Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or
“Targa”) today reported third quarter 2021 results.
Third Quarter 2021 Financial
Results
Third quarter 2021 net income attributable to
Targa Resources Corp. was $182.2 million compared to net income of
$69.3 million for the third quarter of 2020.
The Company reported adjusted earnings before
interest, income taxes, depreciation and amortization, and other
non-cash items (“Adjusted EBITDA”) of $505.9 million for the third
quarter of 2021 compared to $419.1 million for the third
quarter of 2020 (see the section of this release entitled “Non-GAAP
Financial Measures” for a discussion of adjusted EBITDA,
distributable cash flow, adjusted free cash flow, adjusted gross
margin and adjusted operating margin, and reconciliations of such
measures to their most directly comparable financial measures
calculated and presented in accordance with U.S. generally accepted
accounting principles (“GAAP”)).
On October 14, 2021, TRC declared a quarterly
dividend of $0.10 per share of its common stock for the
three months ended September 30, 2021, or $0.40 per
share on an annualized basis. Total cash dividends of approximately
$23.3 million will be paid on November 15, 2021 on all
outstanding shares of common stock to holders of record as of the
close of business on October 29, 2021. Also, on October
14, 2021, TRC declared a quarterly cash dividend of $23.75 per
share of its Series A Preferred Stock. Total cash dividends of
approximately $21.8 million will be paid on November 12, 2021 on
all outstanding shares of Series A Preferred Stock to holders of
record as of the close of business on October 29, 2021.
The Company reported distributable cash flow and
adjusted free cash flow before dividends for the third quarter of
2021 of $383.9 million and $297.2 million, respectively.
2021 Updated Operational and Financial
Expectations
Targa now estimates 2021 average Permian natural
gas inlet volumes to exceed the top end of its previously disclosed
5 percent to 10 percent growth range over 2020 average Permian
natural gas inlet volumes, which will also result in incremental
volumes through Targa’s Logistics and Transportation (“L&T”)
systems.
For full year 2021, Targa now estimates adjusted
EBITDA to exceed the top end of its previously disclosed range of
$1.9 billion to $2.0 billion, and Targa’s year-end 2021
consolidated leverage ratio is estimated to be about 3.25 times.
Targa now expects its 2021 net growth capital expenditures to be
around $450 million due to increasing activity levels and some
additional spending for long-lead items for Targa’s next gas plant
in Permian Midland. The estimate for full year 2021 net maintenance
capital expenditures is unchanged at approximately $120
million.
“Our outperformance as we have moved through
this year is reflective of the strength of volume growth across
Targa’s integrated asset footprint, coupled with our success in
utilizing commercial contract structures that protect our downside
and allow us to benefit in a rising commodity price environment.
With consolidated leverage now at the midpoint of our long-term
target range, we are in position to return capital to our
shareholders sooner than previous expectations,” said Matt Meloy,
Chief Executive Officer of Targa. “With year-end leverage estimated
to be about 3.25 times, over the short, medium, and long-term, we
have the flexibility to return capital to our shareholders through
common dividend increases and share repurchases, while executing on
the simplification of our capital structure and continuing to
invest in accretive growth opportunities across our core integrated
strategy. We remain focused on maintaining our balance sheet
strength to preserve Targa’s financial flexibility through business
cycles and position Targa to maximize shareholder value.”
Capital Allocation Update
For the fourth quarter of 2021, Targa intends to
recommend to its board of directors an increase to its common
dividend to $0.35 per common share or $1.40 per common share
annualized. The initial recommended common dividend per share
increase is expected to be effective for the fourth quarter of 2021
and payable in February 2022. An annualized common dividend of
$1.40 per share represents about 30 percent of Targa’s expected
2021 adjusted free cash flow. Beyond 2022, Targa expects to be in
position to provide modest annual increases to its common
dividend.
Given year-end 2021 consolidated leverage is
estimated to be in the lower end of Targa’s target range, the
Company is also in position to opportunistically repurchase common
stock under its existing $500 million authorized share repurchase
program (the “Share Repurchase Program”) and will continue to
simplify its capital structure through the redemption of
outstanding shares of Targa Series A Preferred Stock (“Series A
Preferred”) over time.
There is no change to Targa’s assumption that it
expects to repurchase its interests in its development company
joint ventures from investment vehicles affiliated with Stonepeak
Infrastructure Partners for approximately $925 million in January
2022.
Consistent with previous years, Targa plans to
detail its full year 2022 operational and financial outlook in
February 2022 in conjunction with its fourth quarter 2021 earnings
announcement.
“We believe that Targa provides a unique value
proposition to our shareholders across cycles as we continue to
invest in attractive growth capital opportunities, simplify our
capital structure and advance towards achieving investment grade
ratings. Our updated capital allocation strategy aligns well with
these priorities while increasing the amount of capital that we can
return to our shareholders over time,” said Meloy. “The tailwinds
of the current commodity price environment are welcome, but more
importantly, the strength of our balance sheet will allow us to
capitalize on opportunities across cycles, and maintaining that
flexibility is a priority to our strategy going forward.”
Third Quarter 2021 - Sequential Quarter
over Quarter Commentary
Targa reported third quarter 2021 adjusted
EBITDA of $505.9 million, representing a 10 percent increase when
compared to the second quarter of 2021. 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 L&T systems during the
third quarter. In the G&P segment, record Permian natural gas
volumes and higher commodity prices drove the sequential increase
in segment adjusted gross margin, partially offset by lower volumes
in Coastal, which were impacted by the effects of Hurricane Ida.
The increase in natural gas inlet volumes in the Permian were
attributable to an increase in production and activity levels. In
the L&T segment, higher sequential pipeline transportation and
fractionation volumes were partially offset by lower LPG export
volumes. Targa’s Grand Prix NGL Pipeline (“Grand Prix”) and its
fractionation complex in Mont Belvieu operated at record levels
during the third quarter primarily due to higher supply volumes
from Targa’s Permian G&P systems. Lower sequential LPG export
volumes were attributable to general maintenance at Targa’s Galena
Park export facility completed during the third quarter, which
reduced the number of available loading days. Higher sequential
operating expenses in the G&P segment were attributable to
system expansions in the Permian with the addition of the Heim
Plant in early September.
Capitalization and Liquidity
The Company’s total consolidated debt as of
September 30, 2021 was $6,786.7 million, net of $46.3 million
of debt issuance costs, with $340.0 million outstanding under Targa
Resources Partners LP’s (“TRP” or the “Partnership”) accounts
receivable securitization facility (the “Securitization Facility”),
$6,465.7 million of outstanding TRP senior notes, and $27.3 million
of finance lease liabilities.
