UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
OF THE SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported)
March 1, 2010
March 1, 2010
TARGA RESOURCES PARTNERS LP
(Exact name of registrant as specified in its charter)
| Delaware (State or other jurisdiction of incorporation or organization) |
001-33303 (Commission File Number) |
65-1295427 (IRS Employer Identification No.) |
1000 Louisiana, Suite 4300
Houston, TX 77002
(Address of principal executive office and Zip Code)
Houston, TX 77002
(Address of principal executive office and Zip Code)
(713) 584-1000
(Registrants’ telephone number, including area code)
(Registrants’ telephone number, including area code)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the
filing obligation of the registrant under any of the following provisions:
| o | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |
| o | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |
| o | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |
| o | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 2.02 Results of Operations and Financial Condition.
On March 1, 2010 Targa Resources Partners LP (the “Partnership”) issued a press release
regarding its financial results for the three months and year ended December 31, 2009. A
conference call to discuss these results is scheduled for 11:00 a.m. Eastern time on Monday, March
1, 2010. The conference call will be webcast live and a replay of the webcast will be available
through the Investors section of the Partnership’s web site (http://www.targaresources.com)
until March 15, 2010. A copy of the earnings press release is furnished as Exhibit 99.1 to this
report, which is hereby incorporated by reference into this Item 2.02.
The press release and accompanying schedules and/or the conference call discussions include
the non-generally accepted accounting principles, or non-GAAP, financial measures of distributable
cash flow, operating margin and Adjusted EBITDA. The press release provides reconciliations of
these non-GAAP financial measures to their most directly comparable financial measure calculated
and presented in accordance with generally accepted accounting principles in the United States of
America (“GAAP”). Our non-GAAP financial measures should not be considered as alternatives to GAAP
measures such as net cash provided by operating activities, net income (loss) or any other GAAP
measure of liquidity or financial performance.
Item 9.01 Financial Statements and Exhibits.
| (d) | Exhibits |
| Exhibit | ||
| Number | Description | |
Exhibit 99.1
|
Targa Resources Partners LP Press Release dated March 1, 2010. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| TARGA RESOURCES PARTNERS LP | ||||
| By: | Targa Resources GP LLC, its general partner |
|||
Dated: March 1, 2010
|
By: | /s/ Jeffrey J. McParland | ||
| Jeffrey J. McParland Executive Vice President and Chief Financial Officer |
||||
EXHIBIT INDEX
| Exhibit | ||
| Number | Description | |
Exhibit 99.1
|
Targa Resources Partners LP Press Release dated March 1, 2010. |
Exhibit 99.1
|
1000 Louisiana, Suite 4300 Houston, TX 77002 713.584.1000 www.targaresources.com |
Targa Resources Partners LP Reports
Fourth Quarter and Full Year 2009 Financial Results
Fourth Quarter and Full Year 2009 Financial Results
HOUSTON — March 1, 2010 -Targa Resources Partners LP (“Targa Resources Partners” or the
“Partnership”) (NYSE: NGLS) today reported fourth quarter 2009 net income of $38.4 million, or
$0.56 per diluted limited partner unit compared to net income of $19.8 million, or $0.48 per
diluted limited partner unit for the fourth quarter of 2008. Net income for the fourth quarter of
2009 and 2008 included $3.8 and $11.8 million in non-cash charges related to derivative
instruments, respectively. The Partnership reported earnings before interest, income taxes,
depreciation and amortization and non-cash income or loss related to derivative instruments
(“Adjusted EBITDA”) of $84.6 million for the fourth quarter of 2009 compared to Adjusted EBITDA of
$82.6 million for the fourth quarter of 2008.
For the full year 2009, the Partnership reported net income of $52.0 million, or $0.86 per diluted
limited partner unit compared to net income of $49.4 million, or $1.83 per diluted limited
partner unit for 2008. Net income for the full year 2009 and 2008 included $43.4 and $59.2 million
in non-cash charges related to affiliate interest expenses and $37.6 and $23.4 million in non-cash
charges related to derivative instruments, respectively. The Partnership reported Adjusted EBITDA
of $286.3 million for 2009 compared to Adjusted EBITDA of $269.4 million for 2008. In accordance
with the accounting treatment for entities under common control, the Partnership’s results include
the Downstream Business for all periods.
Distributable cash flow for the fourth quarter of 2009 of $61.1 million corresponds to distribution
coverage of 1.6 times the $38.8 million in total distributions paid on February 12, 2010 (see the
section of this release entitled “Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA,
operating margin and distributable cash flow, and reconciliations of such measures to the
comparable GAAP measures).
“Our outstanding fourth quarter results were driven primarily by the performance of the Downstream
Business that benefited from weather and petrochemical related volume demand and rising NGL prices.
We are extremely pleased with our full year 2009 performance given the challenges presented by the
difficult economic and capital markets environment. We executed on our business strategies by
managing controllable costs and capital expenditures, closing the dropdown of the Downstream
Business, increasing our gathering and processing inlet volumes and finalizing the necessary
commercial agreements to support a major expansion of Cedar Bayou Fractionator. In 2010 we will
continue our focus on organic and acquisition-based growth opportunities,” said Rene Joyce, Chief
Executive Officer of the Partnership’s general partner and of Targa Resources, Inc. (“Targa”).
The Partnership’s strong fourth quarter 2009 distribution coverage was enhanced due to seasonality
in the marketing segments of the Downstream Business and year-end take-or-pay payments within the
Logistics Assets segment. During the first quarter of 2010, plant turnarounds are scheduled for
several facilities in the Logistics Assets segment.
On January 22, 2010, the Partnership announced a cash distribution of 51.75¢ per common unit, or
$2.07 per unit on an annualized basis, for the fourth quarter of 2009. This $38.8 million cash
distribution was paid February 12, 2010 on all outstanding common and general partner units to
holders of record as of the close of business on February 3, 2010.
Capitalization and Liquidity Update
Total funded debt as of December 31, 2009 was approximately $908 million including $479 million
outstanding under the Partnership’s $978 million senior secured revolving credit facility, $209
million of 8.25% senior unsecured notes due 2016 and $220 million of 11.25% senior unsecured notes
due 2017.
As of December 31, 2009, the Partnership had $410 million in capacity available under its senior
secured revolving credit facility after giving effect to the Lehman default and the issuance of $69
million of letters of credit. As of December 31, 2009, the Partnership had $60 million of cash,
bringing total liquidity to approximately $470 million.
