Table of Contents
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)
November 11, 2008
November 11, 2008
TARGA RESOURCES PARTNERS LP
(Exact name of registrant as specified in its charter)
| Delaware | 001-33303 | 65-1295427 | ||
| (State or other jurisdiction | (Commission | (IRS Employer | ||
| of incorporation or organization) | File Number) | 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
(Registrant’s telephone number, including area code)
(Registrant’s 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))
TABLE OF CONTENTS
| Item 2.02 Results of Operations and Financial Condition | ||||||||
| Item 9.01 Financial Statements and Exhibits | ||||||||
| SIGNATURES | ||||||||
| EXHIBIT INDEX | ||||||||
| EX-99.1 | ||||||||
Table of Contents
Item 2.02 Results of Operations and Financial Condition.
On November 12, 2008, Targa Resources Partners LP (the “Partnership”) will issue a press
release regarding its financial results for the three and nine months ended September 30, 2008. A
conference call to discuss these results is scheduled for 10:00 a.m. Eastern time on Wednesday,
November 12, 2008. 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 November 26, 2008. A copy of the earnings press
release is filed 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 November 12, 2008. |
Table of Contents
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: November 11, 2008
|
By: | /s/ Jeffrey J. McParland
|
||||
| Executive Vice President and Chief Financial Officer | ||||||
Table of Contents
EXHIBIT INDEX
| Exhibit | ||
| Number | Description | |
Exhibit 99.1
|
Targa Resources Partners LP Press Release dated November 12, 2008. |
Exhibit 99.1
| 1000 Louisiana, Suite 4300 | ||||
|
Houston, TX 77002 | |||
| 713.584.1000 | ||||
| www.targaresources.com | ||||
Targa Resources Partners LP Reports Third Quarter 2008 Financial Results
HOUSTON-November 12, 2008-Targa Resources Partners LP (“Targa Resources Partners” or the
“Partnership”) (NASDAQ: NGLS) today reported third quarter 2008 net income of $14.7 million (which
includes a $9.4 million non-cash hedge loss, a $1.0 million loss related to Lehman hedges, $0.2
million in other hedge amortization and an estimated $2.2 million impact due to Hurricane Gustav
and Ike disruptions), or $0.31 per diluted limited partner unit as compared to net income of $14.4
million, or $0.12 per diluted limited partner unit for the third quarter of 2007. The Partnership
reported earnings before interest, income taxes, depreciation and amortization and non-cash income
or loss related to derivative instruments (“Adjusted EBITDA”) of $55.0 million for the third
quarter of 2008 compared to Adjusted EBITDA of $48.2 million for the third quarter of 2007.
Distributable cash flow for the third quarter of 2008 was $37.7 million which corresponds to
distribution coverage of 1.4 times for the 47.1 million total units outstanding on September 30,
2008 (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).
“Third quarter results reflect the impact of discrete events and non-cash items. Excluding those
items, third quarter results were largely in line with second quarter results, but these results
occurred in a drastically different commodity price environment than we are in today. Going forward, we believe that our
healthy coverage ratio, strong liquidity and hedge program will enable us to weather commodity
price volatility and the strained credit market environment. Based on completed and approved
projects and support from current producer drilling programs, we believe 2009 volumes will be at or
above 2008 levels. Obviously, projected commodity prices and producer activities in our areas of
operations must be closely monitored for impacts to our 2009 business plan and we will continue to
execute with a focus on operating cost control and discipline regarding capital expenditures,” said
Rene Joyce, Chief Executive Officer of the Partnership’s general partner and of Targa Resources,
Inc. (“Targa”).
On October 24, 2008, the Partnership announced a cash distribution of 51.75¢ per common and
subordinated unit, or $2.07 per unit on an annualized basis, for the third quarter of 2008. This
cash distribution will be paid November 14, 2008 on all outstanding common and subordinated units
to holders of record as of the close of business on November 4, 2008. The distribution reflects an
increase of approximately 1% over the previous quarter’s distribution and approximately 53% over
the distribution for the third quarter of 2007.
