HOUSTON, May 7, 2009 (GLOBE NEWSWIRE) -- Targa Resources Partners LP ("Targa Resources Partners" or the "Partnership") (Nasdaq:NGLS) today reported a $2.1 million net loss for the first quarter 2009 (which includes an $18.5 million non-cash hedge loss), or $0.09 loss per diluted limited partner unit as compared to net income of $24.9 million, or $0.50 per diluted limited partner unit for the first quarter of 2008. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments ("Adjusted EBITDA") of $45.5 million for the first quarter of 2009 compared to Adjusted EBITDA of $52.6 million for the first quarter of 2008.
Distributable cash flow for the first quarter of 2009 was $33.6 million which corresponds to distribution coverage of approximately 1.3 times for the 47.2 million total units outstanding on March 31, 2009 (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).
"The strong performance of our operations combined with our cost control efforts and hedge program result in strong distribution coverage for the first quarter. These efforts along with our quarter end liquidity of approximately $400 million and discipline regarding capital expenditures position us to bridge the time required to determine what the long-term operating environment looks like for our business," said Rene Joyce, Chief Executive Officer of the Partnership's general partner and of Targa Resources, Inc. ("Targa").
On April 23, 2009, the Partnership announced a cash distribution of 51.75 cents per common and subordinated unit, or $2.07 per unit on an annualized basis, for the first quarter of 2009. This cash distribution will be paid May 15, 2009 on all outstanding common and subordinated units to holders of record as of the close of business on May 6, 2009. The distribution was equal to the previous quarter's distribution and reflects an increase of approximately 24% over the distribution for the first quarter of 2008.
Review of First Quarter Results
Net loss for the first quarter of 2009 was $2.1 million compared to $24.9 million of net income for the 2008 period. The decrease in net income was primarily attributable to an $18.5 million non-cash hedge loss compared to a $0.5 million non-cash hedge loss for the comparable period in 2008. The decrease in net income was also impacted by lower commodity prices and higher operating, depreciation, G&A, and interest expenses, partially offset by lower deferred income tax expenses and other income.
Revenues decreased $273.1 million, or 53%, to $239.0 million for the first quarter of 2009 from $512.1 million for the first quarter of 2008, driven primarily by lower prices for natural gas, NGL and condensate and lower natural gas, NGL and condensate sales volumes.
Gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines) for the first quarter of 2009 decreased 7% to 429.4 MMcf/d compared to 462.9 MMcf/d for the same period in 2008. Plant natural gas inlet volume (the volume of natural gas passing through the meters located at the inlets of our processing plants) was 7% lower at 408.2 MMcf/d for the first quarter of 2009 compared to 437.8 MMcf/d for the same period in 2008. These decreases result primarily from the impact of processing economics on our purchases of lower-margin, discretionary volumes at our LOU System from third party pipeline systems, somewhat offset by increases at our North Texas and SAOU Systems.
Gross NGL production of 41.6 MBbl/d for the first quarter of 2009 was 6% lower than gross NGL production of 44.4 MBbl/d for the first quarter of 2008. NGL sales of 37.2 MBbl/d for the first quarter of 2009 were 2% lower than the 38.0 MBbl/d sold during the first quarter of 2008. The decrease in NGL sales is primarily due to lower plant inlets. Natural gas sales volumes decreased 15% to 355.1 BBtu/d in the first quarter of 2009 compared to 418.4 BBtu/d during the first quarter of 2008. The decrease in natural gas sales is primarily the result of a decrease in demand by our industrial customers and a decrease in purchases from affiliates for resale.
The average realized natural gas price decreased by $3.46 per MMBtu, or 43%, to $4.56 per MMBtu for the first quarter of 2009 compared to $8.02 per MMBtu for the same period in 2008. The average realized price for NGLs decreased by $0.66 per gallon, or 55%, to $0.55 per gallon for the first quarter of 2009 compared to $1.21 per gallon for the same period in 2008. The average realized price for condensate decreased by $44.46 per barrel, or 52%, to $41.13 per barrel for the first quarter of 2009 compared to $85.59 per barrel for the first quarter of 2008. Realized prices reflect the impact of our hedging program.