On January 19, 2010, we completed a public offering of 6.325 million common units at a price of
$23.14 per common unit, providing net proceeds of approximately $140 million. We used the net
proceeds from the offering for general partnership purposes, which included reducing borrowings
under our senior secured credit facility. Pro forma for the closing of the offering, the
Partnership had approximately $610 million of liquidity as of December 31, 2009.
We estimate total capital expenditures of the Partnership will be approximately $130 million in
2010. Maintenance capital expenditures account for approximately 25% of the total 2010 estimate.
Conference Call
Targa Resources Partners will host a conference call for investors and analysts at 11 a.m. Eastern
Time (10 a.m. Central Time) on March 1, 2010 to discuss fourth quarter 2009 financial results. The
conference call can be accessed via Webcast through the Investor’s section of the Partnership’s
website at http://www.targaresources.com or by dialing (877) 941-8609. The pass code is 4206522.
Please dial in ten minutes prior to the scheduled start time. A replay will be available
approximately two hours following completion of the Webcast through the Investor’s section of the
Partnership’s website and will remain available until March 15, 2010. Replay access numbers are
303-590-3030 or 800-406-7325 with pass code 4206522.
2
Results of Operations
With the closing of the acquisition of the Downstream Business in 2009, and in accordance with the
accounting treatment for entities under common control, the results of operations of the
Partnership include the historical results of the Downstream Business for all periods presented.
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| (In millions, except operating and price data) | ||||||||||||||||
Revenues |
$ | 1,254.8 | $ | 1,065.9 | $ | 4,095.6 | $ | 7,502.1 | ||||||||
Product purchases |
1,107.8 | 943.7 | 3,585.6 | 6,950.8 | ||||||||||||
Operating expenses |
43.0 | 56.3 | 185.1 | 254.0 | ||||||||||||
Depreciation and amortization
expense |
25.7 | 25.0 | 101.2 | 97.8 | ||||||||||||
General and administrative expense |
23.4 | 11.2 | 78.9 | 68.6 | ||||||||||||
Other |
— | 3.5 | (0.8 | ) | (0.9 | ) | ||||||||||
Income from operations |
54.9 | 26.2 | 145.6 | 131.8 | ||||||||||||
Other income (expense): |
||||||||||||||||
Interest expense from affiliate |
— | (14.8 | ) | (43.4 | ) | (59.2 | ) | |||||||||
Interest expense allocated
from Parent |
— | — | — | — | ||||||||||||
Other interest expense, net |
(16.7 | ) | (10.7 | ) | (52.0 | ) | (37.9 | ) | ||||||||
Other |
1.5 | 19.9 | 5.0 | 17.4 | ||||||||||||
Income tax expense |
(0.3 | ) | (0.6 | ) | (1.0 | ) | (2.4 | ) | ||||||||
Net income |
39.4 | 20.0 | 54.2 | 49.7 | ||||||||||||
Less: Net income attributable to
noncontrolling interest |
1.0 | 0.2 | 2.2 | 0.3 | ||||||||||||
Net income attributable to Targa
Resources Partners LP |
$ | 38.4 | $ | 19.8 | $ | 52.0 | $ | 49.4 | ||||||||
Net income (loss) attributable to
predecessor operations |
$ | — | $ | (3.9 | ) | $ | (2.4 | ) | $ | (42.1 | ) | |||||
Net income attributable to
general partner |
3.6 | 1.5 | 10.4 | 7.0 | ||||||||||||
Net income attributable to
limited partners |
34.8 | 22.2 | 44.0 | 84.5 | ||||||||||||
Net income attributable to Targa
Resources Partners LP |
$ | 38.4 | $ | 19.8 | $ | 52.0 | $ | 49.4 | ||||||||
Basic and diluted net income per
limited partner unit |
$ | 0.56 | $ | 0.48 | $ | 0.86 | $ | 1.83 | ||||||||
Financial data: |
||||||||||||||||
Operating margin |
$ | 104.0 | $ | 65.9 | $ | 324.9 | $ | 297.3 | ||||||||
Adjusted EBITDA |
84.6 | 82.6 | 286.3 | 269.4 | ||||||||||||
Distributable cash flow |
61.1 | 32.8 | 176.3 | 120.7 | ||||||||||||
Operating statistics: |
||||||||||||||||
Gathering throughput, MMcf/d |
478.8 | 418.5 | 468.6 | 445.8 | ||||||||||||
Plant natural gas inlet, MMcf/d |
455.8 | 392.6 | 445.9 | 421.2 | ||||||||||||
Gross NGL production, MBbl/d |
41.4 | 38.7 | 42.7 | 42.0 | ||||||||||||
Natural gas sales, BBtu/d |
414.5 | 429.4 | 390.9 | 415.6 | ||||||||||||
NGL sales, MBbl/d |
256.9 | 246.7 | 273.1 | 297.3 | ||||||||||||
Condensate sales, MBbl/d |
2.9 | 2.6 | 2.8 | 2.5 | ||||||||||||
Average realized prices: |
||||||||||||||||
Natural gas, $/MMBtu |
$ | 4.32 | $ | 6.05 | $ | 3.96 | $ | 8.45 | ||||||||
NGL, $/gal |
1.04 | 0.81 | 0.79 | 1.39 | ||||||||||||
Condensate, $/Bbl |
60.52 | 52.41 | 57.07 | 90.00 | ||||||||||||
3
Review of Fourth Quarter Results
Net income for the fourth quarter of 2009 was $38.4 million, or $0.56 per diluted limited partner
unit, compared to $19.8 million, or $0.48 per diluted limited partner unit for the fourth quarter
of 2008.
Revenues increased by $188.9 million, or 18%, to $1,254.8 million for 2009 compared to $1,065.9
million for 2008. Revenues from the sale of natural gas decreased by $74.4 million, consisting of
decreases of $66.1 million due to lower realized prices and $8.3 million due to lower sales
volumes. Revenues from the sale of NGLs increased by $262.9 million, consisting of an increase of
$231.2 million due to higher realized prices and an increase of $31.7 million due to higher sales
volumes. Revenues from the sale of condensate increased by $3.8 million, consisting of an increase
of $2.2 million due to higher realized prices and $1.6 million due to higher sales volumes.
Our average realized prices for natural gas decreased by $1.73 per MMBtu, or 29%, to $4.32 per
MMBtu for 2009 compared to $6.05 per MMBtu for 2008. Our average realized prices for NGL increased
by $0.23 per gallon, or 28%, to $1.04 per gallon for 2009 compared to $0.81 per gallon for 2008.
Our average realized price for condensate increased by $8.11 per barrel, or 15%, to $60.52 per
barrel for 2009 compared to $52.41 per barrel for 2008.
