e8vk
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
Date of Report (Date of earliest event reported)
November 4, 2010
TARGA RESOURCES PARTNERS LP
(Exact name of registrant as specified in its charter)
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Delaware
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001-33303
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65-1295427 |
(State or other jurisdiction
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(Commission
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(IRS Employer |
of incorporation or organization)
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File Number)
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Identification No.) |
1000 Louisiana, Suite 4300
Houston, TX 77002
(Address of principal executive office and Zip Code)
(713) 584-1000
(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 November 4, 2010 Targa Resources Partners LP (the Partnership) issued a press release
regarding its financial results for the three months ended September 30, 2010. A conference call
to discuss these results is scheduled for 12:00 p.m. Eastern time on Thursday, November 4, 2010.
The conference call will be webcast live and a replay of the webcast will be available through the
Investors section of the Partnerships web site (http://www.targaresources.com) until
November 18, 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, gross margin, 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
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Exhibit |
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Number |
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Description |
Exhibit 99.1
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Targa Resources Partners LP Press Release dated November 4, 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.
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TARGA RESOURCES PARTNERS LP
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By: |
Targa Resources GP LLC,
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its general partner |
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Dated: November 4, 2010 |
By: |
/s/ Jeffrey J. McParland
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Jeffrey J. McParland |
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Executive Vice President and Chief Financial Officer |
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EXHIBIT INDEX
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Exhibit |
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Number |
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Description |
Exhibit 99.1
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Targa Resources Partners LP Press Release dated November 4, 2010. |
exv99w1
Exhibit 99.1
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1000 Louisiana, Suite 4300
Houston, TX 77002
713.584.1000
www.targaresources.com |
Targa Resources Partners LP Reports Third Quarter 2010 Financial Results and
Distribution Increase for Fourth Quarter 2010 to be Recommended by Management
HOUSTON November 4, 2010 Targa Resources Partners LP (Targa Resources Partners or the
Partnership) (NYSE: NGLS) today reported third quarter 2010 net income attributable to Targa
Resources Partners of $13.8 million, or $0.14 per diluted limited partner unit, compared to a net
loss of $4.2 million, or $0.23 per diluted limited partner unit, for the third quarter of 2009. Net
income for the third quarters of 2010 and 2009 included $7.8 million and $17.1 million in non-cash
charges related to derivative instruments, respectively. The third quarters of 2010 and 2009 also
included $3.9 million and $29.4 million in affiliate interest expenses, respectively, for periods
prior to the acquisition of the Downstream Business, the Permian, Straddle and Versado Systems and
VESCO by the Partnership.
The Partnership reported earnings before interest, income taxes, depreciation and amortization and
non-cash income or loss related to derivative instruments (Adjusted EBITDA) of $91.4 million for
the third quarter of 2010 compared to $98.9 million for the third quarter of 2009.
Distributable cash flow for the third quarter of 2010 of $57.1 million corresponds to distribution
coverage of over 1.2 times the $46.1 million in total distributions to be paid on November 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).
In addition to delivering strong third quarter financial results we are pleased to have completed
a number of key growth initiatives during the quarter, said Rene Joyce, Chief Executive Officer of
the Partnerships general partner and of Targa Resources, Inc (Targa). During the quarter we
closed two accretive acquisitions from Targa including interests in the Versado and VESCO gathering
and processing systems; announced two growth projects in the Downstream Business; approved very
attractive expansion projects associated with our operations in the Permian Basin of West Texas and
approved managements recommended distribution increase for the third quarter. We continue to see
incremental growth opportunities for our Gathering and Processing and Downstream Businesses and we
therefore plan to recommend to the Board of Directors a 4 cent increase in the annualized cash
distribution rate to $2.19 per common unit for the fourth quarter of 2010 distribution.
The fourth quarter recommended cash distribution of 54.75¢ per common unit, or $2.19 unit on an
annualized basis, (if approved by the board) is currently expected to be declared in January 2011
and paid in February 2011.
On October 8, 2010, the Partnership announced a cash distribution of 53.75¢ per common unit, or
$2.15 per unit on an annualized basis, for the third quarter of 2010. The cash distribution will be
paid on November 12, 2010 to all outstanding common and general partner units to holders of record
as of the close of business on October 18, 2010.
Capitalization, Liquidity and Financing Update
Total funded debt as of September 30, 2010 was approximately $1,433.2 million including $753.3
million outstanding under the Partnerships $1.1 billion senior secured revolving credit facility,
$209.1 million of 8.25% senior unsecured notes due 2016, $220.8 million of 11.25% senior unsecured
notes due 2017 and $250 million of 7.875% senior unsecured notes due 2018.
On July 19, 2010, the Partnership entered into an amended and restated five-year $1.1 billion
senior secured revolving credit facility due July 2015 that allows for increases in commitments up
to an additional $300 million. The new senior secured credit facility amends and restates the
former $977.5 million senior secured revolving credit facility due February 2012.
On August 13, 2010, the Partnership completed a public offering of 7,475,000 common units
(6,500,000 common units plus an overallotment option of 975,000 common units) and the private
offering of $250 million of 7.875% Senior Notes due 2018. The Partnership used the net proceeds
from these offerings to reduce borrowings under the senior secured credit facility.
On August 25, 2010, the Partnership acquired Targa Resources, Inc.s interests in the Versado
System for $247.2 million. On September 28, 2010, the Partnership acquired Targa Resources, Inc.s
interests in VESCO for $175.6 million. The Partnership financed these acquisitions substantially
through borrowings under its senior secured revolving credit facility.