Three Months Ended
March 31,
--------------------
2009 2008
------ ------
(In millions)
Revenues $239.0 $512.1
Product purchases 194.5 442.2
Operating expense, excluding DD&A 12.9 12.6
Depreciation and amortization expense 18.9 18.2
General and administrative expense 5.3 5.2
------ ------
Income from operations 7.4 33.9
Interest expense, net (9.9) (8.7)
Deferred income tax expense (0.3) (0.3)
Other 0.7 --
------ ------
Net income $ (2.1) $ 24.9
====== ======
Financial data:
Operating margin $ 31.6 $ 57.3
Adjusted EBITDA 45.5 52.6
Distributable cash flow 33.6 39.9
Operating data:
Gathering throughput, MMcf/d
LOU System 145.7 196.1
SAOU System 101.7 97.8
North Texas System 182.0 169.0
------ ------
429.4 462.9
====== ======
Plant natural gas inlet, MMcf/d
LOU System 140.6 185.1
SAOU System 91.4 90.4
North Texas System 176.2 162.3
------ ------
408.2 437.8
====== ======
Gross NGL production, MBbl/d
LOU System 7.6 10.9
SAOU System 14.3 14.1
North Texas System 19.7 19.4
------ ------
41.6 44.4
====== ======
Natural gas sales, BBtu/d 355.1 418.4
NGL sales, MBbl/d 37.2 38.0
Condensate sales, MBbl/d 3.4 3.7
Average realized prices:
Natural gas, $/MMBtu 4.56 8.02
NGLs, $/gal 0.55 1.21
Condensate, $/ Bbl 41.13 85.59
Capitalization and Liquidity Update
Total funded debt as of March 31, 2009 was approximately $697 million including approximately $488 million outstanding under our $850 million senior secured revolving credit facility and $209 million of senior unsecured notes. As of March 31, 2009, we had approximately $337 million in capacity available under our credit facility after giving effect to the Lehman default and the issuance of $15 million of letters of credit.
As of March 31, 2009, we had approximately $62 million of cash, bringing total liquidity to approximately $400 million. In addition to our strong liquidity position, we are well within our financial covenants and have no near term maturities under our credit facility or our senior unsecured notes.
We are revising our capital expenditures estimate for 2009 to be more inline with the approximately $55 million in 2008 due to cost control programs and cost savings. As we move through the year we may see additional impacts from these programs. Maintenance capital expenditures account for approximately 40% of the 2009 estimate.
Conference Call
Targa Resources Partners will host a conference call for investors and analysts at 11 a.m. Eastern Time (10 a.m. Central Time) on May 7, 2009 to discuss first quarter 2009 financial results. The conference call can be accessed via Webcast through the Investor's section of the Partnership's website at http://www.targaresources.com or by dialing 800-762-8795. The pass code is 4058507. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following completion of the Webcast through the Investor's section of the Partnership's website and will remain available until May 21, 2009. Replay access numbers are 303-590-3030 or 800-406-7325 with pass code 4058507.
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 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
March 31,
--------------------
2009 2008
------ ------
Reconciliation of net income (loss) (In millions)
to "distributable cash flow":
Net income (loss) $ (2.1) $ 24.9
Depreciation and amortization expense 18.9 18.2
Deferred income tax expense 0.3 0.3
Amortization in interest expense 0.6 0.4
Non-cash loss related to derivatives 18.5 0.5
Maintenance capital expenditures (2.6) (4.4)
------ ------
Distributable cash flow $ 33.6 $ 39.9
====== ======
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 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.