Natural gas sales volumes decreased by 14.9 BBtu/d, or 3%, to 414.5 BBtu/d for 2009 compared to
429.4 BBtu/d for 2008. NGL sales volumes increased by 10.2 MBbl/d, or 4%, to 256.9 MBbl/d for 2009
compared to 246.7 MBbl/d for 2008. Condensate sales volumes increased by 0.3 MBbl/d, or 12%, to 2.9
MBbl/d for 2009 compared to 2.6 MBbl/d for 2008.
Product purchases increased by $164.1 million, or 17%, to $1,107.8 million for 2009 compared to
$943.7 million for 2008.
Operating expenses decreased by $13.3 million, or 24%, to $43.0 million for 2009 compared to $56.3
million for 2008.
General and administrative expense increased by $12.2 million, or 109%, to $23.4 million for 2009
compared to $11.2 million for 2008. The increase included increases in compensation related
expenses, professional services, allocated corporate level expenses and insurance expenses.
Interest expense decreased by $8.8 million, or 35%, to $16.7 million for 2009 compared to $25.5
million for 2008. The decrease is primarily a result of the elimination of affiliate indebtedness,
somewhat offset by the issuance of our 11.25% senior unsecured notes.
4
Review of Full Year Results
Net income was $52.0 million for the full year of 2009 compared to $49.4 million for the full year
of 2008.
Revenues decreased by $3,406.5 million, or 45%, to $4,095.6 million for 2009 compared to $7,502.1
million for 2008. Revenues from the sale of natural gas decreased by $719.0 million, consisting of
decreases of $639.6 million due to lower realized prices and $79.4 million due to lower sales
volumes. Revenues from the sale of NGL decreased by $2,659.2 million, consisting of a decrease of
$2,511.5 million due to lower realized prices and a decrease of $147.7 million due to lower sales
volumes. Revenues from the sale of condensate decreased by $22.1 million, which is the net of a
decrease of $33.9 million due to lower realized prices and an increase of $11.8 million due to
higher sales volumes.
Our average realized prices for natural gas decreased by $4.49 per MMBtu, or 53%, to $3.96 per
MMBtu for 2009 compared to $8.45 per MMBtu for 2008. Our average realized prices for NGL decreased
by $0.60 per gallon, or 43%, to $0.79 per gallon for 2009 compared to $1.39 per gallon for 2008.
Our average realized price for condensate decreased by $32.93 per barrel, or 37%, to $57.07 per
barrel for 2009 compared to $90.00 per barrel for 2008.
Natural gas sales volumes decreased by 24.7 BBtu/d, or 6%, to 390.9 BBtu/d for 2009 compared to
415.6 BBtu/d for 2008. NGL sales volumes decreased by 24.2 MBbl/d, or 8%, to 273.1 MBbl/d for 2009
compared to 297.3 MBbl/d for 2008. Condensate sales volumes increased by 0.3 MBbl/d, or 12%, to 2.8
MBbl/d for 2009 compared to 2.5 MBbl/d for 2008.
Product purchases decreased by $3,365.2 million, or 48%, to $3,585.6 million for 2009 compared to
$6,950.8 million for 2008.
Operating expenses decreased by $68.9 million, or 27%, to $185.1 million for 2009 compared to
$254.0 million for 2008.
General and administrative expense increased by $10.3 million, or 15%, to $78.9 million for 2009
compared to $68.6 million for 2008. The increase included increases in compensation related
expenses, professional services, allocated corporate level expenses and insurance expenses.
Interest expense decreased by $1.7 million, or 2%, to $95.4 million for 2009 compared to $97.1
million for 2008.
5
Review of Segment Performance
The following discussion of segment performance includes inter-segment revenues. The Partnership
views segment operating margin as an important performance measure of the core profitability of its
operations. This measure is a key component of internal financial reporting and is reviewed for
consistency and trend analysis. The generally accepted accounting principles (“GAAP”) measure most
directly comparable to segment operating margin is net income. Operating margin is a non-GAAP
financial measure that is defined later in this release.
6
Natural Gas Gathering and Processing Segment
The Natural Gas Gathering and Processing segment consists of the gathering of natural gas produced
from oil and gas wells and processing this raw natural gas into merchantable natural gas by
extracting natural gas liquids and removing impurities.
The following table provides summary data regarding results of operations of this segment for the
periods indicated:
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| ($ in millions) | ||||||||||||||||
Revenues |
$ | 323.7 | $ | 352.7 | $ | 1,076.5 | $ | 2,074.1 | ||||||||
Product purchases |
(263.9 | ) | (293.2 | ) | (856.7 | ) | (1,803.0 | ) | ||||||||
Operating expenses |
(12.4 | ) | (12.6 | ) | (51.4 | ) | (55.3 | ) | ||||||||
Operating margin |
$ | 47.4 | $ | 46.9 | $ | 168.4 | $ | 215.8 | ||||||||
Operating statistics: |
||||||||||||||||
Gathering throughput, MMcf/d |
||||||||||||||||
LOU System |
211.2 | 144.8 | 190.1 | 178.2 | ||||||||||||
SAOU System |
96.3 | 99.8 | 99.0 | 99.0 | ||||||||||||
North Texas System |
171.3 | 173.9 | 179.5 | 168.6 | ||||||||||||
| 478.8 | 418.5 | 468.6 | 445.8 | |||||||||||||
Plant natural gas inlet, MMcf/d |
||||||||||||||||
LOU System |
200.4 | 136.4 | 180.8 | 168.1 | ||||||||||||
SAOU System |
89.7 | 87.7 | 91.5 | 90.3 | ||||||||||||
North Texas System |
165.7 | 168.5 | 173.6 | 162.8 | ||||||||||||
| 455.8 | 392.6 | 445.9 | 421.2 | |||||||||||||
Gross NGL production, MBbl/d |
||||||||||||||||
LOU System |
8.3 | 5.8 | 8.5 | 9.0 | ||||||||||||
SAOU System |
13.8 | 13.6 | 14.1 | 14.0 | ||||||||||||
North Texas System |
19.3 | 19.3 | 20.1 | 19.0 | ||||||||||||
| 41.4 | 38.7 | 42.7 | 42.0 | |||||||||||||
Natural gas sales, BBtu/d |
414.5 | 429.4 | 390.9 | 415.6 | ||||||||||||
NGL sales, MBbl/d |
38.1 | 34.6 | 38.9 | 37.3 | ||||||||||||
Condensate sales, MBbl/d |
2.9 | 3.6 | 3.0 | 3.6 | ||||||||||||
Average realized prices: |
||||||||||||||||
Natural gas, $/MMBtu |
$ | 4.32 | $ | 6.05 | $ | 3.96 | $ | 8.45 | ||||||||
NGLs, $/gal |
0.93 | 0.65 | 0.71 | 1.22 | ||||||||||||
Condensate, $/Bbl |
60.52 | 46.92 | 55.59 | 81.26 | ||||||||||||
7
Review of Fourth Quarter Results
Revenues decreased by $29.0 million, or 8%, to $323.7 million for the fourth quarter of 2009
compared to $352.7 million for the fourth quarter of 2008. The decrease was primarily due to:
| • | a decrease attributable to commodity prices of $27.3 million, comprising a decrease in natural gas of $66.1 million, partially offset by increases in NGL and condensate revenues of $35.1 million and $3.7 million; | ||
| • | a decrease attributable to commodity sales volume of $1.9 million comprising decreases in natural gas and condensate revenues of $8.3 million and $2.7 million, partially offset by an increase in NGL revenues of $9.1 million; and | ||
| • | an increase in other revenues of $0.2 million, primarily from miscellaneous processing activities. |
The average realized price for NGLs and condensate increased by 43% and 29% and the average
realized price for natural gas decreased by 29% for 2009 compared to 2008.
