Targa Resources Partners LP (NYSE:NGLS PRA) (“Targa Resources
Partners”, the “Partnership” or “TRP”) and Targa Resources Corp.
(NYSE:TRGP) (“TRC”, the “Company” or “Targa”) today reported fourth
quarter and full year 2015 results.
Targa Resources Partners – Fourth
Quarter and Full Year 2015 Financial Results
Fourth quarter 2015 net income attributable to
Targa Resources Partners before impairment of goodwill was $50.7
million compared to $108.2 million for the fourth quarter of
2014. The net income results for the fourth quarter and full year
2015 excludes a non-cash provisional loss of $290 million
associated with impairment of goodwill in the Field Gathering and
Processing segment. The Partnership reported earnings before
interest, income taxes, depreciation and amortization, impairment
of goodwill and other non-cash items (“Adjusted EBITDA”) of $324.7
million for the fourth quarter of 2015 compared to
$258.3 million for the fourth quarter of 2014. The Partnership
paid $200.4 million in common equity, general partner, and
incentive distribution right distributions and $2.4 million of
preferred distributions with respect to the fourth quarter of 2015,
which resulted in approximately 1.2 times equity distribution
coverage. Distributable cash flow was $237.0 million (see the
section of this release entitled “Targa Resources Partners -
Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA,
gross margin, operating margin and distributable cash flow, 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”)).
For the full year 2015, net income attributable
to Targa Resources Partners before impairment of goodwill was
$217.8 million compared to $467.7 million for 2014. The
Partnership reported Adjusted EBITDA of $1,191.2 million for the
full year 2015 compared to $970.3 million for the full year
2014.
“Targa’s solid 2015 performance in the current industry
environment highlights the strengths of our diverse businesses and
of our exceptional work force,” said Joe Bob Perkins, Chief
Executive Officer of the Company. “With the buy-in now closed and
with our recently announced preferred equity transaction, we are
well positioned to be patient and potentially opportunistic as we
move through the energy cycle in 2016.”
On January 19, 2016, the Partnership announced a
cash distribution on common units for the fourth quarter 2015 of
$0.8250 per common unit, or $3.30 per unit on an
annualized basis, representing an unchanged distribution from the
previous quarter and approximately 2% growth over the distribution
for the fourth quarter 2014. The cash distribution was paid on
February 9, 2016 on all outstanding common units to holders of
record as of the close of business on February 2, 2016. The
total distribution paid was $200.4 million, with
$139.0 million to the Partnership’s third-party limited
partners and $61.4 million to TRC for its ownership of common
units, incentive distribution rights (“IDRs”) and its 2% general
partner interest in the Partnership.
The Partnership pays monthly preferred
distributions of $0.1875 per Series A Preferred Unit. The initial
distribution rate for the partial month of October 2015 that the
series was outstanding was $0.10 per unit. The Partnership paid
$2.4 million of preferred distributions with respect to the fourth
quarter of 2015.
Targa Resources Corp. – Fourth Quarter
and Full Year 2015 Financial Results
TRC reported net income available to common
shareholders before impairment of goodwill of $52.5 million for the
fourth quarter 2015 compared to $25.6 million for the fourth
quarter 2014. For the full year 2015, net income attributable
to common shareholders before impairment of goodwill was $83.9
million compared to $102.3 million for 2014.
The Company, which as of December 31, 2015 owned
a 2% general partner interest in the Partnership (held through its
100% ownership interest in the general partner of the Partnership),
all of the IDRs and 16,309,594 common units of the
Partnership, presents its results consolidated with those of the
Partnership.
Fourth quarter 2015 distributions paid on
February 9, 2016 by the Partnership to the Company were $61.4
million, with $13.5 million, $43.9 million and $4.0 million
paid with respect to common units, IDRs and general partner
interests, respectively.
On January 19, 2016, TRC declared a quarterly
dividend of $0.9100 per share of its common stock for the
three months ended December 31, 2015, or $3.64 per share
on an annualized basis, flat over the previous quarter’s dividend
and an increase of 24% over the dividend for the fourth quarter of
2014. Total cash dividends of approximately $51.0 million were paid
February 9, 2016 on all outstanding common shares to holders of
record as of the close of business on February 2, 2016.
The Company’s distributable cash flow for the
fourth quarter 2015 was $54.9 million compared to $51.7 million in
total declared dividends for the quarter (see the section of this
release entitled “Targa Resources Corp. - Non-GAAP Financial
Measures” for a discussion of distributable cash flow and
reconciliations of this measure to its most directly comparable
financial measure calculated and presented in accordance with
GAAP).
Targa Resources Partners Fourth Quarter
2015 - Capitalization, Liquidity and Financing
Total funded debt of the Partnership as of
December 31, 2015 was $5,383.3 million including
$280.0 million outstanding under the Partnership’s $1.6
billion senior secured revolving credit facility,
$219.3 million outstanding under the Partnership’s accounts
receivable securitization facility, and $4,884.0 million of
senior unsecured notes, net of unamortized discounts.
As of December 31, 2015, after giving effect to
$12.9 million in outstanding letters of credit, the Partnership had
available revolver capacity of $1,307.1 million.
Targa Resources Corp. Fourth Quarter
2015 - Capitalization, Liquidity and Financing
Total funded debt of the Company as of December
31, 2015, excluding debt of the Partnership, was
$597.5 million including $440.0 million outstanding under the
Company’s $670.0 million senior secured revolving credit facility
due 2020 and $157.5 million, net of unamortized discounts,
outstanding on the Company’s senior secured term loan due 2022.
This resulted in $230.0 million in available revolver capacity as
of December 31, 2015.
TRC/TRP Merger
On February 17, 2016, TRC completed the
previously announced transactions contemplated by the Agreement and
Plan of Merger (the “TRC/TRP Merger Agreement”), by and among TRP,
Targa Resources GP LLC (its “general partner”), TRC and Spartan
Merger Sub LLC, a subsidiary of TRC (“Merger Sub”) pursuant to
which TRC acquired indirectly all of TRP’s outstanding common units
that TRC and its subsidiaries did not already own. Upon the terms
and conditions set forth in the Merger Agreement, Merger Sub merged
with and into TRP (the “TRC/TRP Merger”), with TRP continuing as
the surviving entity and as a subsidiary of TRC. As a result of the
TRC/TRP Merger, TRC owns all of TRP’s outstanding common units.
At the effective time of the TRC/TRP Merger,
each outstanding TRP common unit not owned by TRC or its
subsidiaries was converted into the right to receive 0.62 shares of
common stock of TRC, par value $0.001 per share (“TRC shares”). No
fractional TRC shares were issued in the TRC/TRP Merger, and TRP
common unitholders instead received cash in lieu of fractional TRC
shares.
Pursuant to the TRC/TRP Merger Agreement, TRC
has agreed to cause TRP’s common units to be delisted from the New
York Stock Exchange (“NYSE”) and deregistered under the Securities
Exchange Act of 1934, as amended (the “Exchange Act”). As a result
of the completion of the TRC/TRP Merger, TRP’s common units are no
longer publicly traded. The Series A Preferred Units of TRP remain
outstanding as limited partner interests in TRP and continue to
trade on the NYSE under the symbol “NGLS PRA.”
TRC Private Placement of 9.5% Series A
Preferred Stock
On February 18, 2016, TRC announced that it had
entered into an agreement with an affiliate of Stonepeak
Infrastructure Partners (“Stonepeak”) for the issuance and sale of
$500 million of 9.5% Series A Preferred Stock (the "Preferred
Stock"). The Preferred Stock can be redeemed in whole or in part at
the Company’s option after five years, and is also convertible into
TRC common stock beginning in 2028 by Stonepeak or under certain
conditions by TRC. In connection with the issuance of the Preferred
Stock, TRC also agreed to issue to Stonepeak 7,020,000 warrants
with a strike price of $18.88 per common share and 3,385,000
warrants with a strike price of $25.11 per common share. The
warrants have a seven year term. The Company expects to use the net
proceeds from the sale of the Preferred Stock, which is expected to
close in March 2016, to repay indebtedness and for general
corporate purposes.
Conference Call
Targa will host a conference call for investors
and analysts at 10:30 a.m. Eastern time (9:30 a.m. Central time) on
February 25, 2016 to discuss fourth quarter and full year 2015
financial results. The conference call can be accessed via webcast
through the Events and Presentations section of Targa’s website at
www.targaresources.com, by going directly to
http://ir.targaresources.com/trc/events.cfm or by dialing
877-881-2598. The pass code for the dial-in is 48931557.
Please dial in ten minutes prior to the scheduled start time. A
replay will be available approximately two hours following the
completion of the webcast through the Investors section of the
Company’s website. An updated investor presentation will also be
available in the Events and Presentations section of the Company’s
websites following the completion of the conference call.