For the first nine months of 2008, Adjusted EBITDA rose 23% to $163.1 million, compared with $132.7
million in the same period a year ago. Distributable cash flow for the nine months ended September
30, 2008 increased 35% to $118.2 million from $87.3 million in the same period a year ago. Both
metrics were driven primarily by favorable increases in both gathering throughput and plant inlet
volumes and natural gas, NGL, and condensate prices.
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| (In millions) | ||||||||||||||||
Revenues |
$ | 578.7 | $ | 405.0 | $ | 1,721.3 | $ | 1,187.4 | ||||||||
Product purchases |
512.4 | 337.8 | 1,509.8 | 1,004.0 | ||||||||||||
Operating expense, excluding DD&A |
15.4 | 12.7 | 42.7 | 36.7 | ||||||||||||
Depreciation and amortization expense |
18.6 | 18.0 | 55.2 | 53.6 | ||||||||||||
General and administrative expense |
5.3 | 6.5 | 16.2 | 14.5 | ||||||||||||
Casualty loss |
0.2 | — | 0.2 | — | ||||||||||||
Gain on sale of assets |
— | — | (0.1 | ) | (0.3 | ) | ||||||||||
Income from operations |
26.8 | 30.0 | 97.3 | 78.9 | ||||||||||||
Interest expense, net |
(10.7 | ) | (5.1 | ) | (27.4 | ) | (12.9 | ) | ||||||||
Interest expense, allocated from Parent |
— | (2.8 | ) | — | (19.0 | ) | ||||||||||
Loss on mark-to-market derivative
instruments |
(1.0 | ) | (7.4 | ) | (1.0 | ) | (28.4 | ) | ||||||||
Deferred income tax expense |
(0.4 | ) | (0.3 | ) | (1.1 | ) | (1.0 | ) | ||||||||
Net income |
$ | 14.7 | $ | 14.4 | $ | 67.8 | $ | 17.6 | ||||||||
Financial data: |
||||||||||||||||
Operating margin |
$ | 50.9 | $ | 54.5 | $ | 168.8 | $ | 146.7 | ||||||||
Adjusted EBITDA |
55.0 | 48.2 | 163.1 | 132.7 | ||||||||||||
Distributable cash flow |
37.7 | 35.8 | 118.2 | 87.3 | ||||||||||||
Operating data: |
||||||||||||||||
Gathering throughput, MMcf/d |
438.3 | 464.3 | 455.0 | 447.7 | ||||||||||||
Plant natural gas inlet, MMcf/d |
415.9 | 445.1 | 430.8 | 423.5 | ||||||||||||
Gross NGL production, MBbl/d |
41.3 | 43.9 | 43.2 | 42.1 | ||||||||||||
Natural gas sales, BBtu/d |
404.4 | 414.8 | 410.9 | 403.3 | ||||||||||||
NGL sales, MBbl/d |
37.4 | 37.5 | 38.2 | 35.7 | ||||||||||||
Condensate sales, MBbl/d |
3.3 | 3.7 | 3.6 | 3.6 | ||||||||||||
Average realized prices: |
||||||||||||||||
Natural gas, $/MMBtu |
||||||||||||||||
Average realized sales price |
9.47 | 5.87 | 9.31 | 6.61 | ||||||||||||
Impact of hedging |
(0.05 | ) | 0.09 | (0.02 | ) | 0.08 | ||||||||||
Average realized price |
9.42 | 5.96 | 9.29 | 6.69 | ||||||||||||
NGLs, $/gal |
||||||||||||||||
Average realized sales price |
1.47 | 1.06 | 1.41 | 0.95 | ||||||||||||
Impact of hedging |
(0.11 | ) | (0.02 | ) | (0.10 | ) | (0.01 | ) | ||||||||
Average realized price |
1.36 | 1.04 | 1.31 | 0.94 | ||||||||||||
Condensate, $/ Bbl |
||||||||||||||||
Average realized sales price |
103.38 | 69.05 | 98.86 | 60.09 | ||||||||||||
Impact of hedging |
(5.59 | ) | (0.31 | ) | (4.12 | ) | 0.78 | |||||||||
Average realized price |
97.79 | 68.74 | 94.74 | 60.87 | ||||||||||||
2
Review of Third Quarter Results
Net income for the three months ended September 30, 2008 was $14.7 million, up from $14.4 million
for the three months ended September 30, 2007. The increase in net income was attributable to
higher commodity prices partially offset by higher operating expenses and higher interest expense
during the 2008 period. Net income for the three months ended September 30, 2008 also includes a
$9.4 million non-cash hedge loss, a $1.0 million loss related to
Lehman hedges, $0.2 million in other hedge amortization and an estimated $2.2 million
impact due to the hurricanes. The third quarter of 2007 includes a $7.4 million loss on
mark-to-market derivative contracts related to the SAOU and LOU Systems that was recognized during
the period prior to the acquisition of these businesses by the Partnership.