Natural gas sales volumes decreased by 14.9 BBtu/d, or 3%, for 2009 compared to 2008. The decrease
in natural gas sales volumes was primarily the result of a decrease in purchases from affiliates
for resale partially offset by an increase in demand from the Partnership’s industrial customers.
NGL sales volumes increased by 3.5 MBbl/d, or 10% and condensate sales volumes decreased by 0.7
MBbl/d, or 19%, for the same periods.
Product purchases decreased by $29.3 million, or 10% compared to 2008. The decrease in product
purchase cost reflects lower commodity pricing.
Operating expenses for 2009 decreased by $0.2 million, or 2% compared to 2008. The decrease in
operating expenses was primarily the result of a decrease in system maintenance expenses, repairs
and supplies and ad valorem taxes partially offset by an increase in compensation and benefit
costs.
Review of Full Year Results
Revenues decreased $997.6 million, or 48%, to $1,076.5 million for 2009 compared to $2,074.1
million for 2008. The decrease was primarily due to a decrease attributable to prices of $928.3
million, consisting of decreases in natural gas, NGL, and condensate revenues of $639.6 million,
$260.4 million, and $28.3 million; a decrease attributable to volumes of $68.5 million, consisting
of decreases in natural gas and condensate revenues of $79.4 million and $19.4 million; partially
offset by an increase in NGL revenues of $30.3 million; and a decrease in fee and other revenues of
$0.8 million.
Average realized prices for our sales of natural gas decreased by $4.49 per MMBtu, or 53%, to $3.96
per MMBtu during 2009 compared to $8.45 per MMBtu for 2008. Average realized prices for our sales
of NGLs decreased by $0.51 per gallon, or 42%, to $0.71 per gallon for 2009 compared to $1.22 per
gallon for 2008. Average realized prices for our sales of condensate decreased by $25.67 per Bbl,
or 32%, to $55.59 per Bbl for 2009 compared to $81.26 per Bbl for 2008.
Natural gas sales volume decreased by 24.7 BBtu/d or 6%, to 390.9 BBtu/d during 2009 compared to
415.6 BBtu/d for 2008 due to a decrease in purchases from affiliates for resale partially offset by
an increase in demand from our industrial customers. NGL sales increased by 1.6 MBbl/d, or 4%, to
38.9
8
MBbl/d for 2009 compared to 37.3 MBbl/d for 2008. Condensate sales volumes decreased by 0.6,
or 17%, to 3.0 MBbl/d for 2009 compared to 3.6 MBbl/d for 2008.
Product purchases during 2009 were $856.7 million, which decreased by $946.3 million or 52%,
compared to $1,803.0 million during 2008. The decrease in product purchases corresponds with the
decrease in commodity revenue for 2009.
Operating expenses during 2009 were $51.4 million, which decreased by $3.9 million or 7%, compared
to $55.3 million during 2008. The decrease in operating expenses was primarily the result of
decreases in system maintenance, repairs and supplies expenses and ad valorem taxes partially
offset by increases in compensation and benefit costs.
Logistics Assets Segment
The Logistics Assets segment is involved with gathering and storing mixed NGLs and fractionating,
storing, treating and transporting finished NGLs. These assets are predominantly located in Mont
Belvieu and Galena Park, Texas and in western Louisiana. They are generally connected to and
supplied in part by Targa’s natural gas processing plants.
The following table provides summary data regarding results of operations of this segment for the
periods indicated:
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| ($ in millions) | ||||||||||||||||
Revenues from services |
$ | 59.5 | $ | 53.6 | $ | 212.4 | $ | 235.4 | ||||||||
Other revenues |
(1.2 | ) | 2.0 | 1.9 | 2.6 | |||||||||||
| 58.3 | 55.6 | 214.3 | 238.0 | |||||||||||||
Operating expenses |
(29.6 | ) | (40.2 | ) | (127.3 | ) | (188.1 | ) | ||||||||
Operating margin |
$ | 28.7 | $ | 15.4 | $ | 87.0 | $ | 49.9 | ||||||||
Equity in earnings of GCF |
$ | 1.8 | $ | 0.9 | $ | 5.0 | $ | 3.9 | ||||||||
Operating statistics: |
||||||||||||||||
Fractionation volumes, MBbl/d |
222.8 | 190.8 | 217.2 | 212.2 | ||||||||||||
Treating volumes, MBbl/d |
32.0 | 25.7 | 21.9 | 20.7 | ||||||||||||
Review of Fourth Quarter Results
Revenues from fractionation, terminalling and storage, transportation and treating increased by
$5.9 million, or 11%, for 2009 compared to 2008. Fractionation and treating volumes increased
substantially for 2009 compared to 2008 primarily due to the impact of the hurricanes on the
fractionators and the hydrotreater in 2008. Fractionation and treating revenues were higher due to
higher throughput and higher fixed portions on the fractionation fees, partially offset by
decreased variable portions of the fees due to lower fuel & electricity prices in 2009.
Transportation revenue was also down primarily as a result of lower barge activity in 2009.
9
Operating expenses decreased by $10.6 million, or 26% compared to 2008. The decrease was primarily
due to lower fuel and utilities expense as a result of lower gas prices and lower third party
fractionation expenses. Reduced barge activity was also a factor in reducing operating expense.
These reductions were partially offset by lower inventory gains in 2009 compared to 2008.
Review of Full Year Results
Revenues from fractionation, terminalling and storage, transport, and treating decreased $23.0
million, or 10%, to $212.4 million for 2009 compared to $235.4 million for 2008. Fractionation and
treating volumes increased slightly, but fractionation and treating revenue decreased as the
variable components of the related fees were lower due to decreased fuel and electricity prices.