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Targa Resources Partners – Consolidated Financial Results
of Operations |
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Three Months Ended December 31, |
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Year Ended December 31, |
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2015 |
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2014 |
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2015 |
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2014 |
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| Revenues: |
($ in millions, except operating statistics
and price amounts) |
| Sales of
commodities |
|
$ |
|
1,345.7 |
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$ |
|
1,742.0 |
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$ |
|
5,465.4 |
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$ |
|
7,595.2 |
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| Fees from midstream
services |
|
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300.2 |
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|
290.9 |
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1,193.2 |
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|
1,021.3 |
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| Total revenues |
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1,647.3 |
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|
2,032.9 |
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|
|
6,658.6 |
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8,616.5 |
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| Product purchases |
|
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1,195.3 |
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|
1,634.7 |
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|
4,873.0 |
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7,046.9 |
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| Gross margin (1) |
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452.0 |
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|
398.2 |
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1,785.6 |
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|
1,569.6 |
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| Operating expenses |
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|
122.8 |
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|
109.4 |
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|
504.6 |
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433.0 |
|
| Operating margin
(2) |
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|
329.2 |
|
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|
288.8 |
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1,281.0 |
|
|
|
|
1,136.6 |
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| Depreciation and
amortization expenses |
|
|
|
228.8 |
|
|
|
|
93.7 |
|
|
|
|
|
677.1 |
|
|
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|
346.5 |
|
| General and
administrative expenses |
|
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|
23.5 |
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|
24.6 |
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|
|
153.6 |
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|
|
139.8 |
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| Goodwill
impairment |
|
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290.0 |
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- |
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290.0 |
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- |
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| Other operating
(income) expenses |
|
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|
(7.8 |
) |
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|
2.1 |
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|
(7.1 |
) |
|
|
|
(3.0 |
) |
| Income from
operations |
|
|
|
(205.3 |
) |
|
|
|
168.4 |
|
|
|
|
|
167.4 |
|
|
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|
653.3 |
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| Interest expense,
net |
|
|
|
(30.6 |
) |
|
|
|
(39.7 |
) |
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|
(207.8 |
) |
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|
(143.8 |
) |
| Equity earnings |
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(1.4 |
) |
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4.3 |
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(2.5 |
) |
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18.0 |
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| Gain (loss) from
financing activities |
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3.4 |
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(12.4 |
) |
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2.8 |
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|
(12.4 |
) |
| Other income
(expense) |
|
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|
(5.2 |
) |
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(4.8 |
) |
|
|
|
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(14.2 |
) |
|
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|
(5.2 |
) |
| Income tax (expense)
benefit |
|
|
|
(0.2 |
) |
|
|
|
(1.1 |
) |
|
|
|
|
(0.6 |
) |
|
|
|
(4.8 |
) |
| Net income |
|
|
|
(239.3 |
) |
|
|
|
114.7 |
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|
|
|
(54.9 |
) |
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|
505.1 |
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| Less: Net income
attributable to noncontrolling interests |
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(49.2 |
) |
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6.5 |
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(31.9 |
) |
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37.4 |
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| Net income attributable
to limited partners and the general partners |
|
$ |
|
(190.1 |
) |
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$ |
|
108.2 |
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|
$ |
|
(23.0 |
) |
|
$ |
|
467.7 |
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| Financial and
operating data: |
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| Financial
data: |
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| Adjusted EBITDA
(3) |
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$ |
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324.7 |
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$ |
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258.3 |
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$ |
|
1,191.2 |
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$ |
|
970.3 |
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| Distributable cash flow
(4) |
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|
237.0 |
|
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|
|
199.3 |
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|
867.8 |
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|
763.2 |
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| Capital
expenditures |
|
|
|
206.1 |
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214.0 |
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|
|
|
777.2 |
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|
747.8 |
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| Operating
statistics: |
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| Crude oil gathered,
MBbl/d |
|
|
|
108.8 |
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|
115.9 |
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|
106.3 |
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|
93.5 |
|
| Plant natural gas
inlet, MMcf/d (5)(6)(7) |
|
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3,472.1 |
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2,104.5 |
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3,241.3 |
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|
2,109.5 |
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| Gross NGL production,
MBbl/d (7) |
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294.7 |
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|
155.6 |
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|
265.5 |
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|
153.0 |
|
| Export volumes, MBbl/d
(8) |
|
|
|
192.0 |
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|
|
|
225.5 |
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|
|
|
|
183.0 |
|
|
|
|
176.9 |
|
| Natural gas sales,
BBtu/d (6)(7) |
|
|
|
1,917.2 |
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|
|
|
937.5 |
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|
|
|
|
1,770.7 |
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|
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|
902.3 |
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| NGL sales, MBbl/d
(7) |
|
|
|
563.0 |
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|
|
472.4 |
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|
|
|
517.0 |
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|
|
|
419.5 |
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| Condensate sales,
MBbl/d (7) |
|
|
|
9.0 |
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|
|
4.3 |
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|
|
|
9.3 |
|
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|
4.4 |
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__________(1) Gross margin is a non-GAAP
financial measure and is discussed under “Targa Resources Partners
- Non-GAAP Financial Measures.” (2) Operating margin is a non-GAAP
financial measure and is discussed under “Targa Resources Partners
- Non-GAAP Financial Measures.” (3) Adjusted EBITDA is net income
attributable to Targa Resources Partners LP before: interest,
income taxes, depreciation and amortization, impairment of
goodwill, gains or losses on debt repurchases, redemptions,
amendments, exchanges and early debt extinguishments and asset
disposals, risk management activities related to derivative
instruments including the cash impact of hedges acquired in the
Partnership’s merger with Atlas Pipeline Partners, L.P. (the “APL
merger”), non-cash compensation on TRP equity grants,
transactions costs related to business acquisitions,
earnings/losses from unconsolidated affiliates net of
distributions, distributions from preferred interests and the
noncontrolling interest portion of depreciation and amortization
expenses. This is a non-GAAP financial measure and is discussed
under “Targa Resources Partners - Non-GAAP Financial Measures.”(4)
Distributable cash flow is net income attributable to Targa
Resources Partners LP plus depreciation and amortization,
impairment of goodwill, deferred taxes and amortization of debt
issuance costs included in interest expense, adjusted for non-cash
risk management activities related to derivative instruments
including the cash impact of hedges acquired in the APL merger,
financing activities, non-cash compensation on Partnership equity
grants, transaction costs related to acquisitions, earnings/losses
from unconsolidated affiliates net of distributions and asset
disposals, change in redemptive value of mandatorily redeemable
preferred interests and less maintenance capital expenditures (net
of any reimbursements of project costs). This measure includes any
impact of noncontrolling interests. This is a non-GAAP financial
measure and is discussed under “Targa Resources Partners - Non-GAAP
Financial Measures.”(5) Plant natural gas inlet represents the
volume of natural gas passing through the meter located at the
inlet of a natural gas processing plant, other than in Badlands,
where it represents total wellhead gathered volume. (6) Plant
natural gas inlet volumes include producer take-in-kind volumes,
while natural gas sales exclude producer take-in-kind volumes.(7)
These volume statistics are presented with the numerator as the
total volume sold during the quarter and the denominator as the
number of calendar days during the quarter.(8) Export volumes
represent the quantity of NGL products delivered to third party
customers at the Galena Park Marine terminal that are destined for
international markets.
Targa Resources Partners – Review of
Consolidated Results
Three Months Ended December 31, 2015 Compared to
Three Months Ended December 31, 2014
Revenues from commodity sales declined as the
effect of significantly lower commodity prices
($1,346.5 million) exceeded the favorable impacts of inclusion
of a full quarter of operations of TPL ($332.8 million), other
volume increases ($624.1 million), and favorable hedge
settlements ($23.5 million). Fee-based and other revenues increased
due to the inclusion of TPL’s fee revenue ($53.0 million), which
were partially offset by lower export fees.
Offsetting lower commodity revenues was a
commensurate reduction in product purchases due to significantly
lower commodity costs ($729.9 million), which were partially offset
by the inclusion of product purchases related to TPL’s operations
($290.5 million).
The higher gross margin in 2015 was attributable
to inclusion of TPL operations and increased throughput related to
other system expansions in our Field Gathering and Processing
segment, partially offset by lower LPG export and fractionation
margin and the expiration and recognition of a contract settlement
in 2014 in our Logistics and Marketing segments. Higher operating
expenses are due to the inclusion of TPL’s operations
($32.2 million), which more than offset the cost savings
generated throughout our other operating areas. See “—Targa
Resources Partners – Review of Segment Performance” for additional
information regarding changes in gross margin and operating margin
on a segment basis.
The increase in depreciation and amortization
expenses reflects the impact of TPL, the planned increased
amortization of the Badlands intangible assets and growth
investments placed in service after 2014, including the
international export expansion project, continuing development at
Badlands and other system expansions. During 2015, we recorded an
additional $32.6 million charge to depreciation to reflect an
impairment of certain gas processing facilities and associated
gathering systems in the Coastal Gathering and Processing segment
as a result of reduced forecasted processing volumes due to current
market conditions and processing spreads in Louisiana.
Lower general and administrative expenses are
primarily due to lower compensation and related costs
($11.8 million), which was partially offset by the inclusion
of TPL general and administrative costs ($10.9 million).
The increase in other operating gains during
2015 was primarily related to higher gains on sales of assets.
During 2015, we recognized a provisional loss of
$290.0 million associated with the impairment of goodwill in our
Field and Gathering segment.
The increase in net interest expense primarily
reflects higher borrowings attributable to the APL mergers and
lower capitalized interest associated with major capital projects
compared to 2014. These factors were partially offset by the change
in the redemption value ($30.6 million) of the mandatorily
redeemable preferred interests in the Partnership’s WestTX and
WestOK joint ventures acquired in the Atlas mergers.
During 2015, the gain on financing activities
was due primarily to the Partnership’s $3.6 million gain on
repurchase of debt. In 2014, the loss on financing activities was
due to the Partnership’s redemption of its 7⅞% senior notes.
Net income attributable to noncontrolling
interests decreased due to lower earnings in 2015 that impacted the
Partnership and its joint ventures at Cedar Bayou Fractionators,
VESCO and Versado. The inclusion of non-controlling interest from
TPL’s Centrahoma joint venture increased the net income
attributable to non-controlling interests.
Year Ended December 31, 2015 Compared to Year
Ended December 31, 2014
Revenues from commodity sales declined as the
effect of significantly lower commodity prices
($6,318.1 million) exceeded the favorable impacts of inclusion
of ten months of operations of TPL ($1,260.5 million), other
volume increases ($2,934.0 million), and favorable hedge
settlements ($84.2 million). Fee-based and other revenues increased
due to the inclusion of TPL’s fee revenue ($179.7 million), which
were partially offset by lower export fees.
Offsetting lower commodity revenues was a
commensurate reduction in product purchases due to significantly
lower commodity costs ($3,280.0 million). 2015 also included
product purchases related to TPL’s operations ($1,106.1
million).
The higher gross margin in 2015 was attributable
to inclusion of TPL operations, increased throughput related to
other system expansions in TRP’s Field Gathering and Processing
segment, recognition of a renegotiated commercial contract and
increased terminaling and storage fees, partially offset by lower
fractionation and export margin in TRP’s Logistics and Marketing
segments. Higher operating expenses are due to the inclusion of
TPL’s operations ($101.6 million), which more than offset the
cost savings generated throughout TRP’s other operating areas
($31.0 million). See “—Targa Resources Partners – Review of
Segment Performance” for additional information regarding changes
in gross margin and operating margin on a segment basis.
The increase in depreciation and amortization
expenses reflects the impact of TPL, the planned increased
amortization of the Badlands intangible assets and growth
investments placed in service after 2014, including the
international export expansion project, continuing development at
Badlands and other system expansions. During 2015, we recorded an
additional $32.6 million charge to depreciation to reflect an
impairment of certain gas processing facilities and associated
gathering systems in the Coastal Gathering and Processing segment
as a result of reduced forecasted processing volumes due to current
market conditions and processing spreads in Louisiana.
Higher general and administrative expenses is
due to the inclusion of TPL general and administrative costs
($32.1 million), which was partially offset by other general
and administrative reductions ($18.1 million), primarily from lower
compensation and related costs.
The increase in other operating gains during
2015 was primarily related to higher gains on sales of assets.
During 2015, we recognized a provisional loss of
$290.0 million associated with the impairment of goodwill in our
Field and Gathering segment.
The increase in net interest expense primarily
reflects higher borrowings attributable to the APL merger and lower
capitalized interest associated with major capital projects
compared to 2014. These factors were partially offset by the change
in the estimated redemption value ($30.6 million) of the
mandatorily redeemable preferred interests in the WestTX and WestOK
joint ventures acquired in the Atlas mergers.
During 2015, the gain on financing activities
was due primarily to $3.6 million in gains on repurchase of
debt offset by a $0.7 million loss the APL notes exchange offer. In
2014, the loss on financing activities was due to the redemption of
the Partnership’s 7⅞% senior notes.
Net income attributable to noncontrolling
interests decreased due to lower earnings in 2015 at the
Partnership’s joint ventures: Cedar Bayou Fractionators, VESCO and
Versado. The inclusion of non-controlling interest from TPL’s joint
ventures increased the net income attributable to noncontrolling
interests.
Targa Resources Partners – Review of
Segment Performance
The following discussion of segment performance
includes inter-segment revenues. The Partnership views segment
operating margin as an important performance measure of the core
profitability of its operations. This measure is a key component of
internal financial reporting and is reviewed for consistency and
trend analysis. For a discussion of operating margin, see “Targa
Resources Partners - Non-GAAP Financial Measures - 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. For all operating statistics presented,
the numerator is the total volume or sales during the applicable
reporting period and the denominator is the number of calendar days
during the applicable reporting period.
The Partnership reports its operations in two
divisions: (i) Gathering and Processing, consisting of two
reportable segments - (a) Field Gathering and Processing and (b)
Coastal Gathering and Processing; and (ii) Logistics and
Marketing, consisting of two reportable segments -
(a) Logistics Assets and (b) Marketing and Distribution.
The financial results of the Partnership’s commodity hedging
activities are reported in Other.
Field Gathering and
Processing
The Field Gathering and Processing segment's
assets are located in the Permian Basin of West Texas and Southeast
New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale
in North Texas; the Anadarko, Ardmore, and Arkoma Basins in
Oklahoma and South Central Kansas; and the Williston Basin in North
Dakota.