Total consolidated liquidity as of September 30,
2021, was over $3.1 billion, including $228.6 million of cash and
$60.0 million available under the Securitization Facility. As of
September 30, 2021, TRC did not have any borrowings under its
$670.0 million senior secured revolving credit facility (the “TRC
Revolver”). TRP did not have any borrowings and had $48.8 million
in letters of credit outstanding under its $2.2 billion senior
secured revolving credit facility (the “TRP Revolver”), resulting
in available senior secured revolving credit facility capacity of
$2,151.2 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 November 4, 2021 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/s3rh8j3u. 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 September 30, |
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30, |
|
|
|
|
|
|
|
|
|
2021 |
|
|
2020 |
|
|
2021 vs. 2020 |
|
|
2021 |
|
|
2020 |
|
|
2021 vs. 2020 |
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
4,118.1 |
|
|
$ |
1,840.8 |
|
|
$ |
2,277.3 |
|
|
124 |
% |
|
$ |
10,577.3 |
|
|
$ |
4,900.8 |
|
|
$ |
5,676.5 |
|
|
116 |
% |
Fees from midstream services |
|
341.6 |
|
|
|
274.3 |
|
|
|
67.3 |
|
|
25 |
% |
|
|
930.9 |
|
|
|
786.7 |
|
|
|
144.2 |
|
|
18 |
% |
Total revenues |
|
4,459.7 |
|
|
|
2,115.1 |
|
|
|
2,344.6 |
|
|
111 |
% |
|
|
11,508.2 |
|
|
|
5,687.5 |
|
|
|
5,820.7 |
|
|
102 |
% |
Product purchases and fuel
(1) |
|
3,614.7 |
|
|
|
1,322.9 |
|
|
|
2,291.8 |
|
|
173 |
% |
|
|
9,159.8 |
|
|
|
3,405.1 |
|
|
|
5,754.7 |
|
|
169 |
% |
Operating expenses (1) |
|
189.4 |
|
|
|
162.2 |
|
|
|
27.2 |
|
|
17 |
% |
|
|
545.3 |
|
|
|
506.8 |
|
|
|
38.5 |
|
|
8 |
% |
Depreciation and amortization
expense |
|
222.8 |
|
|
|
203.7 |
|
|
|
19.1 |
|
|
9 |
% |
|
|
650.9 |
|
|
|
647.3 |
|
|
|
3.6 |
|
|
1 |
% |
General and administrative
expense |
|
67.3 |
|
|
|
58.6 |
|
|
|
8.7 |
|
|
15 |
% |
|
|
192.4 |
|
|
|
180.6 |
|
|
|
11.8 |
|
|
7 |
% |
Impairment of long-lived
assets |
|
— |
|
|
|
— |
|
|
|
— |
|
|
— |
|
|
|
— |
|
|
|
2,442.8 |
|
|
|
(2,442.8 |
) |
|
(100 |
%) |
Other operating (income)
expense |
|
(1.0 |
) |
|
|
72.2 |
|
|
|
(73.2 |
) |
|
(101 |
%) |
|
|
3.4 |
|
|
|
73.8 |
|
|
|
(70.4 |
) |
|
(95 |
%) |
Income (loss) from
operations |
|
366.5 |
|
|
|
295.5 |
|
|
|
71.0 |
|
|
24 |
% |
|
|
956.4 |
|
|
|
(1,568.9 |
) |
|
|
2,525.3 |
|
|
161 |
% |
Interest expense, net |
|
(91.0 |
) |
|
|
(97.7 |
) |
|
|
6.7 |
|
|
7 |
% |
|
|
(284.2 |
) |
|
|
(292.4 |
) |
|
|
8.2 |
|
|
3 |
% |
Equity earnings (loss) |
|
14.3 |
|
|
|
18.6 |
|
|
|
(4.3 |
) |
|
(23 |
%) |
|
|
38.9 |
|
|
|
54.1 |
|
|
|
(15.2 |
) |
|
(28 |
%) |
Gain (loss) from financing
activities |
|
— |
|
|
|
(13.7 |
) |
|
|
13.7 |
|
|
100 |
% |
|
|
(16.6 |
) |
|
|
47.4 |
|
|
|
(64.0 |
) |
|
(135 |
%) |
Other, net |
|
0.2 |
|
|
|
1.4 |
|
|
|
(1.2 |
) |
NM |
|
|
|
0.3 |
|
|
|
2.2 |
|
|
|
(1.9 |
) |
NM |
|
Income tax (expense)
benefit |
|
(2.0 |
) |
|
|
(31.9 |
) |
|
|
29.9 |
|
|
94 |
% |
|
|
(23.5 |
) |
|
|
286.6 |
|
|
|
(310.1 |
) |
|
(108 |
%) |
Net income (loss) |
|
288.0 |
|
|
|
172.2 |
|
|
|
115.8 |
|
|
67 |
% |
|
|
671.3 |
|
|
|
(1,471.0 |
) |
|
|
2,142.3 |
|
|
146 |
% |
Less: Net income (loss)
attributable to noncontrolling interests |
|
105.8 |
|
|
|
102.9 |
|
|
|
2.9 |
|
|
3 |
% |
|
|
286.5 |
|
|
|
116.5 |
|
|
|
170.0 |
|
|
146 |
% |
Net income (loss) attributable
to Targa Resources Corp. |
|
182.2 |
|
|
|
69.3 |
|
|
|
112.9 |
|
|
163 |
% |
|
|
384.8 |
|
|
|
(1,587.5 |
) |
|
|
1,972.3 |
|
|
124 |
% |
Dividends on Series A
Preferred Stock |
|
21.8 |
|
|
|
22.9 |
|
|
|
(1.1 |
) |
|
(5 |
%) |
|
|
65.5 |
|
|
|
68.8 |
|
|
|
(3.3 |
) |
|
(5 |
%) |
Deemed dividends on Series A
Preferred Stock |
|
— |
|
|
|
9.5 |
|
|
|
(9.5 |
) |
|
(100 |
%) |
|
|
— |
|
|
|
27.7 |
|
|
|
(27.7 |
) |
|
(100 |
%) |
Net income (loss) attributable
to common shareholders |
$ |
160.4 |
|
|
$ |
36.9 |
|
|
$ |
123.5 |
|
NM |
|
|
$ |
319.3 |
|
|
$ |
(1,684.0 |
) |
|
$ |
2,003.3 |
|
|
119 |
% |
Financial
data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (2) |
$ |
505.9 |
|
|
$ |
419.1 |
|
|
$ |
86.8 |
|
|
21 |
% |
|
$ |
1,481.4 |
|
|
$ |
1,198.5 |
|
|
$ |
282.9 |
|
|
24 |
% |
Distributable cash flow
(2) |
|
383.9 |
|
|
|
294.7 |
|
|
|
89.2 |
|
|
30 |
% |
|
|
1,120.7 |
|
|
|
878.9 |
|
|
|
241.8 |
|
|
28 |
% |
Adjusted free cash flow
(2) |
|
297.2 |
|
|
|
189.3 |
|
|
|
107.9 |
|
|
57 |
% |
|
|
892.8 |
|
|
|
360.4 |
|
|
|
532.4 |
|
|
148 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_______________(1) Beginning in 2021, the
Company reclassified certain fuel and power costs previously
included in Operating expenses to Product purchases and fuel to
better reflect the direct relationship of these costs to Targa’s
revenue-generating activities and align with the Company’s
evaluation of the performance of the business.(2) 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 September 30, 2021 Compared to Three
Months Ended September 30, 2020
The increase in commodity sales reflects higher
NGL, natural gas and condensate prices ($2,259.0 million) and
higher NGL and natural gas volumes ($226.6 million), partially
offset by the unfavorable impact of hedges ($192.8 million).