Revenues increased $173.7 million, or 43%, to $578.7 million for the third quarter of 2008 from
$405.0 million for the third quarter of 2007, driven by higher prices for natural gas, NGL and
condensate. The benefit of higher prices was partially offset by the impact of lower sales volumes,
mainly the result of processing plant disruptions and lower industrial sales primarily due to the
impact of the hurricanes.
Gathering throughput (the volume of natural gas gathered and passed through natural gas gathering
pipelines) for the third quarter of 2008 decreased by 26.0 MMcf/d, or 6%, to 438.3 MMcf/d compared
to 464.3 MMcf/d for the same period in 2007. Plant natural gas inlet volume (the volume of natural
gas passing through the meter located at the inlet of a processing plant) was 7% lower at 415.4
MMcf/d for the third quarter of 2008 compared to 445.1 MMcf/d for the same period in 2007 due
primarily to the impact of the hurricanes.
Gross NGL production of 41.3 MBbl/d for the third quarter of 2008 was 6% lower than gross NGL
production of 43.9 MBbl/d for the third quarter of 2007. Natural gas sales volumes decreased 3% to
404.4 BBtu/d in the third quarter of 2008 compared to 414.8 BBtu/d during the third quarter of
2007. NGL sales of 37.4 MBbl/d for the third quarter of 2008 were less than 1% lower than the 37.5
MBbl/d sold during the third quarter of 2007. These volume decreases were due primarily to the
impact of the hurricanes offset by the purchase of raw NGL mix for fractionation at Gillis.
The average realized natural gas price increased by $3.46 per MMBtu, or 58%, to $9.42 per MMBtu for
the third quarter of 2008 compared to $5.96 per MMBtu for the same period in 2007. The average
realized price for NGLs increased by $0.32 per gallon, or 31%, to $1.36 per gallon for the third
quarter of 2008 compared to $1.04 per gallon for the same period in 2007. The average realized
price for condensate increased by $29.05 per barrel, or 42%, to $97.79 per barrel for the third
quarter of 2008 compared to $68.74 per barrel for the third quarter of 2007. All of the average
realized prices reflect the impact of our hedging program.
Review of Nine Month Results
Net income for the first nine months of 2008 was $67.8 million compared to $17.6 million for the
same period of 2007. The increase in net income was attributable to higher commodity prices and
higher inlet volumes partially offset by higher operating expenses and higher general and
administrative expenses for the 2008 period. The nine months ended September 30, 2008 also includes
a $10.1 million non-cash hedge loss, a $1.0 million loss related to Lehman hedges, and $0.5 million
of other hedge amortization as well as an estimated $2.2 million impact due to the
3
hurricanes. In addition, the first nine months of 2007 includes a $28.4 million loss on
mark-to-market derivative contracts related to the SAOU and LOU Systems recognized during the
period prior to the acquisition of these businesses by the Partnership.
For the first nine months of 2008, gathering throughput was 455.0 MMcf/d, 2% higher than 447.7
MMcf/d for the same period in 2007. Plant natural gas inlet volume was 430.8 MMcf/d for the first
nine months of 2008, 2% higher than 423.5 MMcf/d for the same period in 2007.