Reconciliation of Non-GAAP Measures
-----------------------------------
Three Months Ended
March 31,
--------------------
2009 2008
------ ------
(In millions)
Reconciliation of net income (loss) to
Adjusted EBITDA:
Net income (loss) $ (2.1) $ 24.9
Add:
Interest expense, net 9.9 8.7
Deferred income tax expense 0.3 0.3
Depreciation and amortization expense 18.9 18.2
Non-cash loss related to derivatives 18.5 0.5
------ ------
Adjusted EBITDA $ 45.5 $ 52.6
====== ======
Three Months Ended
March 31,
--------------------
2009 2008
------ ------
(In millions)
Reconciliation of net cash provided by
operating activities to Adjusted EBITDA:
Net cash provided by operating activities $ 22.0 $ 52.8
Interest expense, net 9.3 8.3
Changes in operating working capital
which used (provided) cash:
Accounts receivable and other assets (6.3) 5.4
Accounts payable and other liabilities 20.5 (13.9)
------ ------
Adjusted EBITDA $ 45.5 $ 52.6
====== ======
Three Months Ended
March 31,
--------------------
2009 2008
------ ------
(In millions)
Reconciliation of net income (loss) to
operating margin:
Net income (loss) $ (2.1) $ 24.9
Add:
Depreciation and amortization expense 18.9 18.2
Deferred income tax expense 0.3 0.3
Interest expense, net 9.9 8.7
General and administrative and other expense 4.6 5.2
------ ------
Operating margin $ 31.6 $ 57.3
====== ======
Forward-Looking Statements
Certain statements in this release are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside Targa Resources Partners' control, which could cause results to differ materially from those expected by management of Targa Resources Partners. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including declines in the production of natural gas or in the price and market demand for natural gas and natural gas liquids, the timing and success of business development efforts, the credit risk of customers and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Partnership's reports and other filings with the Securities and Exchange Commission. Targa Resources Partners undertakes no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
--------------------------------------------------------------------
CONSOLIDATED BALANCE SHEET DATA
-------------------------------
(In thousands)
March 31, December 31,
2009 2008
---------- ----------
ASSETS
Current assets
Cash and cash equivalents $ 62,310 $ 81,768
Assets from risk management activities 90,796 91,816
Other current assets 75,724 81,926
---------- ----------
Total current assets 228,830 255,510
---------- ----------
Property, plant and equipment, net 1,233,221 1,244,337
Long-term assets from risk management
activities 63,339 68,296
Other assets 13,196 12,763
---------- ----------
Total assets 1,538,586 1,580,906
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Accounts payable and accrued liabilities $ 66,930 $ 94,840
Liabilities from risk management activities 12,259 11,664
---------- ----------
Total current liabilities 79,189 106,504
---------- ----------
Long-term debt 696,845 696,845
Long term liabilities from risk
management activities 16,250 9,679
Other long-term liabilities 5,908 5,514
---------- ----------
Total liabilities 798,192 818,542
Partners' capital 740,394 762,364
---------- ----------
Total liabilities and partners' capital $1,538,586 $1,580,906
========== ==========
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
--------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF OPERATIONS
-------------------------------------
(In thousands, except per unit data)
Three Months Ended
March 31,
------------------------
2009 2008
---------- ----------
REVENUES $ 239,034 $ 512,069
COSTS AND EXPENSES:
Product purchases 194,564 442,150
Operating expenses 12,903 12,570
Depreciation and amortization expense 18,878 18,248
General and administrative expense 5,321 5,201
Gain on sale of assets -- (74)
---------- ----------
Total costs and expenses 231,666 478,095
---------- ----------
INCOME FROM OPERATIONS 7,368 33,974
Other income (expense):
Interest expense, net (9,924) (8,718)
Other 726 16
---------- ----------
Income (loss) before income taxes (1,830) 25,272
Income tax expense (300) (337)
---------- ----------
NET INCOME (LOSS) (2,130) 24,935
Net income attributable to general partner 1,890 1,846
---------- ----------
Net income (loss) available to limited
partners $ (4,020) $ 23,089
========== ==========
Basic and diluted net income (loss) per
limited partner unit $ (0.09) $ 0.50
========== ==========
Basic and diluted average limited partner
units outstanding 46,205 46,165
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
--------------------------------------------------------------------
CONSOLIDATED CASH FLOW INFORMATION
----------------------------------
(In thousands)
Three Months Ended
March 31,
------------------------
2009 2008
---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (2,130) $ 24,935
Adjustments to reconcile net income
(loss) to net cash provided by operating
activities:
Depreciation, amortization and
accretion 19,657 18,751
Deferred income tax expense 300 337
Risk management activities 18,511 478
Gain on sale of assets -- (74)
Changes in operating assets and
liabilities (14,325) 8,360
---------- ----------
Net cash provided by operating activities 22,013 52,787
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment (15,102) (7,381)
Other -- (4,167)
---------- ----------
Net cash used in investing activities (15,102) (11,548)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments on credit facility -- (50,000)
Distributions (26,374) (18,792)
General partner contributions 5 --
---------- ----------
Net cash used in financing activities (26,369) (68,792)
---------- ----------
Net change in cash and cash equivalents (19,458) (27,553)
Cash and cash equivalents, beginning
of period 81,768 50,994
---------- ----------
Cash and cash equivalents, end of period $ 62,310 $ 23,441
========== ==========