/losses related to
derivative contracts that were not designated as cash flow hedges.
The Company has entered into derivative instruments to hedge the
commodity price associated with a portion of the Company’s future
commodity purchases and sales and natural gas transportation basis
risk within the Company’s Logistics and Transportation segment.
About Targa Resources Corp.
Targa Resources Corp. is a leading provider of
midstream services and is one of the largest independent midstream
infrastructure companies in North America. The Company owns,
operates, acquires and develops a diversified portfolio of
complementary 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 400.
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 June 30, |
|
|
|
Six Months Ended June 30, |
|
|
2022 |
|
|
2021 |
|
|
2022 |
|
|
2021 |
|
|
(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. |
$ |
|
596.4 |
|
|
$ |
|
56.2 |
|
|
$ |
|
684.4 |
|
|
$ |
|
202.6 |
|
Interest (income) expense, net |
|
|
81.2 |
|
|
|
|
94.8 |
|
|
|
|
174.7 |
|
|
|
|
193.2 |
|
Income tax expense (benefit) |
|
|
87.1 |
|
|
|
|
6.6 |
|
|
|
|
110.1 |
|
|
|
|
21.6 |
|
Depreciation and amortization expense |
|
|
269.9 |
|
|
|
|
211.9 |
|
|
|
|
479.0 |
|
|
|
|
428.0 |
|
(Gain) loss on sale or disposition of assets |
|
|
(0.6 |
) |
|
|
|
(0.4 |
) |
|
|
|
(1.6 |
) |
|
|
|
(0.2 |
) |
Write-down of assets |
|
|
0.5 |
|
|
|
|
1.1 |
|
|
|
|
1.0 |
|
|
|
|
4.7 |
|
(Gain) loss from financing activities (1) |
|
|
33.8 |
|
|
|
|
1.9 |
|
|
|
|
49.6 |
|
|
|
|
16.6 |
|
(Gain) loss from sale of equity method investment |
|
|
(435.9 |
) |
|
|
|
— |
|
|
|
|
(435.9 |
) |
|
|
|
— |
|
Equity (earnings) loss |
|
|
(1.4 |
) |
|
|
|
(12.8 |
) |
|
|
|
(7.0 |
) |
|
|
|
(24.6 |
) |
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
|
6.8 |
|
|
|
|
26.9 |
|
|
|
|
19.3 |
|
|
|
|
60.2 |
|
Compensation on equity grants |
|
|
13.8 |
|
|
|
|
15.0 |
|
|
|
|
27.3 |
|
|
|
|
29.9 |
|
Risk management activities |
|
|
4.5 |
|
|
|
|
69.7 |
|
|
|
|
182.7 |
|
|
|
|
68.2 |
|
Noncontrolling interests adjustments (2) |
|
|
10.3 |
|
|
|
|
(10.9 |
) |
|
|
|
8.5 |
|
|
|
|
(24.5 |
) |
Adjusted
EBITDA |
$ |
|
666.4 |
|
|
$ |
|
460.0 |
|
|
$ |
|
1,292.1 |
|
|
$ |
|
975.7 |
|
Interest expense on debt obligations (3) |
|
|
(90.7 |
) |
|
|
|
(95.5 |
) |
|
|
|
(182.2 |
) |
|
|
|
(194.2 |
) |
Maintenance capital expenditures, net (4) |
|
|
(39.7 |
) |
|
|
|
(24.2 |
) |
|
|
|
(77.4 |
) |
|
|
|
(43.2 |
) |
Cash taxes |
|
|
(2.6 |
) |
|
|
|
(0.8 |
) |
|
|
|
(4.3 |
) |
|
|
|
(1.3 |
) |
Distributable Cash
Flow |
$ |
|
533.4 |
|
|
$ |
|
339.5 |
|
|
$ |
|
1,028.2 |
|
|
$ |
|
737.0 |
|
Growth capital expenditures, net (4) |
|
|
(199.3 |
) |
|
|
|
(83.4 |
) |
|
|
|
(320.7 |
) |
|
|
|
(144.4 |
) |
Adjusted Free Cash
Flow |
$ |
|
334.1 |
|
|
$ |
|
256.1 |
|
|
$ |
|
707.5 |
|
|
$ |
|
592.6 |
|
___________________
(1) Gains or losses on
debt repurchases or early debt
extinguishments.(2) Noncontrolling interest
portion of depreciation and amortization
expense.(3) Excludes amortization of
interest expense.(4) 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 2022:
|
2022E |
|
|
(In millions) |
|
Reconciliation of Estimated Net Income attributable to
Targa Resources Corp. to |
|
|
|
Estimated Adjusted
EBITDA |
|
|
|
Net income attributable to Targa Resources Corp. |
$ |
1,245.0 |
|
Interest expense, net |
|
400.0 |
|
Income tax expense |
|
340.0 |
|
Depreciation and amortization expense |
|
1,050.0 |
|
Gain from sale of equity method investment |
|
(440.0 |
) |
Equity earnings |
|
(14.0 |
) |
Loss from financing activities (1) |
|
50.0 |
|
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
40.0 |
|
Compensation on equity grants |
|
55.0 |
|
Risk management and other |
|
180.0 |
|
Noncontrolling interests adjustments (2) |
|
(6.0 |
) |
Estimated Adjusted
EBITDA |
$ |
2,900.0 |
|
(1) Losses on debt
repurchases or early debt
extinguishments.(2) Noncontrolling interest
portion of depreciation and amortization expense.
Forward-Looking Statements
Certain statements in this release are
“forward-looking statements” within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other
than statements of historical facts, included in this release that
address activities, events or developments that the Company
expects, believes or anticipates will or may occur in the future,
are forward-looking statements. These forward-looking statements
rely on a number of assumptions concerning future events and are
subject to a number of uncertainties, factors and risks, many of
which are outside the Company’s control, which could cause results
to differ materially from those expected by management of the
Company. Such risks and uncertainties include, but are not limited
to, weather, political, economic and market conditions, including a
decline in the price and market demand for natural gas, natural gas
liquids and crude oil, the impact of pandemics such as COVID-19,
commodity price volatility due to ongoing conflict in Ukraine,
actions by the Organization of the Petroleum Exporting Countries
(“OPEC”) and non-OPEC oil producing countries, the timing and
success of business development efforts, expected benefits relating
to the Delaware Basin acquisition and their impact on the Company’s
results of operations, 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 LadVice President, Finance & Investor
Relations
Jennifer KnealeChief Financial Officer
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