The increase in fees from midstream services is
primarily due to higher gas gathering and processing fees,
partially offset by lower terminaling and storage fees.
The increase in product purchases and fuel
reflects higher NGL, natural gas and condensate prices and higher
NGL and natural gas volumes.
Operating expenses were higher due to increased
labor costs and higher repairs and maintenance primarily due to
increased activity levels and system expansions.
See “—Results of Operations—By Reportable
Segment” for additional information on a segment basis.
The increase in depreciation and amortization
expense is primarily due to a full quarter of depreciation on major
growth capital projects previously placed in service, including the
addition of fractionation trains in Mont Belvieu, Texas and
additional processing plants and associated infrastructure in the
Permian Basin. The increase in depreciation and amortization
expense was partially offset by the sale of assets in Channelview,
Texas, in October 2020.
The increase in general and administrative
expense is primarily due to higher compensation and benefits and an
increase in insurance costs.
Other operating (income) expense in 2020
consisted primarily of a loss associated with the reduction in the
carrying value of the Company’s assets in Channelview, Texas in
connection with the October 2020 Sale and write-down of certain
assets to their recoverable amounts.
The decrease in interest expense, net is
primarily due to lower net borrowings, partially offset by lower
capitalized interest resulting from lower growth capital
investments.
During the third quarter of 2020, the
Partnership redeemed the 6¾% Senior Notes due 2024, resulting in a
$13.7 million net loss from financing activities.
The decrease in income tax expense is primarily
due to a larger release of the valuation allowance in 2021 compared
to
2020.
The decrease in dividends on Series A Preferred
is due to the partial repurchase of the Company’s Series A
Preferred in December 2020.
The decrease in deemed dividends on Series A
Preferred is due to the adoption of Accounting Standards Update
2020-06, Debt - Debt with Conversion and Other Options (Subtopic
470-20) and Derivatives and Hedging - Contracts in Entity’s Own
Equity (Subtopic 815-40): Accounting for Convertible Instruments
and Contracts in an Entity’s Own Equity, which no longer requires
the discount accretion related to beneficial conversion feature as
a deemed dividend.
Nine Months Ended September 30, 2021 Compared to Nine
Months Ended September 30, 2020
The increase in commodity sales reflects higher
NGL, natural gas and condensate prices ($5,840.0 million) and
higher NGL and natural gas volumes ($650.5 million), partially
offset by lower petroleum products, crude marketing and condensate
volumes ($148.0 million) and the unfavorable impact of hedges
($666.0 million).
The increase in fees from midstream services is
primarily due to higher gas gathering and processing fees,
partially offset by lower terminaling and storage fees.
The increase in product purchases and fuel
reflects higher NGL, natural gas and condensate prices and higher
NGL and natural gas volumes, partially offset by lower petroleum
products, crude marketing and condensate volumes.
Operating expenses were higher due to increased
labor costs, higher repairs and maintenance and higher ad valorem
taxes primarily due to increased activity levels and system
expansions.
See “—Results of Operations—By Reportable
Segment” for additional information on a segment basis.
The increase in general and administrative
expense is primarily due to higher compensation and benefits and an
increase in insurance costs, partially offset by a decrease in
professional fees.
In 2020, the Company recognized a non-cash
pre-tax impairment charge of $2,442.8 million, primarily associated
with the partial impairment of certain gas processing facilities
and gathering systems associated with the Company’s Central
operations and full impairment of the Company’s Coastal
operations.
Other operating (income) expense in 2020
consisted primarily of a loss associated with the reduction in the
carrying value of the Company’s assets in Channelview, Texas in
connection with the October 2020 Sale and write-down of certain
assets to their recoverable amounts.
The decrease in interest expense, net is
primarily due to lower net borrowings, partially offset by lower
capitalized interest resulting from lower growth capital
investments.
The decrease in equity earnings is primarily due
to lower earnings from the Company’s investments in Gulf Coast
Fractionators and Cayenne Pipeline LLC, partially offset by an
increase from Little Missouri 4 LLC (“Little Missouri 4”).
During 2021, the Partnership redeemed the 5⅛%
Notes, the TPL Notes and the 4¼% Notes resulting in a $16.6 million
net loss from financing activities. During 2020, the Partnership
repurchased a portion of its outstanding senior notes on the open
market, resulting in a $47.4 million net gain from financing
activities.
The increase in income tax expense is primarily
due to an increase in pre-tax book income, partially offset by a
decrease in the valuation allowance.
The increase in net income attributable to
noncontrolling interests is primarily due to impairment losses
allocated to noncontrolling interest holders in the first quarter
of 2020 and higher income allocated to noncontrolling interest
holders in Grand Prix Pipeline LLC. The increase in net income
attributable to noncontrolling interests was partially offset by
the impact of the redemption of the Partnership’s preferred units
in December 2020.
The decrease in dividends on Series A Preferred
is due to the partial repurchase of the Company’s Series A
Preferred in December 2020.
The decrease in deemed dividends on Series A
Preferred is due to the adoption of Accounting Standards Update
2020-06, Debt - Debt with Conversion and Other Options (Subtopic
470-20) and Derivatives and Hedging - Contracts in Entity’s Own
Equity (Subtopic 815-40): Accounting for Convertible Instruments
and Contracts in an Entity’s Own Equity, which no longer requires
the discount accretion related to beneficial conversion feature as
a deemed dividend.