Gross NGL production of 43.2 MBbl/d for the first nine months of 2008 was 3% higher than gross NGL
production of 42.1 MBbl/d for the first nine months of 2007. Natural gas sales volumes increased 2%
to 410.9 BBtu/d for the first nine months of 2008 as compared to 403.3 BBtu/d for the same period
in 2007. NGL sales of 38.2 MBbl/d for the first nine months of 2008 were 7% higher than NGL sales
of 35.7 MBbl/d for the same period in 2007. The increase was primarily due to increased NGL
recoveries from higher inlet volumes and decreased NGL take-in-kind volumes.
The average realized natural gas price increased by $2.60 per MMBtu, or 39%, to $9.29 per MMBtu
for the first nine months of 2008, from $6.69 per MMBtu for the first nine months of 2007. The
average realized price for NGLs increased by $0.37 per gallon, or 39%, to $1.31 per gallon for the
first nine months of 2008 compared to $0.94 per gallon for the first nine months of 2007. The
average realized price for condensate increased by $33.87 per barrel, or 56%, to $94.74 per barrel
for the first nine months of 2008 compared to $60.87 per barrel for the first nine months of 2007.
All of the average realized prices reflect the impact of our hedging program.
Capitalization / Liquidity Update
As of September 30, 2008, we had approximately $425.3 million in capacity available under our
senior secured credit facility, after giving effect to outstanding borrowings of $390 million and
the issuance of $34.7 million of letters of credit. Our senior secured credit facility allows us to
request increases in the commitments under the facility by up to $150 million.
On October 16, 2008, we requested a $100 million funding under our senior secured credit facility
to increase our cash on hand in the face of significant deterioration in the credit markets.
Lehman Brothers Commercial Bank, a lender under our senior secured credit facility, defaulted on
its portion of the borrowing request resulting in an actual funding of $97.8 million. The proceeds
from this borrowing are currently available to us as cash deposits. As a result of the Lehman
default, we believe that our availability under the senior secured credit facility has been
effectively reduced by $9.5 million to $415.8 million.
As of October 31, 2008, we had approximately $130 million of cash and approximately $313 million of
availability under the senior secured credit facility, after giving effect to the Lehman default,
bringing total liquidity to approximately $443 million. In addition to our strong liquidity
position, we are well within our financial covenants and have no near term maturities under our
senior secured credit facility or our senior unsecured notes.
Total funded debt as of September 30, 2008 was $640.0 million, approximately 50% of total book
capitalization.
4
Conference Call
Targa Resources Partners will host a conference call for investors and analysts at 10:00 a.m.
Eastern Time (9:00 a.m. Central Time) on November 12, 2008 to discuss third quarter 2008 financial
results. The conference call can be accessed via Webcast through the Investors section of the
Partnership’s web site at http://www.targaresources.com or by dialing 800-240-6709. The
pass code is 11121588. Please dial in five to ten minutes prior to the scheduled start time. A
replay will be available through the Investors section of the Partnership’s web site approximately
two hours following completion of the Webcast and will remain available until November 26, 2008.
Replay access numbers are 303-590-3000 or 800-405-2236 with pass code 11121588.
About Targa Resources Partners
Targa Resources Partners was formed by Targa 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, seven natural gas processing plants and two fractionators and currently
operates in Southwest Louisiana, the Permian Basin in West Texas and the Fort Worth Basin in North
Texas. 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.
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 - 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 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 non-GAAP
financial measure for our unitholders because 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
5
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 flows sufficient to make distributions to our investors.
The GAAP measure most directly comparable to distributable cash flow is net income (loss). Our
non-GAAP measure of distributable cash flow should not be considered as an alternative to GAAP net
income (loss). 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 (loss) and is
defined differently by different companies in our industry, our definition of distributable cash
flow may not be comparable to similarly titled measures of other companies, thereby diminishing its
utility. Management compensates for the limitations of distributable cash flow as an analytical
tool by reviewing the comparable GAAP measures, understanding the differences between the measures
and incorporating these learnings into our decision-making processes.
