TARGA RESOURCES PARTNERS LP REPORTS SECOND QUARTER 2008 FINANCIAL RESULTS
HOUSTON-August 11, 2008-Targa Resources Partners LP ("Targa Resources Partners" or the "Partnership") (NASDAQ: NGLS) today announced its financial results for the three months ended June 30, 2008. For the second quarter of 2008, the Partnership reported (i) net income of $28.2 million or $0.54 per common and subordinated unit on a fully diluted basis as determined under Generally Accepted Accounting Principles ("GAAP") for entities under common control; (ii) income from operations of $36.5 million and (iii) earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments ("Adjusted EBITDA") of $55.5 million. Adjusted EBITDA is a non-GAAP financial measure that is defined and reconciled later in this press release to its most directly comparable GAAP financial measure, net income (loss).
On July 23, 2008, Targa Resources Partners announced a cash distribution of $0.5125 per common and subordinated unit, or $2.05 per unit on an annualized basis, for the second quarter of 2008. This cash distribution will be paid August 14, 2008 on all outstanding common and subordinated units to holders of record as of the close of business on August 4, 2008. Distributable cash flow for the second quarter of 2008 was $40.1 million which corresponds to distribution coverage of 1.6 times for the 47.1 million total units outstanding on June 30, 2008. Distributable cash flow is a non-GAAP financial measure that is defined and reconciled later in this press release to its most directly comparable GAAP financial measure, net income (loss).
Review of Second Quarter Results
Revenues were $630.5 million for the three months ended June 30, 2008, 45% higher than revenues of $433.6 million for the three months ended June 30, 2007. Income from operations for the second quarter of 2008 increased 29% to $36.5 million from $28.2 million in the same period of 2007. The increase was due to higher commodity prices for the three months ended June 30, 2008 compared to the three months ended June 30, 2007.
Net income for the second quarter 2008 was $28.2 million versus $13.8 million for the same period 2007. The increase in net income is attributable to higher commodity prices partially offset by higher operating expenses and higher general and administrative expenses during the second quarter 2008. In addition, second quarter 2007 includes a $6.2 million loss on mark-to-market derivative contracts related to the SAOU and LOU Systems prior to the acquisition of these businesses by the Partnership. Prior to the sale of SAOU and LOU to the Partnership, Targa Resources, Inc ("Targa") entered into derivative instruments for forecasted transactions of the SAOU and LOU businesses that were accorded hedge accounting treatment in Targa's consolidated financial statements. Because the SAOU and LOU businesses were not a direct party to the derivative instruments, they were not entitled to hedge accounting treatment in their separate financial statements. Accordingly, all unrealized gains and losses on the allocated derivatives were reflected in the SAOU and LOU businesses financial statements as mark-to-market losses on derivative instruments.
For the second quarter of 2008, gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines) increased by 2% to 463.9 MMcf/d compared to 453.1 MMcf/d for the same period in 2007. For the same periods, plant natural gas inlet volume (the volume of natural gas passing through the meter located at the inlet of a processing plant) was 2% higher at 435.2 MMcf/d compared to 427.1 MMcf/d in the second quarter of 2007.
Gross NGL production of 44.5 MBbl/d for the three months ended June 30, 2008 was 3% higher than NGL production of 43.2 MBbl/d for the three months ended June 30, 2007. Natural gas sales volumes decreased 1% to 410.0 BBtu/d in the three months ended June 30, 2008 as compared to the 414.6 BBtu/d sold in the same 2007 period. Additionally, NGL sales of 39.1 MBbl/d for the second quarter of 2008 were 7% higher than the 36.5 MBbl/d sold in the same 2007 period. 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 42% or $3.11 per MMBtu from $7.36 per MMBtu for the three months ended June 30, 2007, to $10.47 per MMBtu for the three months ended June 30, 2008, including the impact of our hedging program. The average realized price for NGLs increased by $0.39 per gallon, or 41%, to $1.35 per gallon for the three months ended June 30, 2008 compared to $0.96 per gallon for the three months ended June 30, 2007, including the impact of our hedging program. The average realized price for condensate increased by $40.85 per barrel, or 68%, to $101.11 per barrel for the three months ended June 30, 2008 compared to $60.26 per barrel for the three months ended June 30, 2007, including the impact of our hedging program.
Review of Six Month Results
Revenues were $1,142.6 million for the six months ended June 30, 2008, 46% higher than revenues of $782.4 million for the six months ended June 30, 2007. Income from operations for the six months ended June 30, 2008 increased 44% to $70.5 million from $48.9 million in the same period of 2007. The increase was primarily due to higher commodity prices and higher inlet volumes for the six months ended June 30, 2008 compared to the six months ended June 30, 2007.
Net income for the six months ended June 30, 2008 was $53.1 million versus $3.2 million for the same period 2007. The increase in net income is attributable to higher commodity prices and higher inlet volumes partially offset by higher operating expenses and higher general and administrative expenses for the six months ended June 30, 2008. In addition, the six months ended June 30, 2007 includes the $21.0 million loss on mark-to-market derivative contracts related to the SAOU and LOU Systems recognized in the second quarter prior to the acquisition of these businesses by the Partnership.