Reduced barge and truck utilization also contributed to the lower revenue. These reductions in
revenue were partially offset by increased fixed portions on the fractionation fees and increased
wholesale terminal revenue in 2009.
Operating expenses decreased $60.8 million, or 32%, to $127.3 million for 2009 compared to $188.1
million for 2008. The decrease was primarily the result of lower fuel and electricity expenses.
NGL Distribution and Marketing Services Segment
The NGL Distribution and Marketing Services segment markets the Partnership’s natural gas liquids
production and also purchased natural gas liquids products in selected United States markets. The
following table provides summary data regarding results of operations of this segment for the
periods indicated:
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| ($ in millions) | ||||||||||||||||
NGL sales revenues |
$ | 896.5 | $ | 607.8 | $ | 2,907.7 | $ | 5,172.2 | ||||||||
Other revenues |
6.4 | 8.6 | 28.5 | 41.2 | ||||||||||||
| 902.9 | 616.4 | 2,936.2 | 5,213.4 | |||||||||||||
Product purchases |
(889.3 | ) | (612.8 | ) | (2,890.1 | ) | (5,193.2 | ) | ||||||||
Operating expenses |
0.3 | (0.2 | ) | (0.3 | ) | (1.7 | ) | |||||||||
Operating margin |
$ | 13.9 | $ | 3.4 | $ | 45.8 | $ | 18.5 | ||||||||
Operating statistics: |
||||||||||||||||
NGL sales, MBbl/d |
229.4 | 206.0 | 245.7 | 244.6 | ||||||||||||
NGL realized price, $/gal |
1.01 | 0.76 | 0.77 | 1.38 | ||||||||||||
10
Review of Fourth Quarter Results
NGL sales revenues increased by $288.7 million, or 47%, for 2009 compared to 2008. The increase comprised a $240.8 million increase from higher average sales prices, which were up 33% for 2009 compared to 2008 and a $48.0 million increase from higher sales volumes, up 11% for 2009 compared to 2008. The increase in sales volumes was primarily attributable to higher petrochemical plant operating rates and increased
spot sales volumes. This increase is somewhat offset by a contractual volume change with a large petrochemical customer. Other revenues, which consist primarily of non-commodity based service revenue, decreased by $2.2 million.
Product purchases increased by $276.5 million, or 45%, for 2009 compared to 2008. The increase comprised a $228.0 million increase from higher average market prices and a $48.5 million increase from higher purchased volumes.
Review of Full Year Results
Revenues decreased $2,277.2 million, or 44%, to $2,936.2 million for 2009 compared to $5,213.4 million for 2008. Lower market prices decreased revenue $2,096.0 million. Overall sales volumes were higher as the value associated with the volumes is $168.5 million lower due to product mix.
NGL sales increased 1.1 MBbl/d, or less than 1%, to 245.7 MBbl/d for 2009 compared to 244.6 MBbl/d for 2008. Sales to petrochemical customers increased inasmuch as plant operational rates were higher, partially offset by lower spot sales.
Product purchases decreased $2,303.1 million, or 44%, to $2,890.1 million for 2009 compared to $5,193.2 million for 2008. Lower market prices decreased product purchases by $2,134.4 million. Overall purchase volumes were higher but the cost associated with these purchased volumes was $168.7 million lower due to product mix and decreased prices.
11
Wholesale Marketing Segment
The Wholesale Marketing segment includes the Partnership’s refinery services business and wholesale
propane marketing business. In the refinery services business, the Partnership provides LPG
(liquefied petroleum gas) balancing services, purchases natural gas liquids products from refinery
customers and sells natural gas liquids products to various customers. The wholesale propane
marketing business includes the sale of propane and related logistics services to multi-state
retailers, independent retailers and other end-users. Wholesale Marketing operates principally in
the United States and has a small marketing presence in Canada.
The following table provides summary data regarding results of operations of this segment for the
periods indicated:
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| ($ in millions) | ||||||||||||||||
NGL sales revenues |
$ | 326.3 | $ | 278.0 | $ | 884.7 | $ | 1,453.3 | ||||||||
Other revenues |
0.1 | 0.9 | 1.3 | 6.8 | ||||||||||||
| 326.4 | 278.9 | 886.0 | 1,460.1 | |||||||||||||
Product purchases |
(313.5 | ) | (278.7 | ) | (862.3 | ) | (1,446.9 | ) | ||||||||
Operating expenses |
— | (0.1 | ) | — | (0.1 | ) | ||||||||||
Operating margin |
$ | 12.9 | $ | 0.1 | $ | 23.7 | $ | 13.1 | ||||||||
Operating statistics: |
||||||||||||||||
NGL sales, MBbl/d |
70.5 | 69.8 | 58.8 | 62.5 | ||||||||||||
NGL realized price, $/gal |
1.20 | 1.03 | 0.98 | 1.51 | ||||||||||||
Review of Fourth Quarter Results
NGL sales revenues increased by $48.3 million, or 17%, to $326.4 million for 2009 compared to
$278.9 million for 2008. Higher NGL market prices increased revenue by $45.4 million and higher
sales volumes increased revenue by an additional $2.9 million. The 0.7 MBbl/d increase in volumes
was primarily due to seasonality and earlier onset of winter weather. Increased sales at remote
storage and terminal locations were partially offset by the expiration of a supply agreement as
well as production issues at certain West Coast refineries.
Product purchases increased by $34.8 million, or 12%, to $313.5 million for 2009 compared to $278.7
million for 2008. Higher NGL market prices and higher sales volumes resulted in increases in
product purchases of $34.9 million and $2.9 million in 2009.
Review of Full Year Results
Revenues decreased $574.1 million, or 39%, to $886.0 million for 2009 compared to $1,460.1 million
for 2008. Lower NGL market prices decreased revenue by $478.7 million, and lower sales volume
decreased revenue an additional $89.9 million. Other revenues are primarily business interruption
insurance proceeds.
12
Our average realized price for NGLs decreased $0.53 per gallon, or 35%, to $0.98 per gallon for
2009 compared to $1.51 per gallon for 2008. NGL sales volume decreased 3.7 MBbl/d, or 6%, to 58.8
MBbl/d for 2009 compared to 62.5 MBbl/d for 2008. The decrease in volumes is due primarily to
expiration of a refinery purchase agreement.
Product purchases decreased $584.6 million, or 40%, to $862.3 million for 2009 compared to $1,446.9
million for 2008. Lower NGL market prices decreased product purchases by $489.4 million while lower
volumes decreased product purchases an additional $89.2 million.