The following table presents a reconciliation of net income (loss) to distributable cash flow for
the Partnership for the periods shown:
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| (In millions) | ||||||||||||||||
Reconciliation of net income to “distributable cash flow”: |
||||||||||||||||
Net income |
$ | 14.7 | $ | 14.4 | $ | 67.8 | $ | 17.6 | ||||||||
Depreciation and amortization expense |
18.6 | 18.0 | 55.2 | 53.6 | ||||||||||||
Deferred income tax expense |
0.4 | 0.3 | 1.1 | 1.0 | ||||||||||||
Amortization of debt issue costs |
0.6 | 0.4 | 1.5 | 1.4 | ||||||||||||
Non-cash loss related to derivative instruments |
10.6 | 7.6 | 11.6 | 28.6 | ||||||||||||
Maintenance capital expenditures |
(7.2 | ) | (4.9 | ) | (19.0 | ) | (14.9 | ) | ||||||||
Distributable cash flow |
$ | 37.7 | $ | 35.8 | $ | 118.2 | $ | 87.3 | ||||||||
| Nine Months Ended September 30, 2007 | ||||||||||||||||
| Pre-Acquisition | Post Acquisition | |||||||||||||||
| SAOU-LOU | North Texas | |||||||||||||||
| Jan 1, 2007 to Sep | Jan 1, 2007 to Feb | |||||||||||||||
| TRP LP | 30, 2007 | 13, 2007 | TRP LP | |||||||||||||
| (In millions) | ||||||||||||||||
Net income (loss) |
$ | 17.6 | $ | 14.4 | $ | (6.9 | ) | $ | 10.1 | |||||||
Depreciation and amortization expense |
53.6 | 10.8 | 6.9 | 35.9 | ||||||||||||
Deferred income tax expense |
1.0 | — | — | 1.0 | ||||||||||||
Amortization of debt issue costs |
1.4 | 0.9 | — | 0.5 | ||||||||||||
Loss on mark-to-market derivative instruments |
28.6 | 28.6 | — | — | ||||||||||||
Maintenance capital expenditures |
(14.9 | ) | (5.6 | ) | (1.5 | ) | (7.8 | ) | ||||||||
Distributable Cash Flow |
$ | 87.3 | $ | 49.1 | $ | (1.5 | ) | $ | 39.7 | |||||||
Adjusted EBITDA - We define 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 our management and by external
6
users of our financial statements such as investors, commercial banks and others, to assess: (1)
the financial performance of our assets without regard to financing methods, capital structure or
historical cost basis; (2) our operating performance and return on capital as 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 our
assets to generate cash sufficient to pay interest costs, support our indebtedness and make
distributions to our investors. The GAAP measure most directly comparable to Adjusted EBITDA is net
income. Our 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 our 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 in our industry, our 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 management’s decision-making processes.
Operating Margin - We define operating 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) and operating expense. Management reviews
operating margin monthly for consistency and trend analysis. Based on this monthly analysis,
management takes appropriate action to maintain positive trends or to reverse negative trends.
Management uses operating margin as an important performance measure of the core profitability of
our operations.
The GAAP measure most directly comparable to operating margin is net income. Our 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 our 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 in our
industry, our 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 management’s
decision-making processes.