As of September 30, 2010, the Partnership had $245.2 million in capacity available under its senior
secured revolving credit facility after giving effect to the issuance of $101.5 million of letters
of credit.
We estimate that total capital expenditures of the Partnership will be approximately $145 million
for 2010. Maintenance capital expenditures account for approximately 35% of the total 2010
estimate.
Conference Call
Targa Resources Partners will host a conference call for investors and analysts at 12 p.m. Eastern
Time (11 a.m. Central Time) on November 4, 2010 to discuss third quarter 2010 financial results.
The conference call can be accessed via Webcast through the Events and Presentations section of the
Partnerships website at www.targaresources.com, by going directly to http://ir.targaresources.com/events.cfm?company=LP or by dialing 877-881-2598. The pass code for
the dial-in is 22737218. 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
Investors section of the Partnerships website. Telephone replay access numbers are 800-642-1687
or 706-645-9291 with pass code 22737218 and will remain available, along with the Webcast, until
November 18, 2010.
2
Consolidated Financial Results of Operations
With the closing of the acquisition of the Downstream Business in 2009, the Permian, Straddle and
Versado Systems and VESCO in 2010, 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, Permian, Straddle and Versado Systems and VESCO for all periods
presented.
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2010 |
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2009 |
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2010 |
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2009 |
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(In millions, except |
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operating and price data) |
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Revenues (1) |
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$ |
1,216.9 |
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$ |
1,118.0 |
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$ |
3,938.3 |
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$ |
3,120.6 |
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Product purchases |
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1,032.1 |
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936.2 |
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3,387.7 |
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2,624.6 |
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Gross margin (2) |
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184.8 |
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181.8 |
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550.6 |
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496.0 |
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Operating expenses |
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66.0 |
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63.2 |
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190.2 |
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182.1 |
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Operating margin (3) |
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118.8 |
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118.6 |
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360.4 |
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313.9 |
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Depreciation and amortization expense |
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43.3 |
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43.1 |
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128.3 |
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125.0 |
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General and administrative expense |
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26.7 |
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22.6 |
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80.0 |
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81.9 |
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Casualty loss adjustment |
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(3.8 |
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Income from operations |
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48.8 |
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52.9 |
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152.1 |
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110.8 |
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Other income (expense): |
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Interest expense from affiliate |
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(2.5 |
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(27.2 |
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(23.8 |
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(84.2 |
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Interest expense allocated from Parent |
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(1.4 |
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(2.2 |
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(5.6 |
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(6.9 |
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Other interest expense, net |
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(23.3 |
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(16.1 |
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(56.4 |
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(35.2 |
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Other |
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(1.5 |
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(6.2 |
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29.0 |
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(9.2 |
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Income tax benefit (expense) |
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(1.7 |
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0.2 |
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(3.9 |
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(0.9 |
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Net income |
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18.4 |
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1.4 |
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91.4 |
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(25.6 |
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Less: Net income attributable to noncontrolling interest |
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4.6 |
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5.6 |
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18.2 |
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11.9 |
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Net income (loss) attributable to Targa Resources Partners LP |
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$ |
13.8 |
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$ |
(4.2 |
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$ |
73.2 |
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$ |
(37.5 |
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Net loss attributable to predecessor operations |
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$ |
(1.3 |
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$ |
(18.4 |
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$ |
25.8 |
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$ |
(53.4 |
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Net income attributable to general partner |
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5.0 |
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2.8 |
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12.0 |
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6.7 |
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Net income allocable to limited partners |
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10.1 |
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11.4 |
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35.4 |
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9.2 |
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Net income (loss) attributable to Targa Resources Partners LP |
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$ |
13.8 |
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$ |
(4.2 |
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$ |
73.2 |
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$ |
(37.5 |
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Basic and diluted net income (loss) per limited partner unit |
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$ |
0.14 |
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$ |
0.23 |
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$ |
0.51 |
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$ |
0.19 |
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Financial data: |
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Adjusted EBITDA (4) |
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91.4 |
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98.9 |
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278.7 |
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278.6 |
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Distributable cash flow (5) |
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57.1 |
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78.8 |
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198.8 |
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216.8 |
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(1) |
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Includes business interruption insurance revenues of $1.0 million and $6.0 million for the
three and nine months of 2009. |
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(2) |
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Gross margin is revenues less product purchases. See Non-GAAP Financial Measures. |
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(3) |
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Operating margin is gross margin less operating expenses. See Non-GAAP Financial Measures. |
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(4) |
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Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization
and non-cash gain or loss related to derivative instruments. See Non-GAAP Financial
Measures. |
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(5) |
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Distributable cash flow is net income plus depreciation and amortization and deferred taxes,
adjusted for losses on mark to market derivative contracts, less maintenance capital
expenditures. See Non-GAAP Financial Measures. |
Review of Consolidated Second Quarter Results
Three Months Ended September 30, 2010 Compared to Three Months Ended September, 2009
Revenue increased $98.9 million due to higher commodity prices ($183.1 million) offset by lower
sales volumes ($83.8 million) and lower fee-based and other revenues ($0.4 million).
The $3.0 million increase in gross margin reflects higher revenue of $98.9 million offset by higher
product purchase costs of $95.9 million.
For additional information regarding the period to period changes in our gross margins, see Review
of Segment Performance
The $2.8 million increase in operating expenses was primarily due to increased compensation and
benefit costs and increased non-capitalized maintenance costs, offset by decreased costs associated
with outside contract services and lower professional fees.