Review of Segment
Performance
The following discussion of segment performance
includes inter-segment activities. The Company views segment
operating margin and adjusted gross margin as important performance
measures of the core profitability of its operations. These
measures are key components of internal financial reporting and are
reviewed for consistency and trend analysis. For a discussion of
adjusted operating margin and adjusted gross margin, see “Non-GAAP
Financial Measures ― Adjusted Operating Margin” and “Non-GAAP
Financial Measures ― Adjusted Gross Margin.” Segment operating
financial results and operating statistics include the effects of
intersegment transactions. These intersegment transactions have
been eliminated from the consolidated presentation.
The Company operates in two primary segments:
(i) Gathering and Processing; and (ii) Logistics and
Transportation.
Gathering and Processing
Segment
The Gathering and Processing segment includes
assets used in the gathering and/or purchase and sale of natural
gas produced from oil and gas wells, removing impurities and
processing this raw natural gas into merchantable natural gas by
extracting NGLs; and assets used for the gathering and terminaling
and/or purchase and sale of crude oil. The Gathering and Processing
segment's assets are located in the Permian Basin of West Texas and
Southeast New Mexico (including the Midland, Central and Delaware
Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in
North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma
(including the SCOOP and STACK) and South Central Kansas; the
Williston Basin in North Dakota (including the Bakken and Three
Forks plays); and the onshore and near offshore regions of the
Louisiana Gulf Coast and the Gulf of Mexico.
The following table provides summary data
regarding results of operations of this segment for the periods
indicated:
|
Three Months Ended September 30, |
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
2021 |
|
2020 |
|
2021 vs. 2020 |
|
|
2021 |
|
|
2020 |
|
|
2021 vs. 2020 |
|
|
|
(In millions, except operating statistics and price
amounts) |
|
|
|
|
|
|
Operating margin |
$ |
361.4 |
|
$ |
261.0 |
|
$ |
100.4 |
|
|
38 |
% |
|
$ |
938.2 |
|
|
$ |
753.7 |
|
|
$ |
184.5 |
|
|
24 |
% |
Operating expenses (1) |
|
122.8 |
|
|
102.1 |
|
|
20.7 |
|
|
20 |
% |
|
|
343.1 |
|
|
|
313.6 |
|
|
|
29.5 |
|
|
9 |
% |
Adjusted gross margin (1) |
$ |
484.2 |
|
$ |
363.1 |
|
$ |
121.1 |
|
|
33 |
% |
|
$ |
1,281.3 |
|
|
$ |
1,067.3 |
|
|
$ |
214.0 |
|
|
20 |
% |
Operating statistics
(2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet,
MMcf/d (3),(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (5) |
|
2,109.2 |
|
|
1,811.5 |
|
|
297.7 |
|
|
16 |
% |
|
|
1,900.7 |
|
|
|
1,722.1 |
|
|
|
178.6 |
|
|
10 |
% |
Permian Delaware |
|
842.7 |
|
|
758.1 |
|
|
84.6 |
|
|
11 |
% |
|
|
805.9 |
|
|
|
712.4 |
|
|
|
93.5 |
|
|
13 |
% |
Total Permian |
|
2,951.9 |
|
|
2,569.6 |
|
|
382.3 |
|
|
|
|
|
|
2,706.6 |
|
|
|
2,434.5 |
|
|
|
272.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
180.5 |
|
|
233.6 |
|
|
(53.1 |
) |
|
(23 |
%) |
|
|
184.0 |
|
|
|
261.5 |
|
|
|
(77.5 |
) |
|
(30 |
%) |
North Texas |
|
180.7 |
|
|
197.8 |
|
|
(17.1 |
) |
|
(9 |
%) |
|
|
179.2 |
|
|
|
206.3 |
|
|
|
(27.1 |
) |
|
(13 |
%) |
SouthOK |
|
420.6 |
|
|
386.9 |
|
|
33.7 |
|
|
9 |
% |
|
|
402.6 |
|
|
|
463.3 |
|
|
|
(60.7 |
) |
|
(13 |
%) |
WestOK |
|
219.4 |
|
|
233.6 |
|
|
(14.2 |
) |
|
(6 |
%) |
|
|
211.6 |
|
|
|
258.7 |
|
|
|
(47.1 |
) |
|
(18 |
%) |
Total Central |
|
1,001.2 |
|
|
1,051.9 |
|
|
(50.7 |
) |
|
|
|
|
|
977.4 |
|
|
|
1,189.8 |
|
|
|
(212.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (6) |
|
135.2 |
|
|
137.0 |
|
|
(1.8 |
) |
|
(1 |
%) |
|
|
137.8 |
|
|
|
136.1 |
|
|
|
1.7 |
|
|
1 |
% |
Total Field |
|
4,088.3 |
|
|
3,758.5 |
|
|
329.8 |
|
|
|
|
|
|
3,821.8 |
|
|
|
3,760.4 |
|
|
|
61.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
527.1 |
|
|
522.8 |
|
|
4.3 |
|
|
1 |
% |
|
|
598.3 |
|
|
|
672.9 |
|
|
|
(74.6 |
) |
|
(11 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
4,615.4 |
|
|
4,281.3 |
|
|
334.1 |
|
|
8 |
% |
|
|
4,420.1 |
|
|
|
4,433.3 |
|
|
|
(13.2 |
) |
|
— |
|
NGL production, MBbl/d
(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (5) |
|
307.3 |
|
|
253.0 |
|
|
54.3 |
|
|
21 |
% |
|
|
274.8 |
|
|
|
247.6 |
|
|
|
27.2 |
|
|
11 |
% |
Permian Delaware |
|
119.8 |
|
|
105.3 |
|
|
14.5 |
|
|
14 |
% |
|
|
109.3 |
|
|
|
97.1 |
|
|
|
12.2 |
|
|
13 |
% |
Total Permian |
|
427.1 |
|
|
358.3 |
|
|
68.8 |
|
|
|
|
|
|
384.1 |
|
|
|
344.7 |
|
|
|
39.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SouthTX |
|
24.2 |
|
|
29.2 |
|
|
(5.0 |
) |
|
(17 |
%) |
|
|
22.6 |
|
|
|
28.7 |
|
|
|
(6.1 |
) |
|
(21 |
%) |
North Texas |
|
21.0 |
|
|
23.7 |
|
|
(2.7 |
) |
|
(11 |
%) |
|
|
20.2 |
|
|
|
24.5 |
|
|
|
(4.3 |
) |
|
(18 |
%) |
SouthOK |
|
52.1 |
|
|
45.9 |
|
|
6.2 |
|
|
14 |
% |
|
|
48.8 |
|
|
|
54.6 |
|
|
|
(5.8 |
) |
|
(11 |
%) |
WestOK |
|
15.7 |
|
|
19.3 |
|
|
(3.6 |
) |
|
(19 |
%) |
|
|
16.2 |
|
|
|
21.2 |
|
|
|
(5.0 |
) |
|
(24 |
%) |
Total Central |
|
113.0 |
|
|
118.1 |
|
|
(5.1 |
) |
|
|
|
|
|