7
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| (In millions) | ||||||||||||||||
Reconciliation of net cash provided by (used in)
operating activities to “Adjusted EBITDA”: |
||||||||||||||||
Net cash provided by (used in) operating activities |
$ | (25.4 | ) | $ | 64.9 | $ | 74.0 | $ | 133.8 | |||||||
Allocated interest expense from parent |
— | 2.4 | — | 17.6 | ||||||||||||
Interest expense, net |
10.1 | 5.1 | 25.9 | 12.9 | ||||||||||||
Changes in operating working capital
which used (provided) cash: |
||||||||||||||||
Accounts receivable and other |
2.3 | (22.5 | ) | 51.1 | (14.8 | ) | ||||||||||
Accounts payable |
(4.0 | ) | (0.6 | ) | (3.9 | ) | (3.2 | ) | ||||||||
Accrued liabilities |
72.0 | (1.1 | ) | 16.0 | (13.6 | ) | ||||||||||
Adjusted EBITDA |
$ | 55.0 | $ | 48.2 | $ | 163.1 | $ | 132.7 | ||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| (In millions) | ||||||||||||||||
Reconciliation of net income to “Adjusted EBITDA”: |
||||||||||||||||
Net income |
14.7 | $ | 14.4 | $ | 67.8 | $ | 17.6 | |||||||||
Add: |
||||||||||||||||
Allocated interest expense, net |
— | 2.8 | — | 19.0 | ||||||||||||
Interest expense, net |
10.7 | 5.1 | 27.4 | 12.9 | ||||||||||||
Deferred income tax expense |
0.4 | 0.3 | 1.1 | 1.0 | ||||||||||||
Depreciation and amortization expense |
18.6 | 18.0 | 55.2 | 53.6 | ||||||||||||
Non-cash loss related to derivative instruments |
10.6 | 7.6 | 11.6 | 28.6 | ||||||||||||
Adjusted EBITDA |
$ | 55.0 | $ | 48.2 | $ | 163.1 | $ | 132.7 | ||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| (In millions) | ||||||||||||||||
Reconciliation of net income to “operating margin”: |
||||||||||||||||
Net income |
$ | 14.7 | $ | 14.4 | $ | 67.8 | $ | 17.6 | ||||||||
Add: |
||||||||||||||||
Depreciation and amortization expense |
18.6 | 18.0 | 55.2 | 53.6 | ||||||||||||
Deferred income tax expense |
0.4 | 0.3 | 1.1 | 1.0 | ||||||||||||
Allocated interest expense, net |
— | 2.8 | — | 19.0 | ||||||||||||
Interest expense, net |
10.7 | 5.1 | 27.4 | 12.9 | ||||||||||||
Loss on mark-to-market derivative instruments |
1.0 | 7.4 | 1.0 | 28.4 | ||||||||||||
General and administrative and other expense |
5.5 | 6.5 | 16.3 | 14.2 | ||||||||||||
Operating margin |
$ | 50.9 | $ | 54.5 | $ | 168.8 | $ | 146.7 | ||||||||
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
8
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.
Investor contact info:
Phone: 713-584-1133
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
9
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED BALANCE SHEET DATA
(In thousands)
(In thousands)
| September 30, | December 31, | |||||||
| 2008 | 2007 | |||||||
ASSETS |
||||||||
Current assets
|
||||||||
Cash and cash equivalents |
$ | 34,319 | $ | 50,994 | ||||
Assets from risk management activities |
35,799 | 8,695 | ||||||
Other current assets |
109,775 | 148,786 | ||||||
Total current assets |
179,893 | 208,475 | ||||||
Property, plant and equipment, net |
1,237,472 | 1,259,594 | ||||||
Long-term assets from risk management activities |
22,091 | 3,040 | ||||||
Other assets |
14,449 | 8,863 | ||||||
Total assets |
1,453,905 | 1,479,972 | ||||||
LIABILITIES AND PARTNERS’ CAPITAL |
||||||||
Accounts payable and accrued liabilities |
$ | 136,396 | $ | 148,529 | ||||
Liabilities from risk management activities |
12,888 | 44,003 | ||||||
Total current liabilities |
149,284 | 192,532 | ||||||
Long-term debt |
640,000 | 626,300 | ||||||
Long term liabilities from risk management activities |
27,780 | 43,109 | ||||||
Other long-term liabilities |
5,181 | 3,825 | ||||||
Total liabilities |
822,245 | 865,766 | ||||||
Partners’ capital |
631,660 | 614,206 | ||||||
Total liabilities and partners’ capital |
$ | 1,453,905 | $ | 1,479,972 | ||||
10
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit data)
(In thousands, except per unit data)