About Targa Resources Partners
Targa Resources Partners was formed by Targa Resources, Inc. (“Targa” or the “Company”) to engage
in the business of gathering, compressing, treating, processing and selling natural gas and
fractionating and selling natural gas liquids and natural gas liquids products. Targa Resources
Partners owns an extensive network of integrated gathering pipelines and seven natural gas
processing plants and currently operates in Southwest Louisiana, the Permian Basin in West Texas
and the Fort Worth Basin in North Texas. Additionally, our natural gas liquids logistics and
marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in
Lake Charles, Louisiana with terminals and transportation assets across the United States. A
subsidiary of Targa is the general partner of Targa Resources Partners.
Targa Resources Partners’ principal executive offices are located at 1000 Louisiana, Suite 4300,
Houston, Texas 77002 and its telephone number is 713-584-1000. For more information, visit
www.targaresources.com.
13
Non-GAAP Financial Measures
This press release and accompanying schedules include the non-GAAP financial measures Adjusted
EBITDA, operating margin and distributable cash flow. The accompanying schedules provide
reconciliations of these non-GAAP financial measures to their most directly comparable financial
measure calculated and presented in accordance with U.S. generally accepted accounting principles
(“GAAP”). Our 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— We define distributable cash flow as net income attributable to Targa
Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt
issue costs included in interest expense, adjusted for losses/(gains) on mark-to-market derivative
contracts and debt repurchases, less maintenance capital expenditures. Distributable cash flow is a
significant performance metric used by us and by external users of our financial statements, such
as investors, commercial banks, research analysts and others to compare basic cash flows generated
by us (prior to the establishment of any retained cash reserves by the board of directors of our
general partner) to the cash distributions we expect to pay our unitholders. Using this metric,
management can quickly compute the coverage ratio of estimated cash flows to planned cash
distributions. Distributable cash flow is also an important financial measure for our unitholders
since it serves as an indicator of our success in providing a cash return on investment.
Specifically, this financial measure indicates to investors whether or not we are generating cash
flow at a level that can sustain or support an increase in our 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). The economic substance behind our
use of distributable cash flow is to measure the ability of our assets to generate cash flow
sufficient to make distributions to our 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. You should not consider
distributable cash flow in isolation or as a substitute for analysis of our 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 our industry, our definition of
distributable cash flow may not be compatible to similarly titled measures of other companies,
thereby diminishing its utility. We compensate for the limitations of distributable cash flow as an
analytical tool by reviewing the comparable GAAP measures, understanding the differences between
the measures and incorporating these insights into our decision making processes.
14
The following table presents a reconciliation of net income to distributable cash flow for the
periods indicated:
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Reconciliation of net income (loss) to Targa Resources
Partners LP to distributable cash flow: |
||||||||||||||||
Net income attributable to Targa Resources Partners LP |
$ | 38.4 | $ | 19.8 | $ | 52.0 | $ | 49.4 | ||||||||
Add: |
||||||||||||||||
Depreciation and amortization expense |
25.7 | 25.0 | 101.2 | 97.8 | ||||||||||||
Deferred income tax expense |
— | 0.4 | 0.8 | 1.8 | ||||||||||||
Amortization of debt issue costs |
1.3 | 0.6 | 3.8 | 2.1 | ||||||||||||
Loss (gain) on debt repurchases |
— | (13.1 | ) | 1.5 | (13.1 | ) | ||||||||||
Non-cash loss related to mark-to-market derivatives |
3.8 | 11.8 | 37.6 | 23.4 | ||||||||||||
Maintenance capital expenditures |
(7.9 | ) | (11.7 | ) | (20.0 | ) | (40.3 | ) | ||||||||
Other |
(0.2 | ) | — | (0.6 | ) | (0.4 | ) | |||||||||
Distributable cash flow |
$ | 61.1 | $ | 32.8 | $ | 176.3 | $ | 120.7 | ||||||||
Adjusted EBITDA—The Partnership defines Adjusted EBITDA as net income before interest, income
taxes, depreciation and amortization and non-cash income or loss related to derivative instruments.
Adjusted EBITDA is used as a supplemental financial measure by management and by external users of
the Partnership’s financial statements such as investors, commercial banks and others, to assess:
(1) the financial performance of the Partnership’s assets without regard to financing methods,
capital structure or historical cost basis; (2) the Partnership’s operating performance and return
on capital compared to other companies in the midstream energy sector, without regard to
financing or capital structure; and (3) the viability of acquisitions and capital expenditure
projects and the overall rates of return on alternative investment opportunities.
The economic substance behind management’s use of Adjusted EBITDA is to measure the ability of the
Partnership’s assets to generate cash sufficient to pay interest costs, support indebtedness and
make distributions to unitholders. The GAAP measure most directly comparable to Adjusted EBITDA is
net income. The Partnership’s non-GAAP financial measure of Adjusted EBITDA should not be
considered as an alternative to GAAP net income. Adjusted EBITDA is not a presentation made in
accordance with GAAP and has important limitations as an analytical tool. You 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 is defined differently by different companies, 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 learnings into its decision-making processes.
Operating Margin— With respect to the Natural Gas Gathering and Processing division, the
Partnership defines operating margin as total operating revenues, which consist of natural gas and
NGL
15
sales plus service fee revenues, less product purchases, which consist primarily of producer
payments and other natural gas purchases less operating expense. Natural gas and NGL sales revenue
includes settlement gains and losses on commodity hedges. Our Natural Gas Gathering and Processing
segment operating margin is impacted by volumes and commodity prices as well as by our contract mix
and hedging program, which are described in more detail in the Partnership’s reports and other
filings with the Securities and Exchange Commission.
With respect to our NGL Logistics and Marketing division, the Partnership defines operating margin
as total revenue, which consists primarily of service fee revenues and NGL sales, less cost of
sales, which consists primarily of NGL purchases and changes in inventory valuation. Within this
division, our management analyzes segment operating margin for each of the three segments per unit
of NGL handled or sold as an indicator of operational and commercial performance.
The GAAP measure most directly comparable to operating margin is net income. The Partnership’s
non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP
net income. Operating margin is not a presentation made in accordance with GAAP and has important
limitations as an analytical tool. You should not consider operating margin in isolation or as a
substitute for analysis of the Partnership’s results as reported under GAAP. Because operating
margin excludes some, but not all, items that affect net income and is defined differently by
different companies, the Partnership’s definition of operating margin may not be comparable to
similarly titled measures of other companies, thereby diminishing its utility. Management
compensates for the limitations of operating margin as an analytical tool by reviewing the
comparable GAAP measures, understanding the differences between the measures and incorporating
these learnings into its decision-making processes.