107.8 |
|
|
|
129.0 |
|
|
|
(21.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands |
|
16.2 |
|
|
17.0 |
|
|
(0.8 |
) |
|
(5 |
%) |
|
|
16.0 |
|
|
|
16.3 |
|
|
|
(0.3 |
) |
|
(2 |
%) |
Total Field |
|
556.3 |
|
|
493.4 |
|
|
62.9 |
|
|
|
|
|
|
507.9 |
|
|
|
490.0 |
|
|
|
17.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
28.0 |
|
|
32.5 |
|
|
(4.5 |
) |
|
(14 |
%) |
|
|
34.5 |
|
|
|
41.5 |
|
|
|
(7.0 |
) |
|
(17 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
584.3 |
|
|
525.9 |
|
|
58.4 |
|
|
11 |
% |
|
|
542.4 |
|
|
|
531.5 |
|
|
|
10.9 |
|
|
2 |
% |
Crude oil, Badlands,
MBbl/d |
|
140.8 |
|
|
146.4 |
|
|
(5.6 |
) |
|
(4 |
%) |
|
|
138.7 |
|
|
|
160.4 |
|
|
|
(21.7 |
) |
|
(14 |
%) |
Crude oil, Permian,
MBbl/d |
|
34.1 |
|
|
44.6 |
|
|
(10.5 |
) |
|
(24 |
%) |
|
|
35.3 |
|
|
|
45.3 |
|
|
|
(10.0 |
) |
|
(22 |
%) |
Natural gas sales, BBtu/d
(4) |
|
2,319.9 |
|
|
2,032.3 |
|
|
287.6 |
|
|
14 |
% |
|
|
2,162.5 |
|
|
|
2,079.3 |
|
|
|
83.2 |
|
|
4 |
% |
NGL sales, MBbl/d (4) |
|
412.6 |
|
|
389.5 |
|
|
23.1 |
|
|
6 |
% |
|
|
384.7 |
|
|
|
406.0 |
|
|
|
(21.3 |
) |
|
(5 |
%) |
Condensate sales, MBbl/d |
|
15.4 |
|
|
13.6 |
|
|
1.8 |
|
|
13 |
% |
|
|
15.3 |
|
|
|
16.1 |
|
|
|
(0.8 |
) |
|
(5 |
%) |
Average realized
prices - inclusive of hedges (7): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
3.51 |
|
|
1.34 |
|
|
2.17 |
|
|
162 |
% |
|
|
2.85 |
|
|
|
1.10 |
|
|
|
1.75 |
|
|
159 |
% |
NGL, $/gal |
|
0.69 |
|
|
0.29 |
|
|
0.40 |
|
|
138 |
% |
|
|
0.56 |
|
|
|
0.24 |
|
|
|
0.32 |
|
|
133 |
% |
Condensate, $/Bbl |
|
64.41 |
|
|
43.49 |
|
|
20.92 |
|
|
48 |
% |
|
|
56.86 |
|
|
|
38.56 |
|
|
|
18.30 |
|
|
47 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_______________(1) Beginning in 2021, the
Company reclassified certain fuel and power costs previously
included in Operating expenses to Product purchases and fuel to
better reflect the direct relationship of these costs to Targa’s
revenue-generating activities and align with the Company’s
evaluation of the performance of the business.(2) Segment operating
statistics include the effect of intersegment amounts, which have
been eliminated from the consolidated presentation. For all volume
statistics presented, the numerator is the total volume sold during
the quarter and the denominator is the number of calendar days
during the quarter.(3) 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.(4) 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.(5) Permian Midland includes operations in WestTX, of which
the Company owns 72.8%, and other plants that are owned 100% by the
Company. Operating results for the WestTX undivided interest assets
are presented on a pro-rata net basis in the Company’s reported
financials.(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 gross margin of the
Gathering and Processing segment:
|
|
Three Months Ended September 30, 2021 |
|
|
Three Months Ended September 30, 2020 |
|
|
(In millions, except volumetric data and price
amounts) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
Natural gas (BBtu) |
|
20.5 |
|
|
$ |
(1.52 |
) |
|
$ |
(31.2 |
) |
|
17.5 |
|
|
$ |
0.20 |
|
|
$ |
3.5 |
NGL (MMgal) |
|
150.4 |
|
|
|
(0.35 |
) |
|
|
(52.4 |
) |
|
126.4 |
|
|
|
0.08 |
|
|
|
10.5 |
Crude oil (MBbl) |
|
0.5 |
|
|
|
(18.80 |
) |
|
|
(9.4 |
) |
|
0.5 |
|
|
|
16.75 |
|
|
|
8.0 |
|
|
|
|
|
|
|
|
|
$ |
(93.0 |
) |
|
|
|
|
|
|
|
|
$ |
22.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_______________(1) The price spread is the
differential between the contracted derivative instrument pricing
and the price of the corresponding settled commodity
transaction.
|
|
Nine Months Ended September 30, 2021 |
|
|
Nine Months Ended September 30, 2020 |
|
|
(In millions, except volumetric data and price
amounts) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
|
|
VolumeSettled |
|
|
PriceSpread (1) |
|
|
Gain(Loss) |
Natural gas (BBtu) |
|
56.6 |
|
|
$ |
(1.01 |
) |
|
$ |
(57.2 |
) |
|
50.6 |
|
|
$ |
0.55 |
|
|
$ |
27.7 |
NGL (MMgal) |
|
420.0 |
|
|
|
(0.24 |
) |
|
|
(99.3 |
) |
|
322.1 |
|
|
|
0.15 |
|
|
|
49.7 |
Crude oil (MBbl) |
|
1.6 |
|
|
|
(11.38 |
) |
|
|
(18.2 |
) |
|
1.4 |
|
|
|
19.72 |
|
|
|
27.7 |
|
|
|
|
|
|
|
|
|
$ |
(174.7 |
) |
|
|
|
|
|
|
|
|
$ |
105.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_______________(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, 2021 Compared to Three
Months Ended September 30, 2020
The increase in adjusted gross margin was due to
higher realized commodity prices and higher natural gas inlet
volumes resulting in increased margin primarily in the Permian,
partially offset by lower volumes in the Central region. In the
Permian, natural gas inlet volumes increased due to higher
production and producer activity, as well as the addition of the
Gateway and Heim plants during the third quarters of 2020 and 2021,
respectively. In the Badlands and Coastal regions, natural gas
inlet volumes were relatively flat, while in the Central region the
decrease was due to lower production and continued low producer
activity. Total crude oil volumes decreased in the Badlands and the
Permian due to lower production.