The increase in depreciation and amortization expense is primarily attributable to assets acquired
in 2009 that now have a full period of depreciation and capital expenditures during 2010, as well
as incremental depreciation on capital expenditures in 2010 of $36.5 million.
The increase in general and administrative expense reflects primarily higher compensation costs and
the timing of allocations under common control.
The decrease in interest expense was primarily due to lower interest rates on third party debt than
on affiliate debt associated with predecessor operations.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
Revenues increased $817.7 million due to higher commodity prices ($1,080.5 million) offset by lower
sales volumes ($249.0 million), lower business interruption proceeds ($6.0 million) and lower
fee-based and other revenues ($7.8 million).
The $54.6 million increase in gross margin reflects higher revenues of $817.7 million, offset by
higher product purchase costs of $763.1 million.
For additional information regarding the period to period changes in our gross margins, see Review
of Segment Performance
4
The $8.1 million increase in operating expenses was primarily due to increased compensation and
benefits costs, increased non-capitalized maintenance costs and increased environmental spending,
offset by decreased costs associated with outside contract services and lower professional fees.
The increase in depreciation and amortization expense is primarily attributable to assets acquired
in 2009 that now have a full period of depreciation and capital expenditures during 2010, as well
as incremental depreciation on capital expenditures in 2010 of $82.5 million.
The decrease in general and administrative expense was primarily driven by the timing of
allocations under common control.
The decrease in interest expense was primarily due to lower interest rates on third party debt than
on affiliate debt associated with predecessor operations.
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. Operating margin is revenues less product purchases and operating
expenses. 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 for the period and the denominator is the number of calendar days for the period.
In connection with the April 2010 acquisition of Targas interest in the Permian and Straddle
Systems and its impact on our structure used for internal management purposes, an updated
evaluation of our reportable segments was performed during the second quarter of 2010. As a result,
our operations are now presented under four reportable segments: (1) Field Gathering and
Processing, (2) Coastal Gathering and Processing, (3) Logistics Assets and (4) Marketing and
Distribution.
5
Field Gathering and Processing Segment
The Field 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 Field Gathering and Processing segment assets are
located in North Texas and the Permian Basin. The following table provides summary data regarding
results of operations of this segment for the periods indicated:
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2010 |
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2009 |
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2010 |
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2009 |
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($ in millions) |
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Gross margin |
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$ |
77.4 |
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$ |
68.5 |
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$ |
250.4 |
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$ |
187.1 |
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Operating expenses |
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(27.8 |
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(22.6 |
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(73.6 |
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(63.7 |
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Operating margin (1) |
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$ |
49.6 |
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$ |
45.9 |
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$ |
176.8 |
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$ |
123.4 |
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Operating statistics (2): |
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Plant natural gas inlet, MMcf/d |
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Permian System |
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127.3 |
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114.6 |
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127.0 |
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117.8 |
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SAOU System |
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102.6 |
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92.0 |
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97.3 |
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92.1 |
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North Texas System |
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182.7 |
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172.7 |
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177.2 |
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176.2 |
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Versado System |
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171.0 |
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200.8 |
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180.5 |
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199.5 |
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583.6 |
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580.1 |
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582.0 |
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585.6 |
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Gross NGL production, MBbl/d |
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Permian System |
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14.9 |
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12.8 |
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14.5 |
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13.2 |
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SAOU System |
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15.6 |
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14.0 |
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15.0 |
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14.2 |
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North Texas System |
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20.9 |
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20.5 |
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20.3 |
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20.5 |
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Versado System |
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19.2 |
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22.2 |
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20.4 |
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22.2 |
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70.6 |
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69.5 |
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70.2 |
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70.1 |
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Natural gas sales, BBtu/d |
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254.5 |
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241.4 |
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257.2 |
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244.0 |
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NGL sales, MBbl/d |
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54.9 |
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55.3 |
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55.6 |
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55.4 |
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Condensate sales, MBbl/d |
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|
3.1 |
|
|
|
3.3 |
|
|
|
3.0 |
|
|
|
3.5 |
|
Average realized prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
|
4.00 |
|
|
|
2.95 |
|
|
|
4.30 |
|
|
|
3.12 |
|
NGL, $/gal |
|
|
0.86 |
|
|
|
0.72 |
|
|
|
0.91 |
|
|
|
0.63 |
|
Condensate, $/Bbl |
|
|
72.10 |
|
|
|
63.61 |
|
|
|
73.82 |
|
|
|
51.41 |
|
|
|
|
(1) |
|
Operating margin is revenues less product purchases and operating expenses. |
|
(2) |
|
Segment operating statistics include the effect of intersegment sales, which have been
eliminated from the consolidated presentation. For all volume statistics presented, the numerator
is the total
volume sold during the period and the denominator is the number of calendar days during the
period. |
6
Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009
The $8.9 million increase in gross margin for 2010 is primarily due to an increase in commodity
sales prices ($56.5 million) and an increase in natural gas sales volumes ($3.6 million) partially
offset by a decrease NGL and condensate revenue ($2.1 million), fee-based and other revenues ($1.5
million) and increased commodity purchase costs ($47.6 million). The increased volumes were largely
attributable to new well connects throughout our systems, partially offset by production declines
at our Versado System, combined with planned and unplanned operational outages at our Eunice Plant.