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
REVENUES |
$ | 578,747 | $ | 405,038 | $ | 1,721,336 | $ | 1,187,434 | ||||||||
COSTS AND EXPENSES: |
||||||||||||||||
Product purchases |
512,443 | 337,762 | 1,509,752 | 1,003,961 | ||||||||||||
Operating expenses |
15,402 | 12,736 | 42,673 | 36,683 | ||||||||||||
Depreciation and amortization expense |
18,566 | 17,984 | 55,235 | 53,641 | ||||||||||||
General and administrative expense |
5,367 | 6,574 | 16,283 | 14,560 | ||||||||||||
Casualty loss |
167 | — | 167 | — | ||||||||||||
(Gain) loss on sale of assets |
(13 | ) | 17 | (88 | ) | (298 | ) | |||||||||
Total costs and expenses |
551,932 | 375,073 | 1,624,022 | 1,108,547 | ||||||||||||
INCOME FROM OPERATIONS |
26,815 | 29,965 | 97,314 | 78,887 | ||||||||||||
Other income (expense): |
||||||||||||||||
Interest expense, net |
(10,749 | ) | (7,865 | ) | (27,443 | ) | (31,899 | ) | ||||||||
Loss on mark-to-market derivative instruments |
(991 | ) | (7,367 | ) | (991 | ) | (28,369 | ) | ||||||||
Other |
17 | 12 | 53 | 17 | ||||||||||||
Income before income taxes |
15,092 | 14,745 | 68,933 | 18,636 | ||||||||||||
Income tax expense |
(400 | ) | (353 | ) | (1,100 | ) | (1,060 | ) | ||||||||
NET INCOME |
$ | 14,692 | $ | 14,392 | $ | 67,833 | $ | 17,576 | ||||||||
Income attributable to: |
||||||||||||||||
Predecessor operations |
$ | — | $ | 10,523 | $ | — | $ | 7,514 | ||||||||
General partner |
294 | 77 | 5,524 | 201 | ||||||||||||
Limited partners |
14,398 | 3,792 | 62,309 | 9,861 | ||||||||||||
| $ | 14,692 | $ | 14,392 | $ | 67,833 | $ | 17,576 | |||||||||
Net income per limited partner unit: |
||||||||||||||||
Basic |
$ | 0.31 | $ | 0.12 | $ | 1.35 | $ | 0.32 | ||||||||
Diluted |
$ | 0.31 | $ | 0.12 | $ | 1.35 | $ | 0.32 | ||||||||
Weighted average limited partner units outstanding: |
||||||||||||||||
Basic |
46,154 | 30,848 | 46,153 | 30,848 | ||||||||||||
Diluted |
46,164 | 30,857 | 46,161 | 30,855 | ||||||||||||
11
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED CASH FLOW INFORMATION
(In thousands)
(In thousands)
| Nine Months Ended September 30, | ||||||||
| 2008 | 2007 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
Net income |
$ | 67,833 | $ | 17,576 | ||||
Adjustments to reconcile net income to net cash
provided by operating activities: |
||||||||
Depreciation, amortization and accretion |
57,128 | 55,401 | ||||||
Deferred income tax expense |
1,100 | 1,060 | ||||||
Risk management activities |
(75,747 | ) | 28,567 | |||||
Gain on sale of assets |
(88 | ) | (298 | ) | ||||
Changes in operating assets and liabilities |
23,783 | 31,447 | ||||||
Net cash provided by operating activities |
74,009 | 133,753 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
Purchases of property, plant and equipment |
(28,563 | ) | (34,240 | ) | ||||
Other |
(4,088 | ) | 372 | |||||
Net cash used in investing activities |
(32,651 | ) | (33,868 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
Proceeds from borrowings under credit facility |
87,500 | 342,500 | ||||||
Repayments on credit facility |
(323,800 | ) | (48,000 | ) | ||||
Proceeds from issuance of senior notes |
250,000 | — | ||||||
Repayment of affiliated indebtedness |
— | (665,692 | ) | |||||
Proceeds from equity offerings |
— | 380,768 | ||||||
Distributions |
(64,573 | ) | (15,943 | ) | ||||
General partner contributions |
8 | — | ||||||
Costs incurred in connection with public offerings |
(89 | ) | (3,313 | ) | ||||
Costs incurred in connection with financing arrangements |
(7,079 | ) | (4,565 | ) | ||||
Deemed Parent distributions |
— | (57,199 | ) | |||||
Net cash used in financing activities |
(58,033 | ) | (71,444 | ) | ||||
Net change in cash and cash equivalents |
(16,675 | ) | 28,441 | |||||
Cash and cash equivalents, beginning of period |
50,994 | — | ||||||
Cash and cash equivalents, end of period |
$ | 34,319 | $ | 28,441 | ||||
12