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Reconciliation of net cash provided by
operating activities to Adjusted EBITDA: |
||||||||||||||||
Net cash provided by operating activities |
$ | 79.9 | $ | 164.4 | $ | 179.0 | $ | 293.0 | ||||||||
Net income attributable to noncontrolling interest |
(1.0 | ) | (0.2 | ) | (2.2 | ) | (0.3 | ) | ||||||||
Interest expense, net |
15.3 | 10.1 | 48.2 | 35.8 | ||||||||||||
Gain (loss) on debt repurchases |
— | 13.1 | (1.5 | ) | 13.1 | |||||||||||
Termination of commodity derivatives |
— | — | — | 87.4 | ||||||||||||
Current income tax expense |
0.2 | 0.2 | 0.2 | 0.6 | ||||||||||||
Other |
0.4 | — | (1.6 | ) | 3.7 | |||||||||||
Changes in operating working capital
which used (provided) cash: |
||||||||||||||||
Accounts receivable and other assets |
74.9 | (498.1 | ) | 69.4 | (658.2 | ) | ||||||||||
Accounts payable and other liabilities |
(85.1 | ) | 393.1 | (126.0 | ) | 494.3 | ||||||||||
Repayment of affiliate indebtedness |
— | — | 120.8 | — | ||||||||||||
Adjusted EBITDA |
$ | 84.6 | $ | 82.6 | $ | 286.3 | $ | 269.4 | ||||||||
16
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Reconciliation of net income (loss) attributable to Targa
Resources Partners LP to Adjusted EBITDA: |
||||||||||||||||
Net income to Targa Resources Partners LP |
$ | 38.4 | $ | 19.8 | $ | 52.0 | $ | 49.4 | ||||||||
Add: |
||||||||||||||||
Interest expense, net |
16.7 | 25.5 | 95.4 | 97.1 | ||||||||||||
Income tax expense |
0.2 | 0.6 | 1.0 | 2.4 | ||||||||||||
Depreciation and amortization expense |
25.7 | 25.0 | 101.2 | 97.8 | ||||||||||||
Non-cash loss related to derivatives |
3.8 | 11.7 | 37.6 | 23.4 | ||||||||||||
Noncontrolling interest adjustment |
(0.2 | ) | — | (0.9 | ) | (0.7 | ) | |||||||||
Adjusted EBITDA |
$ | 84.6 | $ | 82.6 | $ | 286.3 | $ | 269.4 | ||||||||
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
Reconciliation of net income (loss) attributable to Targa
Resources Partners LP to operating margin: |
||||||||||||||||
Net income to Targa Resources Partners LP |
$ | 38.4 | $ | 19.8 | $ | 52.0 | $ | 49.4 | ||||||||
Add: |
||||||||||||||||
Depreciation and amortization expense |
25.7 | 25.0 | 101.2 | 97.8 | ||||||||||||
General and administrative and other expense |
23.4 | 14.7 | 78.1 | 67.7 | ||||||||||||
Interest expense, net |
16.7 | 25.5 | 95.4 | 97.1 | ||||||||||||
Income tax benefit |
0.2 | 0.6 | 1.0 | 2.4 | ||||||||||||
Other, net |
(0.4 | ) | (19.7 | ) | (2.8 | ) | (17.1 | ) | ||||||||
Operating margin |
$ | 104.0 | $ | 65.9 | $ | 324.9 | $ | 297.3 | ||||||||
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 expects, believes or
anticipates will or may occur in the future are forward-looking statements. These forward-looking
statements rely on a number of assumptions concerning future events and are subject to a number of
uncertainties, factors and risks, many of which are outside Targa Resources Partners’ control,
which could cause results to differ materially from those expected by management of Targa Resources
Partners. Such risks and uncertainties include, but are not limited to, weather, political,
economic and market conditions, including declines in the production of natural gas or in the price
and market demand for natural gas and natural gas liquids, the timing and success of business
development efforts, the credit risk of customers and other uncertainties. These and other
applicable uncertainties, factors and risks are described more fully in the Partnership’s reports
and other filings with the Securities and Exchange Commission. Targa
Resources Partners undertakes no obligation to update or revise any forward-looking statement,
whether as a result of new information, future events or otherwise.
17
Investor contact info:
Phone: 713-584-1133
Anthony Riley
Senior Manager — Finance/Investor Relations
Senior Manager — Finance/Investor Relations
Matt Meloy
Vice President — Finance and Treasurer
Vice President — Finance and Treasurer
18
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED BALANCE SHEET DATA
(In millions)
(In millions)
| December 31, | December 31, | |||||||
| 2009 | 2008 | |||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 60.4 | $ | 95.3 | ||||
Trade receivables |
328.3 | 236.1 | ||||||
Inventory |
39.3 | 72.2 | ||||||
Assets from risk management activities |
25.8 | 91.8 | ||||||
Other current assets |
1.2 | 0.8 | ||||||
Total current assets |
455.0 | 496.2 | ||||||
Property, plant and equipment, net |
1,678.5 | 1,719.1 | ||||||
Long-term assets from risk management activities |
9.1 | 68.3 | ||||||
Other assets |
38.3 | 31.2 | ||||||
Total assets |
$ | 2,180.9 | $ | 2,314.8 | ||||
LIABILITIES AND PARTNERS’ CAPITAL |
||||||||
Current liabilities: |
||||||||
Accounts payable and accrued liabilities |
$ | 379.6 | $ | 260.1 | ||||
Liabilities from risk management activities |
16.3 | 11.7 | ||||||
Total current liabilities |
395.9 | 271.8 | ||||||
Long-term debt payable to third parties |
908.4 | 696.8 | ||||||
Long-term debt payable to Targa Resources, Inc. |
— | 773.9 | ||||||
Long term liabilities from risk management activities |
28.9 | 9.7 | ||||||
Other long-term liabilities |
11.5 | 9.5 | ||||||
Total liabilities |
1,344.7 | 1,761.7 | ||||||
Owner’s equity: |
||||||||
Targa Resources Partners LP owner’s equity |
822.8 | 539.0 | ||||||
Noncontrolling interest in subsidiary |