The $5.2 million increase in operating expenses for 2010 was primarily due to increases in system
maintenance expenses of $3.2 million, primarily attributable to the Eunice plant operational
outages and higher compensation and benefits costs of $1.3 million.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
The $63.3 million increase in gross margin for 2010 is primarily due to an increase in commodity
sales prices ($280.1 million), an increase in natural gas and NGL sales volumes ($12.4 million) and
an increase in fee-based and other revenues ($2.4 million), offset by lower condensate sales
volumes ($6.2 million) and increased commodity purchase costs ($225.4 million). The increased
volumes were largely attributable to new well connects throughout our systems, partially offset at
Versado by production declines in the high volume Morrow formation combined with operational
outages.
The $9.9 million increase in operating expenses for 2010 was primarily due to increases in system
maintenance expenses of $5.2 million and compensation and benefits costs of $2.5 million.
7
Coastal Gathering and Processing Segment
The Coastal Gas Gathering and Processing segment consists of the gathering of natural gas produced
from oil and gas wells and processing this raw natural gas into merchantable natural gas by
extracting natural gas liquids and removing impurities. Coastal Gathering and Processing segment
assets are located in the onshore region of the Louisiana Gulf Coast and Gulf of Mexico.
The following table provides summary data regarding results of operations of this segment for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
($ in millions) |
|
|
|
|
|
Gross margin |
|
$ |
34.2 |
|
|
$ |
34.2 |
|
|
$ |
106.3 |
|
|
$ |
87.7 |
|
Operating expenses |
|
|
(10.7 |
) |
|
|
(14.1 |
) |
|
|
(31.4 |
) |
|
|
(34.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin (1) |
|
$ |
23.5 |
|
|
$ |
20.1 |
|
|
$ |
74.9 |
|
|
$ |
52.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating statistics (2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOU System |
|
|
163.7 |
|
|
|
199.4 |
|
|
|
190.6 |
|
|
|
174.2 |
|
Straddle System |
|
|
1,041.3 |
|
|
|
1,149.0 |
|
|
|
1,100.6 |
|
|
|
983.2 |
|
VESCO System |
|
|
427.7 |
|
|
|
345.8 |
|
|
|
423.3 |
|
|
|
354.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,632.7 |
|
|
|
1,694.2 |
|
|
|
1,714.5 |
|
|
|
1,512.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOU System |
|
|
7.1 |
|
|
|
9.0 |
|
|
|
7.4 |
|
|
|
8.5 |
|
Straddle System |
|
|
19.1 |
|
|
|
20.2 |
|
|
|
20.1 |
|
|
|
16.0 |
|
VESCO System |
|
|
24.8 |
|
|
|
24.8 |
|
|
|
23.0 |
|
|
|
22.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51.0 |
|
|
|
54.0 |
|
|
|
50.5 |
|
|
|
47.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales, BBtu/d |
|
|
292.0 |
|
|
|
283.5 |
|
|
|
305.3 |
|
|
|
249.2 |
|
NGL sales, MBbl/d |
|
|
42.4 |
|
|
|
44.2 |
|
|
|
44.0 |
|
|
|
39.5 |
|
Condensate sales, MBbl/d |
|
|
0.2 |
|
|
|
1.5 |
|
|
|
0.6 |
|
|
|
1.6 |
|
Average realized prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
|
4.41 |
|
|
|
3.42 |
|
|
|
4.64 |
|
|
|
3.88 |
|
NGL, $/gal |
|
|
0.93 |
|
|
|
0.78 |
|
|
|
1.00 |
|
|
|
0.69 |
|
Condensate, $/Bbl |
|
|
72.42 |
|
|
|
78.81 |
|
|
|
78.45 |
|
|
|
55.59 |
|
|
|
|
(1) |
|
Operating margin is revenues less product purchases and operating expenses. |
|
(2) |
|
Segment operating statistics include the effect of intersegment sales, which have been
eliminated from the consolidated presentation. For all volume statistics presented, the numerator
is the total volume sold during the period and the denominator is the number of calendar days
during the period. |
|
(3) |
|
The majority of Straddle System volumes are gathered on third party offshore pipeline systems
and delivered to the plant inlets. |
8
Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009
Gross margin for 2010 was flat when compared to 2009 due to an increase in commodity sales prices
($51.3 million), natural gas sales volumes ($2.7 million) and fee-based and other revenues ($0.2
million), offset by a decrease in NGL and condensate sales volumes ($14.5 million) and an increase
in product purchase costs ($39.7 million). Natural gas sales volumes increased due to increased
sales to affiliates for resale partially offset by a decrease in demand from our industrial
customers. NGL sales volumes decreased primarily due to reduced plant inlet volumes resulting from
a decline in traditional wellhead and offshore supply volumes.
The $3.4 million decrease in operating expenses for 2010 was primarily due to lower system
maintenance expenses.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
The $18.6 million increase in gross margin for 2010 is primarily due to an increase in commodity
sales prices ($224.0 million) and commodity sales volumes ($80.6 million), offset by a decrease in
fee-based and other revenues ($5.7 million) and increased commodity purchase costs ($280.3
million). Natural gas sales volumes increased due to increased demand from our industrial customers
and increased sales to affiliates for resale. NGL sales volumes increased primarily due to the
straddle plants recovering operations in 1Q and 2Q 2009 after hurricanes Gustav and Ike in 2008.
The $3.5 million decrease in operating expenses for 2010 was primarily due to lower system
maintenance expenses, reflecting hurricane related spending in 2009.
9
Logistics Assets Segment
The Logistics Assets segment is involved in gathering and storing mixed NGLs and fractionating and
storing finished NGLs. These assets are generally connected to and supplied, in part, by our
gathering and processing segments and are predominantly located in Mont Belvieu, Texas and Western
Louisiana.