The following table provides summary data
regarding results of operations of this segment for the periods
indicated:
| |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
| |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
| |
|
($ in millions, except operating statistics
and price amounts) |
| Gross margin |
|
$ |
203.8 |
|
|
$ |
134.4 |
|
$ |
760.3 |
|
$ |
563.2 |
| Operating expenses |
|
|
69.0 |
|
|
|
52.0 |
|
|
275.5 |
|
|
190.9 |
| Operating margin |
|
$ |
134.8 |
|
|
$ |
82.4 |
|
$ |
484.8 |
|
$ |
372.3 |
| Operating
statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Plant natural gas
inlet, MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| SAOU (4)(5) |
|
|
241.3 |
|
|
|
221.7 |
|
|
234.0 |
|
|
193.1 |
| WestTX (6) |
|
|
462.0 |
|
|
|
- |
|
|
374.0 |
|
|
- |
| Sand Hills (5) |
|
|
154.0 |
|
|
|
167.3 |
|
|
163.0 |
|
|
165.1 |
| Versado |
|
|
185.9 |
|
|
|
180.6 |
|
|
183.2 |
|
|
169.6 |
| SouthTX (6) |
|
|
140.3 |
|
|
|
- |
|
|
120.0 |
|
|
- |
| North Texas (7) |
|
|
335.7 |
|
|
|
366.9 |
|
|
347.6 |
|
|
354.5 |
| SouthOK (6) |
|
|
470.7 |
|
|
|
- |
|
|
401.5 |
|
|
- |
| WestOK (6) |
|
|
510.3 |
|
|
|
- |
|
|
471.7 |
|
|
- |
| Badlands (8) |
|
|
56.9 |
|
|
|
37.9 |
|
|
49.2 |
|
|
38.9 |
| |
|
|
2,557.1 |
|
|
|
974.4 |
|
|
2,344.2 |
|
|
921.2 |
| Gross NGL production,
MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| SAOU |
|
|
27.6 |
|
|
|
25.7 |
|
|
27.3 |
|
|
25.2 |
| WestTX (6) |
|
|
53.2 |
|
|
|
- |
|
|
43.4 |
|
|
- |
| Sand Hills |
|
|
16.6 |
|
|
|
17.9 |
|
|
17.4 |
|
|
18.0 |
| Versado |
|
|
23.1 |
|
|
|
23.0 |
|
|
23.4 |
|
|
21.4 |
| SouthTX (6) |
|
|
15.5 |
|
|
|
- |
|
|
13.8 |
|
|
- |
| North Texas |
|
|
37.9 |
|
|
|
40.4 |
|
|
39.6 |
|
|
37.8 |
| SouthOK (6) |
|
|
41.8 |
|
|
|
- |
|
|
28.1 |
|
|
- |
| WestOK (6) |
|
|
26.6 |
|
|
|
- |
|
|
23.8 |
|
|
- |
| Badlands |
|
|
8.5 |
|
|
|
3.5 |
|
|
6.8 |
|
|
3.5 |
| |
|
|
250.8 |
|
|
|
110.5 |
|
|
223.6 |
|
|
105.9 |
| Crude oil gathered,
MBbl/d |
|
|
108.8 |
|
|
|
115.9 |
|
|
106.3 |
|
|
93.5 |
| Natural gas sales,
BBtu/d (3) |
|
|
1,436.2 |
|
|
|
515.0 |
|
|
1,340.8 |
|
|
469.0 |
| NGL sales, MBbl/d |
|
|
205.0 |
|
|
|
84.2 |
|
|
176.9 |
|
|
80.7 |
| Condensate sales,
MBbl/d |
|
|
8.0 |
|
|
|
3.3 |
|
|
8.3 |
|
|
3.6 |
| Average
realized prices (9): |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas,
$/MMBtu |
|
|
2.01 |
|
|
|
3.62 |
|
|
2.32 |
|
|
4.05 |
| NGL, $/gal |
|
|
0.30 |
|
|
|
0.53 |
|
|
0.34 |
|
|
0.72 |
| Condensate, $/Bbl |
|
|
34.97 |
|
|
|
63.46 |
|
|
41.29 |
|
|
82.35 |
_______(1) Segment operating statistics include the effect of
intersegment amounts, which have been eliminated from the
consolidated presentation. For all volume statistics presented, the
numerator is the total volume sold during the quarter and the
denominator is the number of calendar days during the quarter,
including the volumes related to plants acquired in the APL
merger.(2) Plant natural gas inlet represents TRP’s undivided
interest in the volume of natural gas passing through the meter
located at the inlet of a natural gas processing plant.(3) Plant
natural gas inlet volumes and gross NGL production volumes include
producer take-in-kind volumes, while natural gas sales exclude
producer take-in-kind volumes.(4) Includes volumes from the 200
MMcf/d cryogenic High Plains plant which started commercial
operations in June 2014.(5) Includes wellhead gathered volumes
moved from Sand Hills via pipeline to SAOU for processing.(6)
Operations acquired as part of the APL merger effective February
27, 2015.(7) Includes volumes from the 200 MMcf/d cryogenic
Longhorn plant which started commercial operations in May 2014.(8)
Badlands natural gas inlet represents the total wellhead gathered
volume.(9) Average realized prices exclude the impact of hedging
activities presented in Other.
Three Months Ended December 31, 2015 Compared to
Three Months Ended December 31, 2014
The increase in gross margin was primarily due
to the inclusion of the TPL volumes partially offset by
significantly lower commodity prices. The increases in plant inlet
volumes were primarily driven by the inclusion of TPL volumes and
by volume increases attributable to SAOU, Sand Hills (see footnote
(5) above) and Versado offset by reduced producer activity and
volumes in North Texas. Badlands crude oil volumes decreased
due to reduced producer activity. Badlands natural gas
volumes increased significantly primarily due to system expansions
and the Little Missouri 3 plant, which started commercial
operations in January 2015.
Excluding the increased operating expenses from
the TPL acquisition, other areas were significantly lower even
including system expansions due to a focused cost reduction
effort.
2015 Compared to 2014
The increase in gross margin was primarily due
to the inclusion of the TPL volumes along with other volume
increases partially offset by significantly lower commodity
prices. The increases in plant inlet volumes at SAOU, Sand
Hills (see footnote (5) above) and Versado were driven by system
expansions and by increased producer activity which increased
available supply across the Partnership’s areas of operation
partially offset by reduced producer activity and volumes in North
Texas. 2015 benefited from a full year operations of the
Longhorn plant in North Texas, the High Plains plant in SAOU and
the Little Missouri 3 plant in Badlands. Badlands crude oil
and natural gas volumes increased significantly due to plant and
system expansion and increased producer activity.
Excluding the increased operating expenses from
the TPL acquisition, other areas were significantly lower even
including system expansions due to a focused cost reduction
effort.
Gross Operating Statistics Compared to
Actual Reported
The table below provides a reconciliation
between gross operating statistics and the actual reported
operating statistics for the Field Gathering and Processing
segment:
| |
Year Ended December 31, 2015 |
| Operating
statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Plant natural gas
inlet, MMcf/d (1),(2) |
|
Gross Volume (3) |
|
Ownership % |
|
Net Volume (3) |
|
|
Pro Forma (4) |
|
|
Timing Adjustment (5) |
|
Actual Reported |
| SAOU |
|
234.0 |
|
|
100.0 |
% |
|
234.0 |
|
|
234.0 |
|
|
|
- |
|
|
234.0 |
| WestTX (6)(7) |
|
612.8 |
|
|
72.8 |
% |
|
446.1 |
|
|
446.1 |
|
|
|
(72.1 |
) |
|
374.0 |
| Sand Hills |
|
163.0 |
|
|
100.0 |
% |
|
163.0 |
|
|
163.0 |
|
|
|
- |
|
|
163.0 |
| Versado (8) |
|
183.2 |
|
|
63.0 |
% |
|
115.4 |
|
|
183.2 |
|
|
|
- |
|
|
183.2 |
| SouthTX (6) |
|
143.1 |
|
|
100.0 |
% |
|
143.1 |
|
|
143.1 |
|
|
|
(23.1 |
) |
|
120.0 |
| North Texas |
|
347.6 |
|
|
100.0 |
% |
|
347.6 |
|
|
347.6 |
|
|
|
- |
|
|
347.6 |
| SouthOK (6) |
|
478.9 |
|
|
Varies (9) |
|
398.6 |
|
|
478.9 |
|
|
|
(77.4 |
) |
|
401.5 |
| WestOK (6) |
|
562.6 |
|
|
100.0 |
% |
|
562.6 |
|
|
562.6 |
|
|
|
(90.9 |
) |
|
471.7 |
| Badlands (10) |
|
49.2 |
|
|
100.0 |
% |
|
49.2 |
|
|
49.2 |
|
|
|
- |
|
|
49.2 |
| Total |
|
2,774.5 |
|
|
|
2,459.7 |
|
|
2,607.8 |
|
|
|
(263.6 |
) |
|
2,344.2 |
| Gross NGL production,
MBbl/d (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SAOU |
|
27.3 |
|
|
100.0 |
% |
|
27.3 |
|
|
27.3 |
|
|
|
- |
|
|
27.3 |
| WestTX (6)(7) |
|
71.1 |
|
|
72.8 |
% |
|
51.8 |
|
|
51.8 |
|
|
|
(8.4 |
) |
|
43.4 |
| Sand Hills |
|
17.4 |
|
|
100.0 |
% |
|
17.4 |
|
|
17.4 |
|
|
|
- |
|
|
17.4 |
| Versado |
|
23.4 |
|
|
63.0 |
% |
|
14.7 |
|
|
23.4 |
|
|
|
- |
|
|
23.4 |
| SouthTX (6) |
|
16.5 |
|
|
100.0 |
% |
|
16.5 |
|
|
16.5 |
|
|
|
(2.7 |
) |
|
13.8 |
| North Texas |
|
39.6 |
|
|
100.0 |
% |
|
39.6 |
|
|
39.6 |
|
|
|
- |
|
|
39.6 |
| SouthOK (6) |
|
33.5 |
|
|
Varies (9) |
|
29.1 |
|
|
33.5 |
|
|
|
(5.4 |
) |
|
28.1 |
| WestOK (6) |
|
28.4 |
|
|
100.0 |
% |
|
28.4 |
|
|
28.4 |
|
|
|
(4.6 |
) |
|
23.8 |
| Badlands |
|
6.8 |
|
|
100.0 |
% |
|
6.8 |
|
|
6.8 |
|
|
|
- |
|
|
6.8 |
| Total |
|
264.0 |
|
|
|
231.5 |
|
|
244.6 |
|
|
|
(21.0 |
) |
|
223.6 |
_______(1) Plant natural gas inlet represents the volume of
natural gas passing through the meter located at the inlet of a
natural gas processing plant.(2) Plant natural gas inlet volumes
and gross NGL production volumes include producer take-in-kind
volumes, while natural gas sales exclude producer take-in-kind
volumes.(3) For these volume statistics presented, the numerator is
the total volume sold during the year and the denominator is the
number of calendar days during the year, other than for the volumes
related to the APL merger, for which the denominator is 306
days.(4) Pro forma statistics represents volumes per day while
owned by the Partnership.(5) Timing adjustment made to the Pro
forma statistics to adjust for the actual reported statistics based
on the full period.(6) Operations acquired as part of the APL
merger effective February 27, 2015.(7) Operating results for the
WestTX undivided interest assets are presented on a pro-rata net
basis in TRP’s reported financials. (8) Versado is a consolidated
subsidiary and its financial results are presented on a gross basis
in TRP’s reported financials.(9) SouthOK includes the Centrahoma
joint venture, of which TPL owns 60% and other plants which are
owned 100% by TPL. Centrahoma is a consolidated subsidiary and its
financial results are presented on a gross basis in TRP’s reported
financials.(10) Badlands natural gas inlet represents the total
wellhead gathered volume.