Operating expenses were higher due to increased
activity levels in the Permian and the addition of the Gateway and
Heim plants in the third quarters of 2020 and 2021, respectively,
which resulted in increased labor costs, materials and
chemicals.
Nine Months Ended September 30, 2021 Compared to Nine
Months Ended September 30, 2020
The increase in adjusted gross margin was due to
higher realized commodity prices and higher natural gas inlet
volumes resulting in higher margin primarily in the Permian,
partially offset by the short-term operational disruptions and
impacts associated with the major winter storm during the first
quarter of 2021. In the Permian, natural gas inlet volumes
increased due to higher production, higher producer activity, the
addition of the Peregrine and Gateway plants in 2020 and the Heim
Plant in the third quarter of 2021. In the Badlands, natural gas
inlet volumes were relatively flat, while the decrease in the
Central and Coastal regions was due to continued low producer
activity. Total crude oil volumes decreased in the Badlands and the
Permian due to lower production.
Operating expenses were higher due to increased
activity levels in the Permian, the addition of the Peregrine and
Gateway plants in 2020 and the Heim Plant in the third quarter of
2021, which resulted in increased labor costs and materials.
Logistics and Transportation
Segment
The Logistics and Transportation segment
includes the activities and assets necessary to convert mixed NGLs
into NGL products and also includes other assets and value-added
services such as transporting, storing, fractionating, terminaling,
and marketing of NGLs and NGL products, including services to
liquefied petroleum gas exporters and certain natural gas supply
and marketing activities in support of the Company’s other
businesses. The Logistics and Transportation segment also includes
Grand Prix, which connects the Company’s gathering and processing
positions in the Permian Basin, Southern Oklahoma and North Texas
with the Company’s downstream facilities in Mont Belvieu, Texas, as
well as the Company’s equity interest in GCX, a natural gas
pipeline connecting the Waha hub in West Texas and other receipt
points, including many of the Company’s Midland Basin processing
facilities, to Agua Dulce in South Texas and other delivery points.
The associated assets, including these pipelines, are generally
connected to and supplied in part by the Company’s Gathering and
Processing segment and, except for the pipelines and smaller
terminals, are located predominantly in Mont Belvieu and Galena
Park, Texas, and in Lake Charles, Louisiana.
The following table provides summary data
regarding results of operations of this segment for the periods
indicated:
|
Three Months Ended September 30, |
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
2021 |
|
2020 |
|
2021 vs. 2020 |
|
2021 |
|
2020 |
|
2021 vs. 2020 |
(In millions, except operating statistics and price
amounts) |
Operating margin |
$ |
280.7 |
|
$ |
280.4 |
|
$ |
0.3 |
|
|
— |
|
|
$ |
|
920.5 |
|
$ |
|
806.0 |
|
$ |
|
114.5 |
|
14 |
% |
Operating expenses (1) |
|
67.3 |
|
|
61.7 |
|
|
5.6 |
|
|
9 |
% |
|
|
|
204.1 |
|
|
|
196.8 |
|
|
|
7.3 |
|
4 |
% |
Adjusted gross margin (1) |
$ |
348.0 |
|
$ |
342.1 |
|
$ |
5.9 |
|
|
2 |
% |
|
$ |
|
1,124.6 |
|
$ |
|
1,002.8 |
|
$ |
|
121.8 |
|
12 |
% |
Operating statistics MBbl/d
(2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline throughput (3) |
|
416.5 |
|
|
300.9 |
|
|
115.6 |
|
|
38 |
% |
|
|
|
383.8 |
|
|
|
273.0 |
|
|
|
110.8 |
|
41 |
% |
Fractionation volumes |
|
662.0 |
|
|
589.5 |
|
|
72.5 |
|
|
12 |
% |
|
|
|
617.5 |
|
|
|
598.0 |
|
|
|
19.5 |
|
3 |
% |
Export volumes (4) |
|
293.2 |
|
|
308.5 |
|
|
(15.3 |
) |
|
(5 |
%) |
|
|
|
305.7 |
|
|
|
277.2 |
|
|
|
28.5 |
|
10 |
% |
NGL sales |
|
857.3 |
|
|
724.1 |
|
|
133.2 |
|
|
18 |
% |
|
|
|
881.1 |
|
|
|
721.6 |
|
|
|
159.5 |
|
22 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Beginning in 2021, the Company reclassified
certain fuel and power costs previously included in Operating
expenses to Product purchases and fuel to better reflect the direct
relationship of these costs to Targa’s revenue-generating
activities and align with the Company’s evaluation of the
performance of the business. (2) Segment operating statistics
include intersegment amounts, which have been eliminated from the
consolidated presentation. For all volume statistics presented, the
numerator is the total volume sold during the period and the
denominator is the number of calendar days during the period. (3)
Pipeline throughput represents the total quantity of mixed NGLs
delivered by Grand Prix to Mont Belvieu.(4) Export volumes
represent the quantity of NGL products delivered to third-party
customers at the Company’s Galena Park Marine Terminal that are
destined for international markets.
Three Months Ended September 30, 2021
Compared to Three Months Ended September 30, 2020
The increase in adjusted gross margin was
primarily due to higher pipeline transportation and fractionation
volumes, partially offset by lower LPG export volumes and 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 volumes were
lower due to reduced short-term loading capacity as a result of
repairs and maintenance that were completed in the third quarter of
2021. Marketing margin decreased due to fewer optimization
opportunities.
Operating expenses were higher due to higher
repairs and maintenance, increased system throughput expenses and
higher ad valorem taxes primarily due to system expansions,
partially offset by cost reduction measures and the sale of assets
in Channelview, Texas, in 2020.
Nine Months Ended September 30, 2021
Compared to Nine Months Ended September 30, 2020
The increase in adjusted gross margin was
primarily due to higher pipeline transportation and fractionation
volumes that benefited from higher supply volumes from the
Company’s Permian Gathering and Processing systems, partially
offset by short-term operational disruptions and impacts associated
with the major winter storm during the first quarter of 2021. Other
drivers included higher marketing margin due to greater
optimization opportunities and higher LPG export volumes, partially
offset by lower LPG export terminal fees.
Operating expenses were higher due to higher
repairs and maintenance, increased system throughput expenses and
higher ad valorem taxes primarily due to system expansions,
partially offset by cost reduction measures and the sale of assets
in Channelview, Texas, in 2020.