The following table provides summary data regarding results of operations of this segment for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
($ in millions) |
|
Gross margin (1) |
|
$ |
43.1 |
|
|
$ |
39.4 |
|
|
$ |
121.5 |
|
|
$ |
109.9 |
|
Operating expenses |
|
|
(19.5 |
) |
|
|
(18.0 |
) |
|
|
(68.6 |
) |
|
|
(62.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin (2) |
|
$ |
23.6 |
|
|
$ |
21.4 |
|
|
$ |
52.9 |
|
|
$ |
47.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fractionation volumes, MBbl/d |
|
|
224.6 |
|
|
|
225.9 |
|
|
|
220.9 |
|
|
|
215.4 |
|
Treating volumes, MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.8 |
|
|
|
27.5 |
|
|
|
17.8 |
|
|
|
18.5 |
|
|
|
|
(1) |
|
Gross margin consists of fee revenue and business interruption proceeds |
|
(2) |
|
Operating margin is revenues less product purchases and operating expenses. |
|
(3) |
|
Consists of the volumes treated in our low sulfur natural gasoline unit. |
Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009
The $3.7 million improvement in gross margin was primarily due to fractionation fee improvement.
Operating expenses increased primarily due to higher fuel and electricity expenses of $2.5 million
driven by higher gas prices, higher compensation costs of $0.9 million, partially offset by
favorable system product gains of $1.6 million.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
The $11.6 million improvement in gross margin reflects higher fractionation fees of $15.1 million,
offset by lower terminalling and storage revenues of $1.0 million. During 2009, we received $1.9
million in business interruption proceeds.
Operating expenses increased due to higher fuel and electricity expense of $5.8 million primarily
driven by higher gas prices and higher compensation costs of $3.2 million, which were partially
offset by favorable system product gains of $3.3 million.
10
Marketing and Distribution Segment
The Marketing and Distribution segment covers all activities required to distribute and market raw
and finished natural gas liquids. It includes (1) marketing our own natural gas liquids production
and purchasing natural gas liquids products in selected United States markets; (2) providing
liquefied petroleum gas balancing services to refinery customers; and (3) transporting, storing and
selling propane and providing related propane logistics services to multi-state retailers,
independent retailers and other end users.
The following table provides summary data regarding results of operations of this segment for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
($ in millions) |
|
Gross margin |
|
$ |
26.4 |
|
|
$ |
26.5 |
|
|
$ |
82.3 |
|
|
$ |
89.5 |
|
Operating expenses |
|
|
(11.4 |
) |
|
|
(11.9 |
) |
|
|
(33.5 |
) |
|
|
(35.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin (1) |
|
$ |
15.0 |
|
|
$ |
14.6 |
|
|
$ |
48.8 |
|
|
$ |
53.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales, BBtu/d |
|
|
612.6 |
|
|
|
561.9 |
|
|
|
630.1 |
|
|
|
497.7 |
|
NGL sales, MBbl/d |
|
|
242.9 |
|
|
|
266.6 |
|
|
|
241.3 |
|
|
|
281.4 |
|
Natural gas realized price, $/gal |
|
|
4.22 |
|
|
|
3.17 |
|
|
|
4.50 |
|
|
|
3.46 |
|
NGL realized price, $/gal |
|
|
0.95 |
|
|
|
0.81 |
|
|
|
1.06 |
|
|
|
0.72 |
|
|
|
|
(1) |
|
Operating margin is revenues less product purchases and operating expenses. |
Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009
Gross margin was flat for the quarter, reflecting the impact of higher commodity prices on revenues
($184.0 million) and increased natural gas volumes ($14.8 million), offset by lower NGL volumes
($74.4 million) and increased product purchases ($125.2 million).
Natural gas sales volumes are higher due to increased purchases for resale. NGL sales volumes are
lower due to a change in contract terms with a petrochemical supplier that has a minimal impact to
gross margin.
Operating expenses were relatively flat versus the prior quarter.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
The $7.2 million decrease in gross margin reflects increased commodity prices ($1,127.8 million)
and higher natural gas volumes ($124.9 million), more than offset by lower NGL volumes ($330.8),
lower fee based and other revenues ($20.5 million), lower business interruption proceeds ($0.5
million) and increased product purchases ($893.7 million). Lower 2010 margins on sales at inventory locations
were primarily attributable 2009 sales that were fixed at relatively high 2008 prices, along with
higher spot
11
fractionation volumes and associated fees. These items were partially offset by higher
marketing fees on higher on contract purchase volumes attributable to higher 2010 market prices.
Margins on transportation activity decreased due to the expiration of a barge contract partially
offset by increased truck activity.
Natural gas sales volumes are higher due to increased purchases for resale. NGL sales volumes are
lower due to a change in contract terms with a petrochemical supplier that has a minimal impact to
gross margin.
The decrease in operating expenses was primarily due to lower outside services of $5.5 million,
partially offset by higher maintenance and supplies expenses of $2.6 million and higher
compensation costs of $0.5 million. Factors contributing to the decrease were the expiration of a
barge contract, partially offset by increased truck utilization.
Other
Other includes the impact on operating margin of the Partnerships derivatives hedging activities.
Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009
During 2010 and 2009, the settlement of our commodity derivatives resulted in $7.1 million and
$16.7 million in additional revenue (cash and non-cash) from our hedge counterparties, which were
recorded as an increase to gross margin from hedge settlements during the quarters. Cash receipts
or payments on our hedge settlements are due to the contracted price of our hedge contracts falling
above or below the market prices of the commodity settled.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
During 2010 and 2009, the settlement of our commodity derivatives resulted in $7.0 million and
$36.6 million in additional revenue (cash and non-cash) from our hedge counterparties, which were
recorded as an increase to gross margin from hedge settlements during the quarters. Cash receipts
or payments on our hedge settlements are due to the contracted price of our hedge contracts falling
above or below the market prices of the commodity settled.