| |
Three Months Ended December 31,
2015 |
| Operating
statistics: |
|
|
|
|
|
|
|
|
| Plant natural gas
inlet, MMcf/d (1),(2) |
|
Gross Volume (3) |
|
Ownership % |
|
Net Volume (3) |
|
Actual Reported |
| SAOU |
|
241.3 |
|
|
100.0 |
% |
|
241.3 |
|
241.3 |
| WestTX (4)(5) |
|
634.6 |
|
|
72.8 |
% |
|
462.0 |
|
462.0 |
| Sand Hills |
|
154.0 |
|
|
100.0 |
% |
|
154.0 |
|
154.0 |
| Versado (6) |
|
185.9 |
|
|
63.0 |
% |
|
117.1 |
|
185.9 |
| SouthTX (4) |
|
140.3 |
|
|
100.0 |
% |
|
140.3 |
|
140.3 |
| North Texas |
|
335.7 |
|
|
100.0 |
% |
|
335.7 |
|
335.7 |
| SouthOK (4) |
|
470.7 |
|
|
Varies (7) |
|
388.9 |
|
470.7 |
| WestOK (4) |
|
510.3 |
|
|
100.0 |
% |
|
510.3 |
|
510.3 |
| Badlands (8) |
|
56.9 |
|
|
100.0 |
% |
|
56.9 |
|
56.9 |
| Total |
|
2,729.7 |
|
|
|
2,406.5 |
|
2,557.1 |
| Gross NGL production,
MBbl/d (2) |
|
|
|
|
|
|
|
|
| SAOU |
|
27.6 |
|
|
100.0 |
% |
|
27.6 |
|
27.6 |
| WestTX (4)(5) |
|
73.1 |
|
|
72.8 |
% |
|
53.2 |
|
53.2 |
| Sand Hills |
|
16.6 |
|
|
100.0 |
% |
|
16.6 |
|
16.6 |
| Versado |
|
23.1 |
|
|
63.0 |
% |
|
14.6 |
|
23.1 |
| SouthTX (4) |
|
15.5 |
|
|
100.0 |
% |
|
15.5 |
|
15.5 |
| North Texas |
|
37.9 |
|
|
100.0 |
% |
|
37.9 |
|
37.9 |
| SouthOK (4) |
|
41.8 |
|
|
Varies (7) |
|
35.1 |
|
41.8 |
| WestOK (4) |
|
26.6 |
|
|
100.0 |
% |
|
26.6 |
|
26.6 |
| Badlands |
|
8.5 |
|
|
100.0 |
% |
|
8.5 |
|
8.5 |
| Total |
|
270.7 |
|
|
|
235.6 |
|
250.8 |
_______(1) Plant natural gas inlet represents the volume of
natural gas passing through the meter located at the inlet of a
natural gas processing plant.(2) Plant natural gas inlet volumes
and gross NGL production volumes include producer take-in-kind
volumes, while natural gas sales exclude producer take-in-kind
volumes.(3) For these volume statistics presented, the numerator is
the total volume sold during the year and the denominator is the
number of calendar days during the year.(4) Operations acquired as
part of the APL merger effective February 27, 2015.(5) Operating
results for the WestTX undivided interest assets are presented on a
pro-rata net basis in TRP’s reported financials. (6) Versado is a
consolidated subsidiary and its financial results are presented on
a gross basis in TRP’s reported financials.(7) SouthOK includes the
Centrahoma joint venture, of which TPL owns 60% and other plants
which are owned 100% by TPL. Centrahoma is a consolidated
subsidiary and its financial results are presented on a gross basis
in TRP’s reported financials.(8) Badlands natural gas inlet
represents the total wellhead gathered volume.
Coastal Gathering and
Processing
The Coastal Gathering and Processing segment
assets are located in the onshore and near offshore region of the
Louisiana Gulf Coast, accessing natural gas from the Gulf Coast and
the Gulf of Mexico. With the strategic location of the
Partnership’s assets in Louisiana, it has access to the Henry Hub,
the largest natural gas hub in the U.S., and to a substantial NGL
distribution system with access to markets throughout Louisiana and
the Southeast United States.
The following table provides summary data
regarding results of operations of this segment for the periods
indicated:
| |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
| |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
| |
|
($ in millions, except operating statistics
and price amounts) |
| Gross margin |
|
$ |
17.2 |
|
$ |
21.9 |
|
$ |
69.8 |
|
$ |
123.8 |
| Operating expenses |
|
|
9.0 |
|
|
11.1 |
|
|
39.5 |
|
|
46.2 |
| Operating margin |
|
$ |
8.2 |
|
$ |
10.8 |
|
$ |
30.3 |
|
$ |
77.6 |
| Operating
statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
| Plant natural gas
inlet, MMcf/d (2),(3) |
|
|
|
|
|
|
|
|
|
|
|
|
| LOU |
|
|
278.1 |
|
|
213.9 |
|
|
200.1 |
|
|
284.6 |
| VESCO |
|
|
452.8 |
|
|
491.4 |
|
|
442.4 |
|
|
509.0 |
| Other Coastal Straddles |
|
|
184.0 |
|
|
424.8 |
|
|
254.5 |
|
|
394.8 |
| |
|
|
914.9 |
|
|
1,130.1 |
|
|
897.0 |
|
|
1,188.4 |
| Gross NGL production,
MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
| LOU |
|
|
8.5 |
|
|
7.1 |
|
|
7.2 |
|
|
9.0 |
| VESCO |
|
|
29.5 |
|
|
25.1 |
|
|
26.6 |
|
|
26.0 |
| Other Coastal Straddles |
|
|
6.0 |
|
|
12.8 |
|
|
8.0 |
|
|
12.1 |
| |
|
|
44.0 |
|
|
45.0 |
|
|
41.8 |
|
|
47.1 |
| Natural gas sales,
BBtu/d (3) |
|
|
254.0 |
|
|
233.0 |
|
|
237.1 |
|
|
258.0 |
| NGL sales, MBbl/d |
|
|
32.5 |
|
|
36.5 |
|
|
31.4 |
|
|
40.2 |
| Condensate sales,
MBbl/d |
|
|
1.0 |
|
|
0.9 |
|
|
0.8 |
|
|
0.7 |
| Average
realized prices: |
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas,
$/MMBtu |
|
|
2.26 |
|
|
3.97 |
|
|
2.69 |
|
|
4.44 |
| NGL, $/gal |
|
|
0.36 |
|
|
0.59 |
|
|
0.39 |
|
|
0.80 |
| Condensate, $/Bbl |
|
|
38.30 |
|
|
68.43 |
|
|
47.72 |
|
|
89.70 |
__________(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 during the applicable reporting period and the
denominator is the number of calendar days during the applicable
reporting period.(2) Plant natural gas inlet represents the volume
of natural gas passing through the meter located at the inlet of a
natural gas processing plant.(3) Plant natural gas inlet volumes
and gross NGL production volumes include producer take-in-kind
volumes, while natural gas sales exclude producer take-in-kind
volumes.
Three Months Ended December 31, 2015 Compared to
Three Months Ended December 31, 2014
The decrease in Coastal Gathering and Processing
gross margin was primarily due to lower NGL prices, a less
favorable frac spread and lower throughput volumes. The overall
decrease in plant inlet volumes was largely attributable to current
market conditions and the decline of leaner off-system supply
volumes partially offset by the availability of short-term
off-system volumes at LOU.
Operating expenses decreased primarily due to
reduced volumes and lower plant run-time due to current market
conditions.
2015 Compared to 2014
The decrease in Coastal Gathering and Processing
gross margin was primarily due to lower NGL prices, a less
favorable frac spread and lower throughput volumes partially offset
by new volumes at LOU and VESCO with higher average GPM.
Operating expenses decreased primarily due to
reduced volumes and lower plant run-time due to current market
conditions.
Logistics and Marketing
Segments
Logistics Assets
The Logistics Assets segment is involved in
transporting, storing, and fractionating mixed NGLs; storing,
terminaling, and transporting finished NGLs, including services for
the LPG export market; and storing and terminaling refined
petroleum products. These assets are generally connected to and
supplied in part by the Partnership’s Gathering and Processing
segments and are predominantly located in Mont Belvieu and Galena
Park, Texas and Lake Charles, Louisiana.
The following table provides summary data
regarding results of operations of this segment for the periods
indicated:
| |
|
Three Months Ended December 31, |
|
|
Year Ended December 31, |
| |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
| |
|
($ in millions, except operating
statistics) |
| Gross margin (1) |
|
$ |
139.3 |
|
$ |
164.1 |
|
|
$ |
613.9 |
|
$ |
613.3 |
| Operating expenses
(1) |
|
|
41.5 |
|
|
43.1 |
|
|
|
174.4 |
|
|
168.2 |
| Operating margin |
|
$ |
97.8 |
|
$ |
121.0 |
|
|
$ |
439.5 |
|
$ |
445.1 |
| Operating
statistics, MBbl/d (2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fractionation volumes
(3) |
|
|
327.7 |
|
|
371.7 |
|
|
|
342.7 |
|
|
350.0 |
| LSNG treating
volumes |
|
|
21.5 |
|
|
21.2 |
|
|
|
22.4 |
|
|
23.4 |
| Benzene treating
volumes |
|
|
21.5 |
|
|
21.2 |
|
|
|
22.4 |
|
|
23.4 |
_______(1) Fractionation and treating contracts include pricing
terms composed of base fees and fuel and power components which
vary with the cost of energy. As such, the logistics segment
results include effects of variable energy costs that impact both
gross margin and operating expenses. (2) Segment operating
statistics include intersegment amounts, which have been eliminated
from the consolidated presentation. For all volume statistics
presented, the numerator is the total volume sold during the year
and the denominator is the number of calendar days during the
year.(3) Fractionation volumes reflect those volumes delivered and
settled under fractionation contracts.
Three Months Ended December 31, 2015 Compared to
Three Months Ended December 31, 2014
Logistics Assets gross margin decreased
primarily due to lower LPG export and fractionation margin, and
decreased terminaling and storage activities. LPG export
volumes (which are reflected in both the Logistics Assets and
Marketing and Distribution segments) averaged 192 MBbl/d in the
fourth quarter of 2015 compared to a record 225 MBbl/d for the
same period last year. Fractionation gross margin was
impacted by the variable effects of fuel and power, which are
largely reflected in lower operating expenses (see footnote (1)
above), and by a decrease in supply volume. Terminaling and storage
volumes decreased due to lower customer throughput.
Operating expenses decreased due to lower fuel
and power expense and lower export-related costs, partially offset
by lower system product gains and higher maintenance costs.
2015 Compared to 2014
Logistics Assets gross margin was flat due to
the recognition of the renegotiated commercial arrangements related
to the Partnership’s Channelview Splitter project and increased
terminaling and storage activities offset by lower LPG export and
fractionation margins. Slightly higher LPG export volumes (which
are reflected in both the Logistics Assets and Marketing and
Distribution segments), averaged 183 MBbl/d in 2015 compared to 177
MBbl/d last year.
Fractionation gross margin was lower due to the
variable effects of fuel and power, which are largely reflected in
lower operating expenses (see footnote (1) above), and by a
decrease in supply volume. Terminaling and storage volumes
increased due to higher customer throughput.
Operating expenses increased due to lower system
product gains and higher maintenance, partially offset by lower
fuel and power expense and lower export-related costs.
Marketing and Distribution
The Marketing and Distribution segment covers
all activities required to distribute and market raw and finished
natural gas liquids and all natural gas marketing activities. It
includes: (1) marketing the Partnership’s natural gas liquids
production and purchasing natural gas liquids products in selected
United States markets; (2) providing LPG balancing services to
refinery customers; (3) transporting, storing and selling
propane and providing related propane logistics services to
multi-state retailers, independent retailers and other end-users;
(4) providing propane, butane and services to LPG exporters;
and (5) marketing natural gas available to the Partnership
from its Gathering and Processing division and the purchase and
resale and other value added activities related to third-party
natural gas in selected United States markets.
The following table provides summary data
regarding results of operations of this segment for the periods
indicated:
| |
|
Three Months Ended December 31, |
|
|
Year Ended December 31, |
| |
|
2015 |
|
2014 |
|
|
2015 |
|
2014 |
| |
|
($ in millions, except operating statistics
and price amounts) |
| Gross margin |
|
$ |
74.4 |
|
$ |
80.9 |
|
$ |
283.8 |
|
$ |
298.0 |
| Operating expenses |
|
|
9.5 |
|
|
10.7 |
|
|
41.6 |
|
|
48.4 |
| Operating margin |
|
$ |
64.9 |
|
$ |
70.2 |
|
$ |
242.2 |
|
$ |
249.6 |
| Operating
statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
| NGL sales, MBbl/d |
|
|
450.2 |
|
|
476.1 |
|
|
432.3 |
|
|
423.3 |
| Average
realized prices: |
|
|
|
|
|
|
|
|
|
|
|
|
| NGL realized price,
$/gal |
|
|
0.44 |
|
|
0.74 |
|
|
0.46 |
|
|
0.93 |
________(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 applicable reporting period and
the denominator is the number of calendar days during the
applicable reporting period.
Three Months Ended December 31, 2015 Compared to
Three Months Ended December 31, 2014
Marketing and Distribution gross margin
decreased primarily due to lower LPG export volumes (which are
reflected in both Logistics Assets and Marketing and Distribution
segments), the expiration and recognition of a contract settlement
in 2014 and a lower price environment. The lower gross margin
was partially offset by higher marketing gains.