For the six months ended June 30, 2008, gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines) increased by 6% to 463.4 MMcf/d compared to 439.2 MMcf/d for the same period in 2007. For the same periods, plant natural gas inlet volume (the volume of natural gas passing through the meter located at the inlet of a processing plant) for the six months ended June 30, 2008 was 6% higher at 436.4 MMcf/d compared to 412.5 MMcf/d for the same period in 2007.
Gross NGL production of 44.1 MBbl/d for the six months ended June 30, 2008 was 7% higher than NGL production of 41.1 MBbl/d for the six months ended June 30, 2007. Natural gas sales volumes increased 4% to 414.2 BBtu/d in the six months ended June 30, 2008 as compared to the 397.5 BBtu/d sold in the same 2007 period. Additionally, NGL sales of 38.5 MBbl/d for the six months ended June 30, 2008 were 11% higher than the 34.8 MBbl/d sold in the same 2007 period. 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 31% or $2.18 per MMBtu from $7.04 per MMBtu for the six months ended June 30, 2007, to $9.22 per MMBtu for the six months ended June 30, 2008, including the impact of our hedging program. The average realized price for NGLs increased by $0.39 per gallon, or 43%, to $1.29 per gallon for the six months ended June 30, 2008 compared to $0.90 per gallon for the six months ended June 30, 2007, including the impact of our hedging program. The average realized price for condensate increased by $36.68 per barrel, or 65%, to $93.38 per barrel for the six months ended June 30, 2008 compared to $56.70 per barrel for the six months ended June 30, 2007, including the impact of our hedging program.
Capitalization
On June 18, 2008 we completed a private placement under Rule 144A and Regulation S of the Securities Act of 1933 ("Rule 144A") of $250 million in aggregate principal amount of 8.25% senior unsecured notes ("Notes") due 2016 at an offering price equal to 100% of par. Proceeds from the Notes were used to repay borrowings under our senior secured credit facility.
Concurrent with the closing of the private placement of the $250 million senior notes, we increased the commitments under our senior secured credit facility by $100 million, bringing the total commitments under our senior secured credit facility to $850 million. We may still request additional commitments of up to $150 million under the senior secured credit facility, which would increase the total commitments under our senior secured credit facility to $1 billion.
Total funded debt as of June 30, 2008 was approximately $575.0 million, approximately 57% of total book capitalization.
As of June 30, 2008, we had approximately $484 million in capacity available under our $850 million senior secured credit facility, after giving effect to outstanding borrowings of $325 million and the issuance of $41 million of letters of credit.
Hedging Update
During July 2008, we borrowed $87.4 million under our senior secured credit facility to terminate certain out-of-the-money natural gas and NGL commodity swaps. Prior to the terminations, the swaps were designated as hedges in accordance with SFAS 133, "Derivative Instruments and Hedging Activities." Deferred loss of approximately $20.8 million, $38.2 million and $27.9 million will be reclassified from OCI as a non-cash reduction of revenues during 2008, 2009 and 2010, respectively, when the hedged forecasted sales transactions were expected to occur. We also entered into new natural gas and NGL commodity swaps at then current market prices that match the production volumes of the terminated swaps through 2010.
Recent Activities
Strong producer activity in our Texas areas of operations remains impressive, resulting in volume increases for those operations. Additional recent highlights include:
Continued to experience growth in new acreage dedications in North Texas and SAOU in the second quarter of 2008;
Well connection activity remains strong, especially in SAOU, where we expect to have a record number of well connections in 2008;
The expansion of the Chico plant's CO2 amine treater is under construction and should be online in the third quarter of 2008;
Approved the expenditure of approximately $11 million of related pipeline projects to handle additional Barnett growth near our Bryan Compressor Station in Wise County;
A significant butane storage project in LOU began receiving liquids from ConocoPhillips' Lake Charles refinery on May 8th;
We extended our footprint into new active areas in SAOU with the purchase of third party pipelines and rights of way; and
We continue to pursue expansion and optimization projects utilizing existing infrastructure, which increases profitability without the need for large capital expenditure outlays and are pursuing or evaluating multiple growth projects. We expect 2008 maintenance and expansion capital expenditures to approximate $70 million.
Conference Call
Targa Resources Partners will host a conference call for investors and analysts at 11:00 a.m. Eastern Time (10:00 a.m. Central Time) on August 11, 2008 to discuss second 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 800-240-5318. The pass code is 11116778. 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 August 25, 2008. Replay access numbers are 303-590-3000 or 800-405-2236 with pass code 11116778.
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 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 income (loss) 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:
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 (loss). Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income (loss). 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. 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 (loss). 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.
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.
Investor contact info:
Phone: 713-584-1133
Anthony Riley
Sr. Manager - Finance/Investor Relations
Matt Meloy
Vice President - Finance and Treasurer