About Targa Resources Partners
Targa Resources Partners is engaged in the business of gathering, compressing, treating, processing
and selling natural gas and storing, fractionating, treating, transporting and selling natural gas
liquids, or NGLs, and NGL products. The Partnership owns an extensive network of integrated
gathering pipelines and gas processing plants and currently operates along the Louisiana Gulf Coast
primarily accessing the offshore region of Louisiana, the Permian Basin in West Texas and Southeast
New Mexico 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.
12
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.
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 units 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.
The following table presents a reconciliation of net income to distributable cash flow for the
periods indicated:
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Reconciliation of net income (loss) attributable to |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Targa Resources Partners LP to distributable cash flow: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Targa Resources Partners LP |
|
$ |
13.8 |
|
|
$ |
(4.2 |
) |
|
$ |
73.2 |
|
|
$ |
(37.5 |
) |
Add: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated and affiliate interest expense |
|
|
3.9 |
|
|
|
29.4 |
|
|
|
29.4 |
|
|
|
91.1 |
|
Depreciation and amortization expense |
|
|
43.3 |
|
|
|
43.1 |
|
|
|
128.3 |
|
|
|
125.0 |
|
Deferred income tax (expense) benefit |
|
|
(0.1 |
) |
|
|
0.1 |
|
|
|
0.3 |
|
|
|
0.9 |
|
Amortization of debt issue costs |
|
|
0.9 |
|
|
|
2.5 |
|
|
|
3.6 |
|
|
|
3.8 |
|
Gain on debt repurchases |
|
|
0.8 |
|
|
|
0.4 |
|
|
|
0.8 |
|
|
|
0.4 |
|
Non-cash (gain) loss related to mark-to-market derivative instruments |
|
|
7.8 |
|
|
|
17.1 |
|
|
|
(5.4 |
) |
|
|
71.2 |
|
Maintenance capital expenditures |
|
|
(12.9 |
) |
|
|
(8.0 |
) |
|
|
(28.5 |
) |
|
|
(33.4 |
) |
Reimbursements |
|
|
0.4 |
|
|
|
|
|
|
|
0.4 |
|
|
|
|
|
Other |
|
|
(0.8 |
) |
|
|
(1.6 |
) |
|
|
(3.3 |
) |
|
|
(4.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow |
|
$ |
57.1 |
|
|
$ |
78.8 |
|
|
$ |
198.8 |
|
|
$ |
216.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAThe 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 Partnerships financial statements such as investors, commercial banks and others, to assess:
(1) the financial performance of the Partnerships assets without regard to financing methods,
capital structure or historical cost basis; (2) the Partnerships 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 managements use of Adjusted EBITDA is to measure the ability of the
Partnerships 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 Partnerships 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 Partnerships 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 Partnerships 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.
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Reconciliation of net cash provided by operating |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
activities to Adjusted EBITDA: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
60.8 |
|
|
$ |
114.3 |
|
|
$ |
240.0 |
|
|
$ |
303.6 |
|
Net (income) loss attributable to noncontrolling interest |
|
|
(4.6 |
) |
|
|
(5.6 |
) |
|
|
(18.2 |
) |
|
|
(11.9 |
) |
Other interest expense, net |
|
|
22.4 |
|
|
|
13.5 |
|
|
|
52.8 |
|
|
|
31.4 |
|
Current income tax (expense) benefit |
|
|
1.8 |
|
|
|
(0.3 |
) |
|
|
3.6 |
|
|
|
|
|
Other |
|
|
(6.0 |
) |
|
|
(5.4 |
) |
|
|
(11.7 |
) |
|
|
(11.1 |
) |
Changes in operating working capital which used (provided) cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable and other |
|
|
26.6 |
|
|
|
(27.3 |
) |
|
|
(40.3 |
) |
|
|
(17.6 |
) |
Accounts payable and other liabilities |
|
|
(9.6 |
) |
|
|
9.7 |
|
|
|
52.5 |
|
|
|
(15.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
91.4 |
|
|
$ |
98.9 |
|
|
$ |
278.7 |
|
|
$ |
278.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net of amortization of debt issuance costs of $0.9 million and $3.6 for the three month
and nine months ended 2010 and $2.5 million and $3.8 million for the three and nine months
ended 2009. Excludes affiliate and allocated interest expense. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Reconciliation of net income (loss) attributable to |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Targa Resources Partners LP to Adjusted EBITDA: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Targa Resources Partners LP |
|
$ |
13.8 |
|
|
$ |
(4.2 |
) |
|
$ |
73.2 |
|
|
$ |
(37.5 |
) |
Add: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
|
|
27.2 |
|
|
|
45.5 |
|
|
|
85.8 |
|
|
|
126.3 |
|
Income tax (expense) benefit |
|
|
1.7 |
|
|
|
(0.2 |
) |
|
|
3.9 |
|
|
|
0.9 |
|
Depreciation and amortization expense |
|
|
43.3 |
|
|
|
43.1 |
|
|
|
128.3 |
|
|
|
125.0 |
|
Non-cash activities related to derivative instruments |
|
|
7.8 |
|
|
|
17.1 |
|
|
|
(5.4 |
) |
|
|
71.2 |
|
Noncontrolling interest adjustment |
|
|
(2.4 |
) |
|
|
(2.4 |
) |
|
|
(7.1 |
) |
|
|
(7.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
91.4 |
|
|
$ |
98.9 |
|
|
$ |
278.7 |
|
|
$ |
278.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
Gross Margin. With respect to our Natural Gas Gathering and Processing segments, we define
gross margin as total operating revenues, which consist of natural gas and NGL sales plus service
fee revenues, less product purchases, which consist primarily of producer payments and other
natural gas purchases. With respect to our Logistics segment we define operating margin as total
revenue, which consists primarily of service fee revenues. With respect to our Marketing and
Distribution segments, we define 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.