Operating expenses decreased primarily due to
lower terminal expense.
2015 Compared to 2014
Marketing and Distribution gross margin
decreased primarily due to a lower price environment and the
expiration and recognition of a contract settlement in 2014.
The lower gross margin was partially offset by higher LPG export
margin, higher marketing gains and higher terminal activity.
Slightly higher LPG export volumes are reflected in both the
Logistics Assets and Marketing and Distribution segments.
Operating expenses decreased due to lower barge
expense and lower terminal expense.
Other
| |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
| |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
(In millions) |
| Gross margin |
|
$ |
23.5 |
|
$ |
4.4 |
|
$ |
84.2 |
|
$ |
|
(8.0 |
) |
| Operating margin |
|
$ |
23.5 |
|
$ |
4.4 |
|
$ |
84.2 |
|
$ |
|
(8.0 |
) |
Other contains the results (including any hedge
ineffectiveness) of commodity derivative activities included in
operating margin and mark-to-market gain/losses related to
derivative contracts that were not designated as cash-flow hedges.
Eliminations of inter-segment transactions are reflected in the
corporate and eliminations column. The primary purpose of our
commodity risk management activities is to mitigate a portion of
the impact of commodity prices on our operating cash flow. The
Partnership has hedged the commodity price associated with a
portion of its expected (i) natural gas equity volumes in Field
Gathering and Processing Operations and (ii) NGL and condensate
equity volumes predominately in Field Gathering and Processing as
well as in the LOU portion of the Coastal Gathering and Processing
Operations that result from percent of proceeds or liquid
processing arrangements by entering into derivative instruments.
Because the Partnership is essentially forward-selling a portion of
its plant equity volumes, these hedge positions will move favorably
in periods of falling commodity prices and unfavorably in periods
of rising commodity prices.
The following table provides a breakdown of the
change in Other operating margin:
|
|
Three Months Ended December 31,
2015 |
|
Three Months Ended December 31,
2014 |
|
|
(In millions, except volumetric data and price
amounts) |
|
|
Volume Settled |
|
Price Spread (1) |
|
Gain (Loss) |
|
Volume Settled |
|
Price Spread (1) |
|
Gain (Loss) |
| Natural Gas (BBtu) |
16.8 |
$ |
0.85 |
$ |
|
14.3 |
|
|
6.1 |
$ |
0.17 |
$ |
|
1.1 |
|
| NGL (MMBbl) |
0.3 |
|
13.33 |
|
|
4.0 |
|
|
0.2 |
|
11.86 |
|
|
2.9 |
|
| Crude Oil (MMBbl) |
0.2 |
|
39.00 |
|
|
7.8 |
|
|
0.2 |
|
18.74 |
|
|
4.2 |
|
| Non-Hedge Accounting
(2) |
|
|
|
|
|
(2.2 |
) |
|
|
|
|
|
|
(3.8 |
) |
| Ineffectiveness
(3) |
|
|
|
|
|
(0.4 |
) |
|
|
|
|
|
|
- |
|
| |
|
|
|
$ |
|
23.5 |
|
|
|
|
|
$ |
|
4.4 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015 |
|
Year Ended December 31, 2014 |
|
|
(In millions, except volumetric data and price
amounts) |
|
|
Volume Settled |
|
Price Spread (1) |
|
Gain (Loss) |
|
Volume Settled |
|
Price Spread (1) |
|
Gain (Loss) |
| Natural Gas (BBtu) |
51.8 |
$ |
0.71/MMBtu |
$ |
|
37.0 |
|
|
21.9 |
$ |
(0.27)/MMBtu |
$ |
|
(5.9 |
) |
| NGL (MMBbl) |
76.4 |
|
0.29/Bbl |
|
|
22.1 |
|
|
0.6 |
|
5.79/Bbl |
|
|
3.6 |
|
| Crude Oil (MMBbl) |
0.8 |
|
9.37/Bbl |
|
|
21.6 |
|
|
0.9 |
|
(1.07)/Bbl |
|
|
(1.0 |
) |
| Non-Hedge Accounting
(2) |
|
|
|
|
|
2.6 |
|
|
|
|
|
|
|
(4.8 |
) |
| Ineffectiveness
(3) |
|
|
|
|
|
0.9 |
|
|
|
|
|
|
|
0.1 |
|
| |
|
|
|
$ |
|
84.2 |
|
|
|
|
|
$ |
|
(8.0 |
) |
______________(1) The price spread is the differential between
the contracted derivative instrument pricing and the price of the
corresponding settled commodity transaction.(2) Mark-to-market
income (loss) associated with derivative contracts that are not
designated as hedges for accounting purposes.(3) Ineffectiveness
primarily relates to certain crude hedging contracts and certain
acquired hedges of APL that do not qualify for hedge
accounting.
As part of the Atlas mergers, outstanding APL
derivative contracts with a fair value of $102.1 million as of the
acquisition date were novated to the Partnership and included in
the acquisition date fair value of assets acquired. Derivative
settlements of $67.9 million related to these novated contracts
were received during the year ended December 31, 2015 and were
reflected as a reduction of the acquisition date fair value of the
APL derivative assets acquired, with no effect on results of
operations.
About Targa Resources Corp. and Targa
Resources Partners
Targa Resources Partners LP is a Delaware
limited partnership formed in October 2006 by its parent, Targa
Resources Corp., to own, operate, acquire and develop a diversified
portfolio of complementary midstream energy assets. On February 17,
2016 TRC completed the acquisition of all outstanding common units
of the Partnership. Targa Resources Corp. is a leading provider of
midstream services and is one of the largest independent midstream
energy companies in North America. TRC owns, operates, acquires,
and develops a diversified portfolio of complementary midstream
energy assets. The Company is primarily engaged in the business of:
gathering, compressing, treating, processing, and selling natural
gas; storing, fractionating, treating, transporting, and selling
NGLs and NGL products, including services to LPG exporters;
gathering, storing, and terminaling crude oil; storing,
terminaling, and selling refined petroleum products.
The principal executive offices of TRC are
located at 1000 Louisiana, Suite 4300, Houston, TX 77002 and their
telephone number is 713-584-1000. For more information please
go to www.targaresources.com.
On February 17, 2016, TRC completed the
previously announced transactions contemplated by the TRC/TRP
Merger Agreement, by and among TRP, Targa Resources GP LLC, TRC and
Merger Sub pursuant to which TRC acquired indirectly all of TRP’s
outstanding common units that TRC and its subsidiaries did not
already own. Upon the terms and conditions set forth in the Merger
Agreement, Merger Sub merged with and into TRP, with TRP continuing
as the surviving entity and as a subsidiary of TRC. As a result of
the TRC/TRP Merger, TRC owns all of TRP’s outstanding common
units.
At the effective time of the TRC/TRP Merger,
each outstanding TRP common unit not owned by TRC or its
subsidiaries was converted into the right to receive 0.62 shares of
common stock of TRC, par value $0.001 per share. No fractional TRC
shares were issued in the TRC/TRP Merger, and TRP common
unitholders, instead received cash in lieu of fractional TRC
shares.
Pursuant to the TRC/TRP Merger Agreement, TRC
has agreed to cause TRP’s common units to be delisted from the NYSE
and deregistered under the Exchange Act. As a result of the
completion of the TRC/TRP Merger, TRP’s common units are no longer
publicly traded. The Series A Preferred Units remain outstanding as
limited partner interests in TRP and continue to trade on the NYSE
under the symbol “NGLS PRA.”
Targa Resources Partners - Non-GAAP
Financial Measures
This press release includes the Partnership’s
non-GAAP financial measures distributable cash flow, Adjusted
EBITDA, gross margin and operating margin. The following tables
provide reconciliations of these non-GAAP financial measures to
their most directly comparable GAAP measures. The Partnership’s
non-GAAP financial measures should not be considered as
alternatives to GAAP measures such as net income, operating income,
net cash flows provided by operating activities or any other GAAP
measure of liquidity or financial performance.
Distributable Cash Flow - The
Partnership defines distributable cash flow as net income
attributable to Targa Resources Partners LP plus depreciation and
amortization, impairment of goodwill, deferred taxes and
amortization of debt issue costs included in interest expense,
adjusted for non-cash risk management activities related to
derivative instruments including the cash impact of hedges acquired
in the APL merger; debt repurchases, redemptions, amendments,
exchanges and early debt extinguishments, non-cash compensation on
Partnership equity grants, changes in fair value of contingent
consideration and mandatory redeemable preferred interests,
transaction costs related to acquisitions, earnings/losses from
unconsolidated affiliates net of distributions and asset disposals
and less maintenance capital expenditures (net of any
reimbursements of project costs). This measure includes any impact
of noncontrolling interests.
Distributable cash flow is a significant
performance metric used by the Partnership and by external users of
its financial statements, such as investors, commercial banks and
research analysts to compare basic cash flows generated by the
Partnership (prior to the establishment of any retained cash
reserves by the board of directors of the Partnership’s general
partner) to the cash distributions it expects to pay its
unitholders. Using this metric, management and external users of
the Partnership’s financial statements can quickly compute the
coverage ratio of estimated cash flows to cash distributions.
Distributable cash flow is also an important financial measure for
the Partnership’s unitholders since it serves as an indicator of
the Partnership’s success in providing a cash return on investment.
Specifically, this financial measure indicates to investors whether
or not the Partnership is generating cash flow at a level that can
sustain or support an increase in its quarterly distribution rates.
Distributable cash flow is also a quantitative standard used
throughout the investment community with respect to publicly-traded
partnerships and limited liability companies because the value of a
unit of such an entity is generally determined by the unit’s yield
(which in turn is based on the amount of cash distributions the
entity pays to a unitholder).
Distributable cash flow is a non-GAAP financial
measure. The GAAP measure most directly comparable to distributable
cash flow is net income attributable to Targa Resources Partners
LP. Distributable cash flow should not be considered as an
alternative to GAAP net income attributable to Targa Resources
Partners LP. It has important limitations as an analytical tool.
Investors should not consider distributable cash flow in isolation
or as a substitute for analysis of the Partnership’s results as
reported under GAAP. Because distributable cash flow excludes some,
but not all, items that affect net income and is defined
differently by different companies in the Partnership’s industry,
the Partnership’s definition of distributable cash flow may not be
comparable to similarly titled measures of other companies, thereby
diminishing its utility.
Management compensates for the limitations of
distributable cash flow as an analytical tool by reviewing the
comparable GAAP measure, understanding the differences between the
measures and incorporating these insights into its decision-making
processes.