Other
|
|
Three Months Ended September 30, |
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
2021 |
|
2020 |
|
2021 vs. 2020 |
|
|
2021 |
|
|
2020 |
|
2021 vs. 2020 |
|
|
|
(In millions) |
|
Operating margin |
|
$ |
13.5 |
|
$ |
88.6 |
|
$ |
(75.1 |
) |
|
$ |
(55.6 |
) |
|
$ |
215.9 |
|
$ |
(271.5 |
) |
Gross
margin |
|
$ |
13.5 |
|
$ |
88.6 |
|
$ |
(75.1 |
) |
|
$ |
(55.6 |
) |
|
$ |
215.9 |
|
$ |
(271.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other contains the results of commodity
derivative activity mark-to-market gains/losses related to
derivative contracts that were not designated as cash flow hedges.
The Company has entered into derivative instruments to hedge the
commodity price associated with a portion of the Company’s future
commodity purchases and sales and natural gas transportation basis
risk within the Company’s Logistics and Transportation segment.
About Targa Resources Corp.
Targa Resources Corp. is a leading provider of
midstream services and is one of the largest independent midstream
infrastructure companies in North America. The Company owns,
operates, acquires and develops a diversified portfolio of
complementary midstream infrastructure assets 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, adjusted gross margin and adjusted
operating margin. The following tables provide reconciliations of
these non-GAAP financial measures to their most directly comparable
GAAP measures. These non-GAAP financial measures should not be
considered as alternatives to GAAP measures such as net income,
operating income, net cash flows provided by operating activities
or any other GAAP measure of liquidity or financial
performance.
The Company utilizes non-GAAP measures to
analyze the Company’s performance. Adjusted gross margin, adjusted
operating margin, adjusted EBITDA, distributable cash flow, and
adjusted free cash flow are non-GAAP measures. The GAAP measure
most directly comparable to these non-GAAP measures are gross
margin, income (loss) from operations and net income (loss)
attributable to TRC. These non-GAAP measures should not be
considered as an alternative to the comparable 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 net income, and are defined
differently by different companies within the Company’s industry,
the Company’s definitions may not be comparable with similarly
titled measures of other companies, thereby diminishing their
utility. Management compensates for the limitations of the
Company’s non-GAAP measures as analytical tools by reviewing the
comparable GAAP measures, understanding the differences between the
measures and incorporating these insights into the Company’s
decision-making processes.
Adjusted EBITDA
Adjusted EBITDA is defined as net income (loss)
attributable to TRC before interest, income taxes, depreciation and
amortization, and other items that the Company believes should be
adjusted consistent with the Company’s core operating performance.
The adjusting items are detailed in the adjusted EBITDA
reconciliation table and its footnotes. Adjusted EBITDA is used as
a supplemental financial measure by the Company and by external
users of the Company’s financial statements such as investors,
commercial banks and others to measure the ability of the Company’s
assets to generate cash sufficient to pay interest costs, support
the Company’s indebtedness and pay dividends to the Company’s
investors.
Distributable Cash Flow and Adjusted Free Cash
Flow
The Company defines distributable cash flow as
adjusted EBITDA less distributions to TRP preferred limited
partners, cash interest expense on debt obligations, cash tax
(expense) benefit and maintenance capital expenditures (net of any
reimbursements of project costs). The Preferred Units that were
issued by the Partnership in October 2015 were redeemed in December
2020, and are no longer outstanding. 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 TRC 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, |
|
|
2021 |
|
|
2020 |
|
|
2021 |
|
|
2020 |
|
|
(In millions) |
|
Reconciliation of Net Income (Loss) attributable to TRC to
Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash
Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to TRC |
$ |
182.2 |
|
$ |
69.3 |
|
|
$ |
384.8 |
|
$ |
(1,587.5 |
) |
Income attributable to TRP preferred limited partners |
|
— |
|
|
2.8 |
|
|
|
— |
|
|
8.4 |
|
Interest (income) expense, net |
|
91.0 |
|
|
97.7 |
|
|
|
284.2 |
|
|
292.4 |
|
Income tax expense (benefit) |
|
2.0 |
|
|
31.9 |
|
|
|
23.5 |
|
|
(286.6 |
) |
Depreciation and amortization expense |
|
222.8 |
|
|
203.7 |
|
|
|
650.9 |
|
|
647.3 |
|
Impairment of long-lived assets |
|
— |
|
|
— |
|
|
|
— |
|
|
2,442.8 |
|
(Gain) loss on sale or disposition of business and assets |
|
(1.5 |
) |
|
58.0 |
|
|
|
(1.7 |
) |
|
58.0 |
|
Write-down of assets |
|
0.5 |
|
|
13.5 |
|
|
|
5.0 |
|
|
13.5 |
|
(Gain) loss from financing activities (1) |
|
— |
|
|
13.7 |
|
|
|
16.6 |
|
|
(47.4 |
) |
Equity (earnings) loss |
|
(14.3 |
) |
|
(18.6 |
) |
|
|
(38.9 |
) |
|
(54.1 |
) |
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
28.2 |
|
|
28.2 |
|
|
|
88.4 |
|
|
81.6 |
|
Compensation on equity grants |
|
14.7 |
|
|
16.4 |
|
|
|
44.6 |
|
|
49.5 |
|
Risk management activities |
|
(12.6 |
) |
|
(88.3 |
) |
|
|
55.6 |
|
|
(214.2 |
) |
Severance and related benefits |
|
— |
|
|
— |
|
|
|
— |
|
|
6.5 |
|
Noncontrolling interests adjustments (2) |
|
(7.1 |
) |
|
(9.2 |
) |
|
|
(31.6 |
) |
|
(211.7 |
) |
TRC Adjusted EBITDA |
$ |
505.9 |
|
$ |
419.1 |
|
|
$ |
1,481.4 |
|
$ |
1,198.5 |
|
Distributions to TRP preferred limited partners |
|
— |
|
|
(2.8 |
) |
|
|
— |
|
|
(8.4 |
) |
Interest expense on debt obligations (3) |
|
(91.6 |
) |
|
(98.2 |
) |
|
|
(285.8 |
) |
|
(289.5 |
) |
Maintenance capital expenditures |
|
(31.1 |
) |
|
(27.3 |
) |
|
|
(78.4 |
) |
|
(67.7 |
) |
Noncontrolling interests adjustments of maintenance capital
expenditures |
|
1.5 |
|
|
3.9 |
|
|
|
5.5 |
|
|
1.6 |
|
Cash taxes |
|
(0.8 |
) |
|
— |
|
|
|
(2.0 |
) |
|
44.4 |
|
Distributable Cash
Flow |
$ |
383.9 |
|
$ |
294.7 |
|
|
$ |
1,120.7 |
|
$ |
878.9 |
|
Growth capital expenditures, net (4) |
|
(86.7 |
) |
|
(105.4 |
) |
|
|
(227.9 |
) |
|
(518.5 |
) |
Adjusted Free Cash
Flow |
$ |
297.2 |
|
$ |
189.3 |
|
|
$ |
892.8 |
|
$ |
360.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_______________(1) Gains or losses on debt
repurchases or early debt extinguishments.(2) Noncontrolling
interest portion of depreciation and amortization expense
(including the effects of the impairment of long-lived assets on
non-controlling interests), net of non-cash accretion of
noncontrolling interests.(3) Excludes amortization of interest
expense.(4) Represents growth capital expenditures, net of
contributions from noncontrolling interests and net contributions
to investments in unconsolidated affiliates.