Operating Margin. With respect to our Natural Gas Gathering and Processing segments, our Logistics
segment and our Marketing and Distribution segment, we define operating margin as gross margin less
operating expense.
The GAAP measure most directly comparable to gross margin and operating margin is net income. The
Partnerships 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 Partnerships 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 Partnerships 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 |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Reconciliation of net income (loss) attributable to |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Targa Resources Partners LP to operating margin: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Targa Resources Partners LP |
|
$ |
13.8 |
|
|
$ |
(4.2 |
) |
|
$ |
73.2 |
|
|
$ |
(37.5 |
) |
Add: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization expense |
|
|
43.3 |
|
|
|
43.1 |
|
|
|
128.3 |
|
|
|
125.0 |
|
General and administrative expense |
|
|
26.7 |
|
|
|
22.6 |
|
|
|
80.0 |
|
|
|
81.9 |
|
Interest expense, net |
|
|
27.2 |
|
|
|
45.5 |
|
|
|
85.8 |
|
|
|
126.3 |
|
Income tax benefit (expense) |
|
|
1.7 |
|
|
|
(0.2 |
) |
|
|
3.9 |
|
|
|
0.9 |
|
Other, net |
|
|
6.1 |
|
|
|
11.8 |
|
|
|
(10.8 |
) |
|
|
17.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin |
|
$ |
118.8 |
|
|
$ |
118.6 |
|
|
$ |
360.4 |
|
|
$ |
313.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
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 Partnerships 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.
Investor contact info:
Phone: 713-584-1133
Anthony Riley
Senior Manager Finance/Investor Relations
Matt Meloy
Vice President Finance and Treasurer
17
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED
BALANCE SHEET DATA
(In millions)
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
54.5 |
|
|
$ |
90.9 |
|
Trade receivables |
|
|
351.0 |
|
|
|
405.5 |
|
Inventory |
|
|
54.9 |
|
|
|
39.3 |
|
Assets from risk management activities |
|
|
37.9 |
|
|
|
32.9 |
|
Other current assets |
|
|
1.0 |
|
|
|
1.9 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
499.3 |
|
|
|
570.5 |
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
2,480.0 |
|
|
|
2,526.6 |
|
Long-term assets from risk management activities |
|
|
27.5 |
|
|
|
13.9 |
|
Other assets |
|
|
56.2 |
|
|
|
41.8 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
3,063.0 |
|
|
$ |
3,152.8 |
|
|
|
|
|
|
|
|
LIABILITIES AND OWNERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
420.9 |
|
|
$ |
474.8 |
|
Liabilities from risk management activities |
|
|
20.5 |
|
|
|
29.2 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
441.4 |
|
|
|
504.0 |
|
|
|
|
|
|
|
|
Long-term debt payable to third parties |
|
|
1,433.2 |
|
|
|
908.4 |
|
Long-term debt allocated from Targa Resources, Inc. |
|
|
|
|
|
|
151.8 |
|
Long-term debt payable to Targa Resources, Inc. |
|
|
|
|
|
|
764.8 |
|
Long-term liabilities from risk management activities |
|
|
29.0 |
|
|
|
43.9 |
|
Other long-term liabilities |
|
|
56.5 |
|
|
|
51.6 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
1,960.1 |
|
|
|
2,424.5 |
|
Owners equity: |
|
|
|
|
|
|
|
|
Targa Resources Partners LP owners equity |
|
|
978.7 |
|
|
|
604.9 |
|
Noncontrolling interest in subsidiary |
|
|
124.2 |
|
|
|
123.4 |
|
|
|
|
|
|
|
|
Total owners equity |
|
|
1,102.9 |
|
|
|
728.3 |
|
|
|
|
|
|
|
|
Total liabilities and owners equity |
|
$ |
3,063.0 |
|
|
$ |
3,152.8 |
|
|
|
|
|
|
|
|
18
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED
STATEMENTS OF OPERATIONS
(In millions, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
REVENUES |
|
$ |
1,216.9 |
|
|
$ |
1,118.0 |
|
|
$ |
3,938.3 |
|
|
$ |
3,120.6 |
|
Product purchases |
|
|
1,032.1 |
|
|
|
936.2 |
|
|
|
3,387.7 |
|
|
|
2,624.6 |
|
Operating expenses |
|
|
66.0 |
|
|
|
63.2 |
|
|
|
190.2 |
|
|
|
182.1 |
|
Depreciation and amortization expense |
|
|
43.3 |
|
|
|
43.1 |
|
|
|
128.3 |
|
|
|
125.0 |
|
General and administrative expense |
|
|
26.7 |
|
|
|
22.6 |
|
|
|
80.0 |
|
|
|
81.9 |
|
Casualty loss adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME FROM OPERATIONS |
|
|
48.8 |
|
|
|
52.9 |
|
|
|
152.1 |
|
|
|