The following table presents a reconciliation of net income of
the Partnership to distributable cash flow for the periods
indicated:
| |
|
|
Three Months Ended December 31, |
|
Year Ended December 31, |
| |
|
|
2015 |
|
2014 |
|
2015 |
|
2014 |
| |
|
|
|
(In millions) |
|
(In millions) |
|
Reconciliation of net income to Distributable Cash
flow: |
|
|
|
|
|
|
|
|
|
|
|
|
| Net income
attributable to Targa Resources Partners LP |
|
$ |
|
(190.1 |
) |
|
$ |
|
108.2 |
|
|
$ |
|
(23.0 |
) |
|
$ |
|
467.7 |
|
|
Depreciation and amortization expenses |
|
|
|
228.8 |
|
|
|
|
93.7 |
|
|
|
|
677.1 |
|
|
|
|
346.5 |
|
| Goodwill
impairments |
|
|
|
290.0 |
|
|
|
|
- |
|
|
|
|
290.0 |
|
|
|
|
- |
|
| Deferred
income tax expense (benefit) |
|
|
|
0.1 |
|
|
|
|
0.5 |
|
|
|
|
(0.2 |
) |
|
|
|
1.6 |
|
| Non-cash
interest expense, net (1) |
|
|
|
3.3 |
|
|
|
|
2.5 |
|
|
|
|
12.6 |
|
|
|
|
11.2 |
|
| Loss from
financing activities |
|
|
|
(3.3 |
) |
|
|
|
12.4 |
|
|
|
|
(2.8 |
) |
|
|
|
12.4 |
|
| (Earnings)
loss from unconsolidated affiliates (2) |
|
|
|
1.4 |
|
|
|
|
(4.3 |
) |
|
|
|
2.5 |
|
|
|
|
(18.0 |
) |
|
Distributions from unconsolidated affiliates (2) |
|
|
|
3.8 |
|
|
|
|
4.3 |
|
|
|
|
15.0 |
|
|
|
|
18.0 |
|
|
Compensation on TRP equity grants (2) |
|
|
|
3.8 |
|
|
|
|
2.2 |
|
|
|
|
16.6 |
|
|
|
|
9.2 |
|
| Change in
redemption value of other long-term liabilities |
|
|
|
(30.6 |
) |
|
|
|
- |
|
|
|
|
(30.6 |
) |
|
|
|
- |
|
| Change in
contingent consideration |
|
|
|
(1.2 |
) |
|
|
|
- |
|
|
|
|
(1.2 |
) |
|
|
|
- |
|
| (Gain) loss
on sale or disposition of assets |
|
|
|
(7.8 |
) |
|
|
|
0.8 |
|
|
|
|
(8.0 |
) |
|
|
|
(4.8 |
) |
| Risk
management activities |
|
|
|
18.8 |
|
|
|
|
3.8 |
|
|
|
|
64.8 |
|
|
|
|
4.7 |
|
| Maintenance
capital expenditures |
|
|
|
(24.9 |
) |
|
|
|
(23.6 |
) |
|
|
|
(97.9 |
) |
|
|
|
(79.1 |
) |
|
Transactions costs related to business acquisitions (2) |
|
|
|
(0.1 |
) |
|
|
|
- |
|
|
|
|
14.8 |
|
|
|
|
- |
|
| Other
(3) |
|
|
|
(55.0 |
) |
|
|
|
(1.2 |
) |
|
|
|
(61.9 |
) |
|
|
|
(6.2 |
) |
| Targa
Resources Partners LP distributable cash flow |
|
$ |
|
237.0 |
|
|
$ |
|
199.3 |
|
|
$ |
|
867.8 |
|
|
$ |
|
763.2 |
|
_______(1) Includes
amortization of debt issuance costs, discount and premium.(2) The
definition of Adjusted EBITDA was changed in 2014 to exclude
non-cash compensation on equity grants and in 2015 to exclude
earnings from unconsolidated investments net of distributions and
transaction costs related to business acquisitions.(3) Includes the
noncontrolling interests portion of maintenance capital
expenditures, depreciation and amortization expenses.
Adjusted
EBITDA - The Partnership defines Adjusted EBITDA
as net income attributable to Targa Resources Partners LP before:
interest; income taxes; depreciation and amortization; impairment
of goodwill; gains or losses on debt repurchases, redemptions,
amendments, exchanges and early debt extinguishments and asset
disposals; risk management activities related to derivative
instruments including the cash impact of hedges acquired in the APL
merger; non-cash compensation on Partnership equity grants;
transaction costs related to business acquisitions; earnings/losses
from unconsolidated affiliates net of distributions, distributions
from preferred interests and the noncontrolling interest portion of
depreciation and amortization expenses. Adjusted EBITDA is used as
a supplemental financial measure by the Partnership and by external
users of its financial statements such as investors, commercial
banks and others. The economic substance behind management’s use of
Adjusted EBITDA is to measure the ability of its assets to generate
cash sufficient to pay interest costs, support its indebtedness and
make distributions to its investors.
Adjusted EBITDA is a non-GAAP financial measure.
The GAAP measures most directly comparable to Adjusted EBITDA are
net cash provided by operating activities and net income
attributable to Targa Resources Partners LP. Adjusted EBITDA should
not be considered as an alternative to GAAP net cash provided by
operating activities or GAAP net income. Adjusted EBITDA has
important limitations as an analytical tool. Investors should not
consider Adjusted EBITDA in isolation or as a substitute for
analysis of the Partnership’s results as reported under GAAP.
Because Adjusted EBITDA excludes some, but not all, items that
affect net income and net cash provided by operating activities and
is defined differently by different companies in the Partnership’s
industry, the Partnership’s definition of Adjusted EBITDA may not
be comparable to similarly titled measures of other companies,
thereby diminishing its utility.
Management compensates for the limitations of
Adjusted EBITDA as an analytical tool by reviewing the comparable
GAAP measures, understanding the differences between the measures
and incorporating these insights into its decision-making
processes.
The following table presents a reconciliation of
net income of the Partnership to Adjusted EBITDA for the periods
indicated:
|
|
|
Three Months Ended December 31, |
|
Year Ended December 31, |
| |
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
| |
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
(In millions) |
| Reconciliation
of Net Income to Adjusted EBITDA |
|
|
|
|
|
|
|
|
|
|
|
| Net income attributable
to Targa Resources Partners LP |
|
$ |
|
(190.1 |
) |
|
$ |
|
108.2 |
|
$ |
|
(23.0 |
) |
|
$ |
|
467.7 |
|
| Interest expense, net |
|
|
|
30.6 |
|
|
|
|
39.7 |
|
|
|
207.8 |
|
|
|
|
143.8 |
|
| Income tax expense |
|
|
|
0.2 |
|
|
|
|
1.1 |
|
|
|
0.6 |
|
|
|
|
4.8 |
|
| Depreciation and amortization
expenses |
|
|
|
228.8 |
|
|
|
|
93.7 |
|
|
|
677.1 |
|
|
|
|
346.5 |
|
| Provisional goodwill
impairment |
|
|
|
290.0 |
|
|
|
|
- |
|
|
|
290.0 |
|
|
|
|
- |
|
| (Gain) loss on sale or disposition
of assets |
|
|
|
(7.8 |
) |
|
|
|
0.8 |
|
|
|
(8.0 |
) |
|
|
|
(4.8 |
) |
| (Gain) Loss from financing
activities |
|
|
|
(3.3 |
) |
|
|
|
12.4 |
|
|
|
(2.8 |
) |
|
|
|
12.4 |
|
| (Earnings) loss from unconsolidated
affiliates (1) |
|
|
|
1.4 |
|
|
|
|
(4.3 |
) |
|
|
2.5 |
|
|
|
|
(18.0 |
) |
| Distributions from unconsolidated
affiliates and preferred partner interests (1) |
|
|
|
9.9 |
|
|
|
|
4.3 |
|
|
|
21.1 |
|
|
|
|
18.0 |
|
| Change in contingent
consideration |
|
|
|
(1.2 |
) |
|
|
|
- |
|
|
|
(1.2 |
) |
|
|
|
- |
|
| Compensation on TRP equity grants
(1) |
|
|
|
3.8 |
|
|
|
|
2.2 |
|
|
|
16.6 |
|
|
|
|
9.2 |
|
| Transaction costs related to
business acquisitions (1) |
|
|
|
(0.1 |
) |
|
|
|
- |
|
|
|
14.8 |
|
|
|
|
- |
|
| Risk management activities |
|
|
|
18.8 |
|
|
|
|
3.8 |
|
|
|
64.8 |
|
|
|
|
4.7 |
|
| Other |
|
|
|
- |
|
|
|
|
- |
|
|
|
0.6 |
|
|
|
|
- |
|
| Noncontrolling interests adjustment
(2) |
|
|
|
(56.3 |
) |
|
|
|
(3.6 |
) |
|
|
(69.7 |
) |
|
|
|
(14.0 |
) |
| Targa Resources
Partners LP Adjusted EBITDA |
|
$ |
|
324.7 |
|
|
$ |
|
258.3 |
|
$ |
|
1,191.2 |
|
|
$ |
|
970.3 |
|
_________(1) The definition of Adjusted EBITDA
was changed in 2014 to exclude non-cash compensation on equity
grants and in 2015 to exclude earnings from unconsolidated
investments net of distributions and transaction costs related to
business acquisitions.(2) Noncontrolling interest portion of
depreciation and amortization expenses.
The following table presents a reconciliation of
net cash provided by Targa Resources Partners L.P. operating
activities to Adjusted EBITDA for the periods indicated:
| |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
| |
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
| |
|
|
|
|
|
|
|
|
|
|
|
| |
|
(In millions) |
|
Reconciliation of net cash provided by Targa
Resources |
|
|
|
|
|
|
|
|
|
|
| Partners LP operating
activities to Adjusted EBITDA: |
|
|
|
|
|
|
|
|
|
|
|
| Net cash provided by
operating activities |
|
$ |
|
346.1 |
|
|
$ |
|
266.8 |
|
$ |
|
1,083.9 |
|
|
$ |
|
838.5 |
|
| Net income attributable
to noncontrolling interests |
|
|
|
49.2 |
|
|
|
|
(6.5 |
) |
|
|
31.9 |
|
|
|
|
(37.4 |
) |
| Interest expense |
|
|
|
30.6 |
|
|
|
|
39.7 |
|
|
|
207.8 |
|
|
|
|
143.8 |
|
| Non-cash interest
expense, net (1) |
|
|
|
(3.3 |
) |
|
|
|
(2.4 |
) |
|
|
(12.6 |
) |
|
|
|
(11.2 |
) |
| (Earnings) loss from
unconsolidated affiliates (2) |
|
|
|
1.4 |
|
|
|
|
(4.3 |
) |
|
|
2.5 |
|
|
|
|
(18.0 |
) |
| Distributions from
unconsolidated affiliates and preferred interests (2) |
|
|
|
9.9 |
|
|
|
|
4.3 |
|
|
|
21.1 |
|
|
|
|
18.0 |
|
| Transaction costs
related to business acquisitions (2) |
|
|
|
(0.1 |
) |
|
|
|
- |
|
|
|
14.8 |
|
|
|
|
| Current income tax
expense |
|
|
|
0.1 |
|
|
|
|
0.6 |
|
|
|
0.8 |
|
|
|
|
3.2 |
|
| Other (3) |
|
|
|
(32.5 |
) |
|
|
|
(4.7 |
) |
|
|
(67.6 |
) |
|
|
|
(18.4 |
) |
| Changes in operating
assets and liabilities which used (provided) cash: |
|
|
|
|
|
|
|
|
|
|
|
| Accounts receivable and other
assets |
|
|
|
(97.0 |
) |
|
|
|
(214.5 |
) |
|
|
(254.9 |
) |
|
|
|
(58.6 |
) |
| Accounts payable and other
liabilities |
|
|
|
20.3 |
|
|
|
|
179.3 |
|
|
|
163.5 |
|
|
|
|
110.4 |
|
| Targa Resources
Partners LP Adjusted EBITDA |
|
$ |
|
324.7 |
|
|
$ |
|
258.3 |
|
$ |
|
1,191.2 |
|
|
$ |
|
970.3 |
|
________(1) Includes amortization of debt issuance costs,
discount and premium.(2) The definition of Adjusted EBITDA was
changed in 2014 to exclude non-cash compensation on equity grants
and in 2015 to exclude earnings from unconsolidated investments net
of distributions and transaction costs related to business
acquisitions.(3) Includes accretion expense associated with asset
retirement obligations, noncontrolling interest portion of
depreciation and amortization expenses and loss on financing
activities.
Gross Margin –
The Partnership defines gross margin as revenues less purchases. It
is impacted by volumes and commodity prices as well as by the
Partnership’s contract mix and commodity hedging program. The
Partnership defines Gathering and Processing gross margin as total
operating revenues from (1) the sale of natural gas, condensate,
crude oil and NGLs and (2) natural gas and crude oil gathering and
service fee revenues less product purchases, which consist
primarily of producer payments and other natural gas and crude oil
purchases. Logistics Assets gross margin consists primarily of
service fee revenue. Gross margin for Marketing and Distribution
equals total revenue from service fees, NGL and natural gas sales,
less cost of sales, which consists primarily of NGL and natural gas
purchases, transportation costs and changes in inventory valuation.
The gross margin impacts of cash flow hedge settlements are
reported in Other.
Operating Margin - The
Partnership defines operating margin as gross margin less operating
expenses. Operating margin is an important performance measure of
the core profitability of the Partnership’s operations.
Gross margin and operating margin are non-GAAP
measures. The GAAP measure most directly comparable to gross margin
and operating margin is net income. Gross margin and operating
margin are not alternatives to GAAP net income and have important
limitations as analytical tools. Investors should not consider
gross margin and operating margin in isolation or as a substitute
for analysis of the Partnership’s results as reported under GAAP.