Adjusted Gross Margin
The Company defines adjusted gross margin 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 segment adjusted gross
margin consists primarily of:
- service fees related to natural gas
and crude oil gathering, treating and processing; and
- revenues from the sale of natural
gas, condensate, crude oil and NGLs less producer payments, natural
gas and crude oil purchases, and the Company's equity volume hedge
settlements.
Logistics and Transportation segment adjusted
gross margin consists primarily of:
- service fees (including the
pass-through of energy costs included in fee rates);
- system product gains and losses;
and
- NGL and natural gas sales, less NGL
and natural gas purchases, fuel, third-party transportation costs
and the net inventory change.
The adjusted gross margin impacts of
mark-to-market hedge unrealized changes in fair value are reported
in Other.
Adjusted Operating Margin
Adjusted operating margin is defined as adjusted
gross margin less operating expenses. Adjusted operating margin is
an important performance measure of the core profitability of the
Company’s operations. Adjusted gross margin and adjusted operating
margin provide useful information to investors because they are
used as supplemental financial measures by management and by
external users of the Company’s financial statements, including
investors and commercial banks, to assess:
- the financial
performance of the Company’s assets without regard to financing
methods, capital structure or historical cost basis;
- the Company’s
operating performance and return on capital as compared to other
companies in the midstream energy sector, without regard to
financing or capital structure; and
- the viability of
capital expenditure projects and acquisitions and the overall rates
of return on alternative investment opportunities.
Management reviews business segment adjusted
gross margin and operating margin monthly as a core internal
management process. The Company believes that investors benefit
from having access to the same financial measures that management
uses in evaluating its operating results.
The following table presents a reconciliation of
income (loss) from operations to adjusted operating margin and
gross margin to adjusted gross margin for the periods
indicated:
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2021 |
|
2020 |
|
|
2021 |
|
2020 |
|
|
|
(In millions) |
|
Reconciliation of Income (Loss) from Operations to Adjusted
Operating Margin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from
operations |
|
$ |
366.5 |
|
$ |
295.5 |
|
|
$ |
956.4 |
|
$ |
(1,568.9 |
) |
Depreciation and amortization expense |
|
|
222.8 |
|
|
203.7 |
|
|
|
650.9 |
|
|
647.3 |
|
General and administrative expense |
|
|
67.3 |
|
|
58.6 |
|
|
|
192.4 |
|
|
180.6 |
|
Impairment of long-lived assets |
|
|
— |
|
|
— |
|
|
|
— |
|
|
2,442.8 |
|
(Gain) loss on sale or disposition of business and assets |
|
|
(1.5 |
) |
|
58.0 |
|
|
|
(1.7 |
) |
|
58.0 |
|
Write-down of assets |
|
|
0.5 |
|
|
13.5 |
|
|
|
5.0 |
|
|
13.5 |
|
Other, net |
|
|
— |
|
|
0.7 |
|
|
|
0.1 |
|
|
2.3 |
|
Adjusted operating
margin |
|
$ |
655.6 |
|
$ |
630.0 |
|
|
$ |
1,803.1 |
|
$ |
1,775.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
|
(In millions) |
Reconciliation of Gross Margin to Adjusted Gross
Margin |
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin |
|
$ |
622.2 |
|
$ |
588.5 |
|
$ |
1,697.5 |
|
$ |
1,635.1 |
Depreciation and amortization expense |
|
|
222.8 |
|
|
203.7 |
|
|
650.9 |
|
|
647.3 |
Adjusted gross
margin |
|
$ |
845.0 |
|
$ |
792.2 |
|
$ |
2,348.4 |
|
$ |
2,282.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents a reconciliation of
estimated net income of the Company to estimated adjusted EBITDA
for 2021:
|
2021E |
|
|
(In millions) |
|
Reconciliation of Estimated Net Income attributable to TRC
to |
|
|
|
Estimated Adjusted
EBITDA |
|
|
|
Net income attributable to TRC |
$ |
555.0 |
|
Interest expense, net |
|
370.0 |
|
Income tax expense |
|
50.0 |
|
Depreciation and amortization expense |
|
870.0 |
|
Equity (earnings) loss |
|
(55.0 |
) |
Distributions from unconsolidated affiliates and preferred partner
interests, net |
|
115.0 |
|
Compensation on equity grants |
|
60.0 |
|
Risk management activities and other |
|
75.0 |
|
Noncontrolling interests adjustments (1) |
|
(40.0 |
) |
TRC Estimated Adjusted
EBITDA |
$ |
2,000.0 |
|
|
|
|
|
_______________(1) Noncontrolling interest
portion of depreciation and amortization expense.
Forward-Looking Statements
Certain statements in this release are
“forward-looking statements” within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other
than statements of historical facts, included in this release that
address activities, events or developments that the Company
expects, believes or anticipates will or may occur in the future,
are forward-looking statements. These forward-looking statements
rely on a number of assumptions concerning future events and are
subject to a number of uncertainties, factors and risks, many of
which are outside the Company’s control, which could cause results
to differ materially from those expected by management of the
Company. Such risks and uncertainties include, but are not limited
to, weather, political, economic and market conditions, including a
decline in the price and market demand for natural gas, natural gas
liquids and crude oil, the impact of pandemics such as COVID-19,
actions by the Organization of the Petroleum Exporting Countries
(“OPEC”) and non-OPEC oil producing countries, the timing and
success of business development efforts, and other uncertainties.
These and other applicable uncertainties, factors and risks are
described more fully in the Company’s filings with the Securities
and Exchange Commission, including its most recent Annual Report on
Form 10-K, and any subsequently filed Quarterly Reports on Form
10-Q and Current Reports on Form 8-K. The Company does not
undertake an obligation to update or revise any forward-looking
statement, whether as a result of new information, future events or
otherwise.
Contact the Company's investor relations
department by email at InvestorRelations@targaresources.com or by
phone at (713) 584-1133.
Sanjay LadVice President, Finance & Investor
Relations
Jennifer KnealeChief Financial Officer
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