13.4 | 14.1 | ||||||
Total owners’ equity |
836.2 | 553.1 | ||||||
Total liabilities and owners’ equity |
$ | 2,180.9 | $ | 2,314.8 | ||||
19
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED
STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(In millions, except per unit data)
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
REVENUES |
$ | 1,254.8 | $ | 1,065.9 | $ | 4,095.6 | $ | 7,502.1 | ||||||||
COSTS AND EXPENSES: |
||||||||||||||||
Product purchases |
1,107.8 | 943.7 | 3,585.6 | 6,950.8 | ||||||||||||
Operating expenses |
43.0 | 56.3 | 185.1 | 254.0 | ||||||||||||
Depreciation and amortization expense |
25.7 | 25.0 | 101.2 | 97.8 | ||||||||||||
General and administrative expense |
23.4 | 11.2 | 78.9 | 68.6 | ||||||||||||
Other |
— | 3.5 | (0.8 | ) | (0.9 | ) | ||||||||||
Total costs and expenses |
1,199.9 | 1,039.7 | 3,950.0 | 7,370.3 | ||||||||||||
INCOME FROM OPERATIONS |
54.9 | 26.2 | 145.6 | 131.8 | ||||||||||||
Other income (expense): |
||||||||||||||||
Interest expense from affiliate |
— | (14.8 | ) | (43.4 | ) | (59.2 | ) | |||||||||
Interest expense allocated from Parent |
— | — | — | — | ||||||||||||
Other interest expense, net |
(16.7 | ) | (10.7 | ) | (52.0 | ) | (37.9 | ) | ||||||||
Equity in earnings of unconsolidated investments |
1.8 | 0.9 | 5.0 | 3.9 | ||||||||||||
Gain (loss) on debt repurchases |
— | 13.1 | (1.5 | ) | 13.1 | |||||||||||
Other income (expense) |
(0.4 | ) | 5.9 | 1.5 | 0.4 | |||||||||||
Income (loss) before income taxes |
39.6 | 20.6 | 55.2 | 52.1 | ||||||||||||
Income tax (expense) benefit |
(0.2 | ) | (0.6 | ) | (1.0 | ) | (2.4 | ) | ||||||||
NET INCOME |
39.4 | 20.0 | 54.2 | 49.7 | ||||||||||||
Less: Net income to noncontrolling interest |
1.0 | 0.2 | 2.2 | 0.3 | ||||||||||||
NET INCOME TO TARGA RESOURCES PARTNERS LP |
$ | 38.4 | $ | 19.8 | $ | 52.0 | $ | 49.4 | ||||||||
Net loss attributable to predecessor operations |
$ | — | $ | (3.9 | ) | $ | (2.4 | ) | $ | (42.1 | ) | |||||
Net income attributable to general partner |
3.6 | 1.5 | 10.4 | 7.0 | ||||||||||||
Net income attributable to limited partners |
34.8 | 22.2 | 44.0 | 84.5 | ||||||||||||
Net income attributable to Targa Resources Partners LP |
$ | 38.4 | $ | 19.8 | $ | 52.0 | $ | 49.4 | ||||||||
Basic and diluted net income per limited partner unit |
$ | 0.56 | $ | 0.48 | $ | 0.86 | $ | 1.83 | ||||||||
Basic and diluted weighted average limited partner units outstanding |
61.6 | 46.3 | 51.2 | 46.2 | ||||||||||||
20
| Three Months Ended | Year Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||||||||
Net income |
$ | 39.4 | $ | 20.0 | $ | 54.2 | $ | 49.7 | ||||||||
Adjustments to reconcile net income to net cash
provided by operating activities: |
||||||||||||||||
Depreciation, amortization and accretion |
27.2 | 25.9 | 105.7 | 100.6 | ||||||||||||
Deferred income tax expense |
— | 0.4 | 0.8 | 1.8 | ||||||||||||
Interest expense on affiliate indebtedness |
— | 14.8 | 43.4 | 59.2 | ||||||||||||
Risk management activities |
3.8 | 11.7 | 37.6 | (64.0 | ) | |||||||||||
Equity in earnings of unconsolidated investments, net of distribution |
(0.7 | ) | 1.1 | — | 0.8 | |||||||||||
Loss on debt repurchases |
— | (13.1 | ) | 1.5 | (13.1 | ) | ||||||||||
Gain on sale of assets |
— | (1.5 | ) | — | (5.9 | ) | ||||||||||
Changes in operating assets and liabilities |
10.2 | 105.1 | 56.6 | 163.9 | ||||||||||||
Repayment of affiliated indebtedness |
— | — | (120.8 | ) | — | |||||||||||
Net cash provided by operating activities |
79.9 | 164.4 | 179.0 | 293.0 | ||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||||||||
Additions to property, plant and equipment |
(10.9 | ) | (31.0 | ) | (57.2 | ) | (86.3 | ) | ||||||||
Other, net |
— | 0.1 | 0.1 | 0.2 | ||||||||||||
Net cash used in investing activities |
(10.9 | ) | (30.9 | ) | (57.1 | ) | (86.1 | ) | ||||||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||||||||
Proceeds from borrowings under credit facility |
171.6 | 97.8 | 569.2 | 185.3 | ||||||||||||
Repayments on credit facility |
(202.8 | ) | — | (577.7 | ) | (323.8 | ) | |||||||||
Proceeds from issuance of senior notes |
— | — | 237.4 | 250.0 | ||||||||||||
Repurchases of senior notes |
— | (26.8 | ) | (18.9 | ) | (26.8 | ) | |||||||||
Repayment of affiliated indebtedness |
— | — | (276.7 | ) | — | |||||||||||
Proceeds from equity offerings |
(0.4 | ) | — | 103.1 | — | |||||||||||
Distributions to unitholders |
(35.2 | ) | (26.5 | ) | (114.3 | ) | (91.0 | ) | ||||||||
General partner contributions |
— | — | 2.2 | — | ||||||||||||
Costs incurred in connection with public offerings |
0.2 | (0.1 | ) | — | (0.1 | ) | ||||||||||
Costs incurred in connection with financing arrangements |
— | — | (9.6 | ) | (7.1 | ) | ||||||||||
Distributions to noncontrolling interest |
1.4 | 0.3 | (0.3 | ) | 0.3 | |||||||||||
Loan from Parent |
— | 3.4 | — | 3.4 | ||||||||||||
Parent distributions |
(1.1 | ) | (129.9 | ) | (71.2 | ) | (166.1 | ) | ||||||||
Net cash used in financing activities |
(66.3 | ) | (81.8 | ) | (156.8 | ) | (175.9 | ) | ||||||||
Net change in cash and cash equivalents |
2.7 | 51.7 | (34.9 | ) | 31.0 | |||||||||||
Cash and cash equivalents, beginning of period |
57.7 | 43.6 | 95.3 | 64.3 | ||||||||||||
Cash and cash equivalents, end of period |
$ | 60.4 | $ | 95.3 | $ | 60.4 | $ | 95.3 | ||||||||
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