Because gross margin and operating margin exclude some, but not
all, items that affect net income and are defined differently by
different companies in the Partnership’s industry, the
Partnership’s definition of gross margin and operating margin may
not be comparable to similarly titled measures of other companies,
thereby diminishing their utility.
Management reviews business segment gross margin
and operating margin monthly as a core internal management process.
The Partnership believes that investors benefit from having access
to the same financial measures that its management uses in
evaluating its operating results. Gross margin and operating margin
provide useful information to investors because they are used as
supplemental financial measures by the Partnership and by external
users of the Partnership’s financial statements, including
investors and commercial banks, to assess:
- the financial performance of the Partnership’s assets without
regard to financing methods, capital structure or historical cost
basis;
- the Partnership’s operating performance and return on capital
as compared to other companies in the midstream energy sector,
without regard to financing or capital structure; and
- the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
Management compensates for the limitations of
gross margin and operating margin as analytical tools by reviewing
the comparable GAAP measures, understanding the differences between
the measures and incorporating these insights into its
decision-making processes.
The following table presents a reconciliation of
gross margin and operating margin to net income for the periods
indicated:
| |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
| |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
| |
|
(In millions) |
| Reconciliation
of Targa Resources Partners LP gross |
|
|
|
|
| margin and
operating margin to net income: |
|
|
|
|
|
|
|
|
|
|
|
| Gross margin |
|
$ |
|
452.0 |
|
|
$ |
|
398.2 |
|
|
$ |
|
1,785.6 |
|
|
$ |
|
1,569.6 |
|
| Operating expenses |
|
|
|
(122.8 |
) |
|
|
|
(109.4 |
) |
|
|
|
(504.6 |
) |
|
|
|
(433.0 |
) |
| Operating margin |
|
|
|
329.2 |
|
|
|
|
288.8 |
|
|
|
|
1,281.0 |
|
|
|
|
1,136.6 |
|
| Depreciation and amortization
expenses |
|
|
|
(228.8 |
) |
|
|
|
(93.7 |
) |
|
|
|
(677.1 |
) |
|
|
|
(346.5 |
) |
| General and administrative
expenses |
|
|
|
(23.5 |
) |
|
|
|
(24.6 |
) |
|
|
|
(153.6 |
) |
|
|
|
(139.8 |
) |
| Provisional goodwill
impairment |
|
|
|
(290.0 |
) |
|
|
|
- |
|
|
|
|
(290.0 |
) |
|
|
|
- |
|
| Interest expense, net |
|
|
|
(30.6 |
) |
|
|
|
(39.7 |
) |
|
|
|
(207.8 |
) |
|
|
|
(143.8 |
) |
| Income tax expense |
|
|
|
(0.2 |
) |
|
|
|
(1.1 |
) |
|
|
|
(0.6 |
) |
|
|
|
(4.8 |
) |
| Gain (loss) on sale or disposition
of assets |
|
|
|
7.9 |
|
|
|
|
(0.8 |
) |
|
|
|
8.0 |
|
|
|
|
4.8 |
|
| Loss from financing activities |
|
|
|
3.4 |
|
|
|
|
(12.4 |
) |
|
|
|
2.8 |
|
|
|
|
(12.4 |
) |
| Other, net |
|
|
|
(6.7 |
) |
|
|
|
(1.8 |
) |
|
|
|
(17.6 |
) |
|
|
|
11.0 |
|
| Net income |
|
$ |
|
(239.3 |
) |
|
$ |
|
114.7 |
|
|
$ |
|
(54.9 |
) |
|
$ |
|
505.1 |
|
Targa Resources Corp. - Non-GAAP Financial
Measures
This press release includes the Company’s
non-GAAP financial measure distributable cash flow. Distributable
cash flow should not be considered as an alternative to GAAP
measures such as net income or any other GAAP measure of liquidity
or financial performance.
Distributable Cash Flow - The
Company defines distributable cash flow as distributions due to it
from the Partnership, less the Company’s specific general and
administrative costs as a separate public reporting entity, the
interest carrying costs associated with its debt and taxes
attributable to the Company’s earnings. It excludes transaction
costs related to acquisitions, losses on debt redemptions and
amendments and non-cash interest expense. Distributable cash flow
is a significant performance metric used by the Company and by
external users of the Company’s financial statements, such as
investors, commercial banks, research analysts and others to
compare basic cash flows generated by the Company to the cash
dividends the Company expects to pay its shareholders. Using this
metric, management and external users of the Company’s financial
statements can quickly compute the coverage ratio of estimated cash
flows to planned cash dividends. Distributable cash flow is also an
important financial measure for the Company’s shareholders since it
serves as an indicator of the Company’s success in providing a cash
return on investment. Specifically, this financial measure
indicates to investors whether or not the Company is generating
cash flow at a level that can sustain or support an increase in the
Company’s quarterly dividend rates. Distributable cash flow is also
a quantitative standard used throughout the investment community
because the share value is generally determined by the share’s
yield (which in turn is based on the amount of cash dividends the
entity pays to a shareholder).
The economic substance behind the Company’s use
of distributable cash flow is to measure the ability of the
Company’s assets to generate cash flow sufficient to pay dividends
to the Company’s investors.
The GAAP measure most directly comparable to
distributable cash flow is net income. Distributable cash flow
should not be considered as an alternative to GAAP net income.
Distributable cash flow is not a presentation made in accordance
with GAAP and has important limitations as an analytical tool.
Investors should not consider distributable cash flow in isolation
or as a substitute for analysis of the Company’s results as
reported under GAAP. Because distributable cash flow excludes some,
but not all, items that affect net income and is defined
differently by different companies in the Company’s industry, the
Company’s definition of distributable cash flow may not be
comparable to similarly titled measures of other companies, thereby
diminishing its utility.
Management compensates for the limitations of
distributable cash flow as an analytical tool by reviewing the
comparable GAAP measure, understanding the differences between the
measures and incorporating these insights into its decision-making
process.
The following tables present a reconciliation of
net income of Targa Resources Corp. to distributable cash flow, and
an alternative reconciliation of cash distributions declared by
Targa Resources Partners LP to distributable cash flow of Targa
Resources Corp. for the periods indicated:
| |
|
|
|
Three Months Ended December 31, |
|
|
Year Ended December 31, |
| |
|
|
|
2015 |
|
2014 |
|
|
|
2015 |
|
|
|
|
2014 |
|
| |
|
|
|
(In millions) |
|
Reconciliation of Net Income attributable to |
|
|
|
|
|
|
|
| |
|
Targa Resources
Corp. to Distributable Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
| Net income
of Targa Resources Corp. |
|
$ |
|
(232.0 |
) |
|
$ |
|
92.3 |
|
|
$ |
|
(151.4 |
) |
|
$ |
|
423.0 |
|
| |
|
Less: Net income of
Targa Resources Partners LP |
|
|
|
239.3 |
|
|
|
|
(114.7 |
) |
|
|
|
54.9 |
|
|
|
|
(505.1 |
) |
| Net loss
for TRC Non-Partnership |
|
|
|
7.3 |
|
|
|
|
(22.4 |
) |
|
|
|
(96.5 |
) |
|
|
|
(82.1 |
) |
| |
|
TRC Non-Partnership
income tax expense |
|
|
|
(14.7 |
) |
|
|
|
13.3 |
|
|
|
|
39.0 |
|
|
|
|
63.2 |
|
| |
|
Distributions from the
Partnership |
|
|
|
61.4 |
|
|
|
|
51.6 |
|
|
|
|
243.2 |
|
|
|
|
190.8 |
|
| |
|
Loss on financing
activities |
|
|
|
- |
|
|
|
|
- |
|
|
|
|
12.9 |
|
|
|
|
- |
|
| |
|
Non-cash interest
expense (1) |
|
|
|
0.8 |
|
|
|
|
- |
|
|
|
|
2.7 |
|
|
|
|
- |
|
| |
|
Depreciation -
Non-Partnership assets |
|
|
|
- |
|
|
|
|
4.2 |
|
|
|
|
- |
|
|
|
|
4.5 |
|
| |
|
Transaction costs
related to business acquisitions (1) |
|
|
|
0.1 |
|
|
|
|
- |
|
|
|
|
12.5 |
|
|
|
|
- |
|
| |
|
Current cash tax
expense (2) |
|
|
|
- |
|
|
|
|
(12.1 |
) |
|
|
|
(6.5 |
) |
|
|
|
(63.5 |
) |
| |
|
Taxes funded with cash
on hand (3) |
|
|
|
- |
|
|
|
|
2.9 |
|
|
|
|
6.5 |
|
|
|
|
11.8 |
|
|
Distributable cash flow |
|
$ |
|
54.9 |
|
|
$ |
|
37.5 |
|
|
$ |
|
213.8 |
|
|
$ |
|
124.7 |
|
|
________ |
|
|
(1 |
) |
|
The
definition of Distributable cash flow was revised in 2015 to adjust
for transaction costs related to business acquisitions and non-cash
interest expense. |
|
|
(2 |
) |
|
Excludes $1.2
million and $4.7 million of non-cash current tax expense arising
from amortization of deferred long-term tax assets from drop down
gains realized for tax purposes and paid in 2010 for the three
months and year ended December 31, 2015 and 2014. |
|
|
(3 |
) |
|
Current
period portion of amount established at our IPO to fund taxes on
deferred gains related to drop down transactions that were treated
as sales for income tax purposes. |
|
|
|
|
|
|
| |
|
|
|
Three Months Ended December 31, |
|
|
Year Ended December 31, |
| |
|
|
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
|
| |
|
|
|
|
(In millions) |
|
Targa Resources Corp. Distributable Cash Flow |
|
|
|
|
|
|
|
|
Distributions declared by Targa Resources Partners LP associated
with: |
|
|
|
|
|
|
| |
|
General Partner
Interests |
|
$ |
|
4.0 |
|
|
$ |
|
2.7 |
|
|
$ |
|
15.9 |
|
|
$ |
|
10.2 |
|
| |
|
Incentive Distribution
Rights |
|
|
|
43.9 |
|
|
|
|
38.4 |
|
|
|
|
173.4 |
|
|
|
|
139.8 |
|
| |
|
Common Units held by
TRC |
|
|
|
13.5 |
|
|
|
|
10.5 |
|
|
|
|
53.9 |
|
|
|
|
40.8 |
|
| Total
distributions declared by Targa Resources Partners LP |
|
|
|
61.4 |
|
|
|
|
51.6 |
|
|
|
|
243.2 |
|
|
|
|
190.8 |
|
| |
Income
(expenses) of TRC Non-Partnership |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
General and
administrative expenses |
|
|
|
(1.7 |
) |
|
|
|
(1.2 |
) |
|
|
|
(8.1 |
) |
|
|
|
(8.2 |
) |
| |
|
Interest expense, net
(1) |
|
|
|
(4.9 |
) |
|
|
|
(0.9 |
) |
|
|
|
(21.4 |
) |
|
|
|
(3.3 |
) |
| |
|
Current cash tax
expense (2) |
|
|
|
- |
|
|
|
|
(12.1 |
) |
|
|
|
(6.5 |
) |
|
|
|
(63.5 |
) |
| |
|
Taxes funded with cash
on hand (3) |
|
|
|
- |
|
|
|
|
2.9 |
|
|
|
|
6.5 |
|
|
|
|
11.8 |
|
| |
|
Other income
(expense) |
|
|
|
0.1 |
|
|
|
|
(2.8 |
) |
|
|
|
0.1 |
|
|
|
|
(2.9 |
) |
|
Distributable cash flow |
|
$ |
|
54.9 |
|
|
$ |
|
37.5 |
|
|
$ |
|
213.8 |
|
|
$ |
|
124.7 |
|
_________________
(1) Excludes non-cash interest expense.(2)
Excludes $1.2 million and $4.7 million of non-cash current tax
expense arising from amortization of deferred long-term tax assets
from drop down gains realized for tax purposes and paid in 2010 for
the three months and year ended December 31, 2015 and 2014.(3)
Current period portion of amount established at our IPO to fund
taxes on deferred gains related to drop down transactions that were
treated as sales for income tax purposes.