110.8 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense from affiliate |
|
|
(2.5 |
) |
|
|
(27.2 |
) |
|
|
(23.8 |
) |
|
|
(84.2 |
) |
Interest expense allocated from Parent |
|
|
(1.4 |
) |
|
|
(2.2 |
) |
|
|
(5.6 |
) |
|
|
(6.9 |
) |
Other interest expense, net |
|
|
(23.3 |
) |
|
|
(16.1 |
) |
|
|
(56.4 |
) |
|
|
(35.2 |
) |
Equity in earnings of unconsolidated investment |
|
|
1.1 |
|
|
|
1.4 |
|
|
|
3.8 |
|
|
|
3.2 |
|
Loss on mark-to-market derivative instruments |
|
|
(1.9 |
) |
|
|
(6.7 |
) |
|
|
26.0 |
|
|
|
(12.1 |
) |
Other |
|
|
(0.7 |
) |
|
|
(0.9 |
) |
|
|
(0.8 |
) |
|
|
(0.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
20.1 |
|
|
|
1.2 |
|
|
|
95.3 |
|
|
|
(24.7 |
) |
Income tax (expense) benefit |
|
|
(1.7 |
) |
|
|
0.2 |
|
|
|
(3.9 |
) |
|
|
(0.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) |
|
|
18.4 |
|
|
|
1.4 |
|
|
|
91.4 |
|
|
|
(25.6 |
) |
Less: Net income attributable to noncontrolling interest |
|
|
4.6 |
|
|
|
5.6 |
|
|
|
18.2 |
|
|
|
11.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP |
|
$ |
13.8 |
|
|
$ |
(4.2 |
) |
|
$ |
73.2 |
|
|
$ |
(37.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to predecessor operations |
|
$ |
(1.3 |
) |
|
$ |
(18.4 |
) |
|
$ |
25.8 |
|
|
$ |
(53.4 |
) |
Net income attributable to general partner |
|
|
5.0 |
|
|
|
2.8 |
|
|
|
12.0 |
|
|
|
6.7 |
|
Net income allocable to limited partners |
|
|
10.1 |
|
|
|
11.4 |
|
|
|
35.4 |
|
|
|
9.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Targa Resources Partners LP |
|
$ |
13.8 |
|
|
$ |
(4.2 |
) |
|
$ |
73.2 |
|
|
$ |
(37.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit basic and diluted |
|
$ |
0.14 |
|
|
$ |
0.23 |
|
|
$ |
0.51 |
|
|
$ |
0.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partner units outstanding basic and diluted |
|
|
72.0 |
|
|
|
50.6 |
|
|
|
69.2 |
|
|
|
47.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED CASH FLOW STATEMENTS
(In millions)
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
91.4 |
|
|
$ |
(25.6 |
) |
Adjustments to reconcile net income (loss) to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, amortization, and accretion |
|
|
134.6 |
|
|
|
131.2 |
|
Deferred income tax expense |
|
|
0.3 |
|
|
|
0.9 |
|
Interest expense on affiliated indebtedness |
|
|
29.4 |
|
|
|
91.1 |
|
Risk management activities |
|
|
(5.4 |
) |
|
|
71.2 |
|
Equity in earnings of unconsolidated investment, net of distribution |
|
|
1.1 |
|
|
|
0.7 |
|
Loss on debt repurchases |
|
|
0.8 |
|
|
|
0.4 |
|
Loss on sale of assets |
|
|
|
|
|
|
0.3 |
|
Changes in operating assets and liabilities |
|
|
(12.2 |
) |
|
|
33.4 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
240.0 |
|
|
|
303.6 |
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
Outlays for property, plant and equipment |
|
|
(82.5 |
) |
|
|
(72.0 |
) |
Other, net |
|
|
2.1 |
|
|
|
(2.0 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(80.4 |
) |
|
|
(74.0 |
) |
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
Proceeds from borrowings under credit facility |
|
|
1,178.1 |
|
|
|
397.6 |
|
Repayments of credit facility |
|
|
(904.0 |
) |
|
|
(374.9 |
) |
Proceeds from issuance of senior notes |
|
|
250.0 |
|
|
|
237.4 |
|
Repayment of affiliated indebtedness |
|
|
(582.8 |
) |
|
|
(397.4 |
) |
Repayment of allocated indebtedness |
|
|
(157.4 |
) |
|
|
|
|
Repurchases of senior notes |
|
|
|
|
|
|
(18.9 |
) |
Parent distributions |
|
|
(102.5 |
) |
|
|
(137.5 |
) |
Proceeds from equity offerings |
|
|
317.8 |
|
|
|
103.5 |
|
Costs incurred in connection with financing arrangements |
|
|
(20.2 |
) |
|
|
(9.8 |
) |
General partner contributions |
|
|
6.8 |
|
|
|
2.2 |
|
Distribution to unitholders |
|
|
(117.8 |
) |
|
|
(79.0 |
) |
Distributions under common control |
|
|
(46.6 |
) |
|
|
|
|
Distributions to noncontrolling interest |
|
|
(17.4 |
) |
|
|
(19.2 |
) |
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(196.0 |
) |
|
|
(296.0 |
) |
|
|
|
|
|
|
|
Net change in cash and cash equivalents |
|
|
(36.4 |
) |
|
|
(66.4 |
) |
Cash and cash equivalents, beginning of period |
|
|
90.9 |
|
|
|
143.2 |
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period |
|
$ |
54.5 |
|
|
$ |
76.8 |
|
|
|
|
|
|
|
|
20