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 Partnership and
the Company expect, believe or anticipate 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 Partnership’s and the Company’s
control, which could cause results to differ materially from those
expected by management of the Partnership and 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 and natural gas
liquids; 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 Partnership’s and
the Company’s filings with the Securities and Exchange Commission,
including their Annual Reports on Form 10-K, Quarterly Reports on
Form 10-Q and Current Reports on Form 8-K. Neither the Partnership
nor the Company undertake an obligation to update or revise any
forward-looking statement, whether as a result of new information,
future events or otherwise.
Contact investor relations by phone at
(713) 584-1133.
Jennifer KnealeVice President – Finance
Matthew Meloy Executive Vice President and Chief
Financial Officer
|
|
|
TARGA RESOURCES PARTNERS LP |
| FINANCIAL SUMMARY (unaudited) |
|
CONSOLIDATED STATEMENTS OF OPERATIONS |
| (In
millions, except per unit amounts) |
| |
Three Months Ended |
|
|
Year Ended |
| |
December 31, |
|
|
December 31, |
| |
2015 |
|
2014 |
|
2015 |
|
2014 |
|
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
| Sale of commodities |
$ |
|
1,345.7 |
|
|
$ |
|
1,742.0 |
|
|
$ |
|
5,465.4 |
|
|
$ |
|
7,595.2 |
|
| Fees from midstream services |
|
|
301.7 |
|
|
|
|
290.9 |
|
|
|
|
1,193.2 |
|
|
|
|
1,021.3 |
|
| Total Revenues |
|
|
1,647.3 |
|
|
|
|
2,032.9 |
|
|
|
|
6,658.6 |
|
|
|
|
8,616.5 |
|
| COSTS AND
EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
| Product purchases |
|
|
1,195.3 |
|
|
|
|
1,634.7 |
|
|
|
|
4,873.0 |
|
|
|
|
7,046.9 |
|
| Operating expenses |
|
|
122.8 |
|
|
|
|
109.4 |
|
|
|
|
504.6 |
|
|
|
|
433.0 |
|
| Depreciation and amortization
expenses |
|
|
228.8 |
|
|
|
|
93.7 |
|
|
|
|
677.1 |
|
|
|
|
346.5 |
|
| General and administrative
expenses |
|
|
23.5 |
|
|
|
|
24.6 |
|
|
|
|
153.6 |
|
|
|
|
139.8 |
|
| Goodwill impairment |
|
|
290.0 |
|
|
|
|
- |
|
|
|
|
290.0 |
|
|
|
|
- |
|
| Other operating (income)
expenses |
|
|
(7.8 |
) |
|
|
|
2.1 |
|
|
|
|
(7.1 |
) |
|
|
|
(3.0 |
) |
| Total costs and expenses |
|
|
1,852.6 |
|
|
|
|
1,864.5 |
|
|
|
|
6,491.2 |
|
|
|
|
7,963.2 |
|
| INCOME FROM
OPERATIONS |
|
|
(205.3 |
) |
|
|
|
168.4 |
|
|
|
|
167.4 |
|
|
|
|
653.3 |
|
| Other income
(expense): |
|
|
|
|
|
|
|
|
|
|
|
| Interest expense, net |
|
|
(30.6 |
) |
|
|
|
(39.7 |
) |
|
|
|
(207.8 |
) |
|
|
|
(143.8 |
) |
| Equity earnings (loss) |
|
|
(1.4 |
) |
|
|
|
4.3 |
|
|
|
|
(2.5 |
) |
|
|
|
18.0 |
|
| Loss from financing activities |
|
|
3.4 |
|
|
|
|
(12.4 |
) |
|
|
|
2.8 |
|
|
|
|
(12.4 |
) |
| Other |
|
|
(5.2 |
) |
|
|
|
(4.8 |
) |
|
|
|
(14.2 |
) |
|
|
|
(5.2 |
) |
| Income before income
taxes |
|
|
(239.1 |
) |
|
|
|
115.8 |
|
|
|
|
(54.3 |
) |
|
|
|
509.9 |
|
| Income tax (expense)
benefit |
|
|
(0.2 |
) |
|
|
|
(1.1 |
) |
|
|
|
(0.6 |
) |
|
|
|
(4.8 |
) |
| NET
INCOME |
|
|
(239.3 |
) |
|
|
|
114.7 |
|
|
|
|
(54.9 |
) |
|
|
|
505.1 |
|
| Less: Net income
attributable to noncontrolling interests |
|
|
(49.2 |
) |
|
|
|
6.5 |
|
|
|
|
(31.9 |
) |
|
|
|
37.4 |
|
| NET INCOME
ATTRIBUTABLE TO TARGA RESOURCES PARTNERS
LP |
$ |
|
(190.1 |
) |
|
$ |
|
108.2 |
|
|
$ |
|
(23.0 |
) |
|
$ |
|
467.7 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
| Net income attributable
to preferred limited partners |
$ |
|
2.4 |
|
|
$ |
|
- |
|
|
$ |
|
2.4 |
|
|
$ |
|
- |
|
| Net income attributable
to general partner |
|
|
40.1 |
|
|
|
|
40.5 |
|
|
|
|
172.1 |
|
|
|
|
148.7 |
|
| Net income attributable
to limited partners |
|
|
(232.6 |
) |
|
|
|
67.7 |
|
|
|
|
(197.5 |
) |
|
|
|
319.0 |
|
| Net income attributable
to Targa Resources Partners LP |
$ |
|
(190.1 |
) |
|
$ |
|
108.2 |
|
|
$ |
|
(23.0 |
) |
|
$ |
|
467.7 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
| Net income per limited
partner unit - basic |
$ |
|
(1.26 |
) |
|
$ |
|
0.58 |
|
|
$ |
|
(1.15 |
) |
|
$ |
|
2.78 |
|
| Net income per limited
partner unit - diluted |
$ |
|
(1.26 |
) |
|
$ |
|
0.58 |
|
|
$ |
|
(1.15 |
) |
|
$ |
|
2.77 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
| Weighted average
limited partner units outstanding - basic |
|
|
184.8 |
|
|
|
|
116.8 |
|
|
|
|
172.3 |
|
|
|
|
114.7 |
|
| Weighted average
limited partner units outstanding - diluted |
|
|
185.1 |
|
|
|
|
117.1 |
|
|
|
|
172.3 |
|
|
|
|
115.1 |
|
| |
TARGA RESOURCES CORP. |
| |
FINANCIAL SUMMARY (unaudited) |
| |
CONSOLIDATED STATEMENTS OF OPERATIONS |
| |
(In
millions, except per share amounts) |
| |
|
Three Months Ended December 31, |
|
Year Ended December 31, |
| |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
| |
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
| |
Sales of commodities |
$ |
|
1,345.7 |
|
|
$ |
|
1,742.0 |
|
|
$ |
|
5,465.4 |
|
|
$ |
|
7,595.2 |
|
| |
Fees from midstream services |
|
|
301.7 |
|
|
|
|
290.9 |
|
|
|
|
1,193.2 |
|
|
|
|
1,021.3 |
|
| |
Total revenues |
|
|
1,647.3 |
|
|
|
|
2,032.9 |
|
|
|
|
6,658.6 |
|
|
|
|
8,616.5 |
|
| |
COSTS AND
EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
| |
Product purchases |
|
|
1,195.3 |
|
|
|
|
1,634.7 |
|
|
|
|
4,873.0 |
|
|
|
|
7,046.9 |
|
| |
Operating expenses |
|
|
122.8 |
|
|
|
|
109.4 |
|
|
|
|
504.6 |
|
|
|
|
433.1 |
|
| |
Depreciation and amortization
expenses |
|
|
228.8 |
|
|
|
|
97.9 |
|
|
|
|
677.1 |
|
|
|
|
351.0 |
|
| |
General and administrative
expenses |
|
|
25.1 |
|
|
|
|
25.8 |
|
|
|
|
161.7 |
|
|
|
|
148.0 |
|
| |
Goodwill impairment |
|
|
290.0 |
|
|
|
|
- |
|
|
|
|
290.0 |
|
|
|
|
- |
|
| |
Other operating income |
|
|
(7.8 |
) |
|
|
|
2.0 |
|
|
|
|
(7.1 |
) |
|
|
|
(3.0 |
) |
| |
Total costs and expenses |
|
|
1,854.2 |
|
|
|
|
1,869.8 |
|
|
|
|
6,499.3 |
|
|
|
|
7,976.0 |
|
| |
INCOME FROM
OPERATIONS |
|
|
(206.9 |
) |
|
|
|
163.1 |
|
|
|
|
159.3 |
|
|
|
|
640.5 |
|
| |
Other income
(expense): |
|
|
|
|
|
|
|
|
|
|
|
| |
Interest expense, net |
|
|
(36.4 |
) |
|
|
|
(40.6 |
) |
|
|
|
(231.9 |
) |
|
|
|
(147.1 |
) |
| |
Equity earnings |
|
|
(1.4 |
) |
|
|
|
4.3 |
|
|
|
|
(2.5 |
) |
|
|
|
18.0 |
|
| |
Loss on financing activities |
|
|
3.3 |
|
|
|
|
(12.4 |
) |
|
|
|
(10.1 |
) |
|
|
|
(12.4 |
) |
| |
Other |
|
|
(5.1 |
) |
|
|
|
(7.5 |
) |
|
|
|
(26.6 |
) |
|
|
|
(8.0 |
) |
| |
Income (loss) before
income taxes |
|
|
(246.5 |
) |
|
|
|
106.9 |
|
|
|
|
(111.8 |
) |
|
|
|
491.0 |
|
| |
Income tax (expense)
benefit |
|
|
14.5 |
|
|
|
|
(14.4 |
) |
|
|
|
(39.6 |
) |
|
|
|
(68.0 |
) |
| |
NET INCOME
(LOSS) |
|
|
(232.0 |
) |
|
|
|
92.5 |
|
|
|
|
(151.4 |
) |
|
|
|
423.0 |
|
| |
Less: Net income (loss)
attributable to noncontrolling interests |
|
|
(258.9 |
) |
|
|
|
66.9 |
|
|
|
|
(209.7 |
) |
|
|
|
320.7 |
|
| |
NET INCOME
AVAILABLE TO COMMON SHAREHOLDERS |
$ |
|
26.9 |
|
|
$ |
|
25.6 |
|
|
$ |
|
58.3 |
|
|
$ |
|
102.3 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net income available
per common share - basic |
$ |
|
0.48 |
|
|
$ |
|
0.61 |
|
|
$ |
|
1.09 |
|
|
$ |
|
2.44 |
|
| |
Net income available
per common share - diluted |
$ |
|
0.48 |
|
|
$ |
|
0.61 |
|
|
$ |
|
1.09 |
|
|
$ |
|
2.43 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Weighted average shares
outstanding - basic |
|
|
56.0 |
|
|
|
|
42.0 |
|
|
|
|
53.5 |
|
|
|
|
42.0 |
|
| |
Weighted average shares
outstanding - diluted |
|
|
56.0 |
|
|
|
|
42.1 |
|
|
|
|
53.6 |
|
|
|
|
42.1 |
|
|
TARGA RESOURCES CORP. |
| FINANCIAL SUMMARY
(unaudited) |
| KEY TARGA
RESOURCES CORP. BALANCE SHEET ITEMS |
| (In
millions) |
|
|
|
|
|
| |
|
|
|
|
|
|
| |
|
|
|
|
December 31, 2015 |
|
Cash and cash equivalents: |
|
|
| |
TRC
Non-Partnership |
$ |
4.8 |
| |
Targa
Resources Partners |
|
135.4 |
| |
|
Total cash
and cash equivalents |
$ |
140.2 |
|
Total funded debt: |
|
|
|
Current |
|
|
|
|
Targa
Resources Partners |
$ |
219.3 |
| Long
term |
|
|
| |
TRC
Non-Partnership |
|
597.5 |
| |
Targa
Resources Partners |
|
5,164.0 |
| |
|
Total
long-term debt |
|
5,761.5 |
| |
|
|
Total
funded debt: |
$ |
5,980.8 |