Exhibit 99.1
Targa Resources Partners LP Reports Second Quarter 2009 Financial Results
HOUSTON – August 6, 2009 -Targa Resources Partners LP ("Targa Resources Partners" or the "Partnership") (NASDAQ: NGLS) today reported second quarter 2009 net income of $6.6 million (which includes an $11.2 million non-cash hedge loss) or $0.10 per diluted limited partner unit as compared to second quarter 2008 net income of $28.2 million or $0.54 per diluted limited partner unit. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments ("Adjusted EBITDA") of $46.9 million for the second quarter of 2009 compared to Adjusted EBITDA of $55.4 million for the second quarter of 2008.
Distributable cash flow for the second quarter of 2009 was $35.6 million which corresponds to distribution coverage of approximately 1.35 times for the 47.2 million total units outstanding on June 30, 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).
“We are pleased with our second quarter operating and financial performance which was driven by higher sequential volumes, improvements in crude and NGL prices and results of our cost control efforts. We still expect to close the previously announced acquisition of the Downstream Business in the third quarter. Combined second quarter 2009 operating margin for the Logistics Assets, NGL Distribution and Marketing and Wholesale Marketing segments was $35.4 million which does not include $1.7 million of equity earnings from Gulf Coast Fractionators. We believe the powerful combination of this strategic asset platform, substantial distribution support and the maximum equity consideration permitted under Targa’s financing agreements underscores Targa’s commitment to the Partnership’s long term success” said Rene Joyce, Chief Executive Officer of the Partnership's general partner and of Targa Resources, Inc. ("Targa").
On July 20, 2009, the Partnership announced a cash distribution of 51.75¢ per common unit, or $2.07 per unit on an annualized basis, for the second quarter of 2009. This cash distribution will be paid August 14, 2009 on all outstanding common units to holders of record as of the close of business on August 5, 2009.
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Review of Second Quarter Results
Net income for the second quarter of 2009 was $6.6 million compared to $28.2 million of net income for the 2008 period. The decrease in net income was primarily attributable to an $11.2 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 depreciation, G&A and interest expenses, partially offset by lower operating expenses.
Revenues decreased $389.9 million, or 62%, to $240.7 million for the second quarter of 2009 from $630.5 million for the second quarter of 2008, driven primarily by lower prices for natural gas, NGL and condensate.
Gathering throughput for the second quarter of 2009 increased 2% to 475.3 MMcf/d compared to 463.9 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 4% higher at 454.7 MMcf/d for the second quarter of 2009 compared to 439.0 MMcf/d for the same period in 2008. These increases resulted primarily from increases at our North Texas and SAOU Systems due to higher producer volumes from new well completions, partially offset by lower volumes at our LOU system. At our LOU System, lower producer volumes were offset by discretionary volumes, including startup of a new source during the second quarter.
Gross NGL production of 44.2 MBbl/d for the second quarter of 2009 was 1% higher than gross NGL production of 43.7 MBbl/d for the second quarter of 2008. NGL sales of 39.8 MBbl/d for the second quarter of 2009 were 2% higher than sales of 39.1 MBbl/d during the second quarter of 2008. The increase in NGL sales is primarily due to higher plant volumes. Natural gas sales volumes decreased 8% to 378.3 BBtu/d in the second quarter of 2009 compared to 410.0 BBtu/d during the second quarter of 2008. The decrease in natural gas sales is primarily the result of a decrease in purchases from affiliates for resale.
The average realized natural gas price decreased by $6.92 per MMBtu, or 66%, to $3.55 per MMBtu for the second quarter of 2009 compared to $10.47 per MMBtu for the same period in 2008. The average realized price for NGLs decreased by $0.69 per gallon, or 51%, to $0.66 per gallon for the second quarter of 2009 compared to $1.35 per gallon for the same period in 2008. The average realized price for condensate decreased by $47.71 per barrel, or 47%, to $53.40 per barrel for the second quarter of 2009 compared to $101.11 per barrel for the second quarter of 2008. Realized prices reflect the impact of our hedging program.
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Review of Six Month Results
Net income for the first six months of 2009 was $4.4 million compared to net income of $53.1 million for the first six months of 2008. Non-cash hedge losses reduced net income by $29.7 million for the first six months of 2009 compared to $1.0 million for the 2008 period. Net income was also negatively impacted by lower commodity prices and higher depreciation, G&A and interest expenses, partially offset by lower operating expenses.
Revenues were $479.7 million for the first six months of 2009, 58% lower than revenues of $1,142.6 million for the first six months of 2008, driven primarily by lower prices for natural gas, NGL and condensate and lower natural gas and condensate sales volumes.
Gathering throughput for the first six months of 2009 decreased by 2% to 452.5 MMcf/d compared to 463.5 MMcf/d for the 2008 period. Plant natural gas inlet was 431.6 MMcf/d for first half of 2009, 2% lower than the 2008 period. Gross NGL production of 42.9 MBbl/d for the first six months of 2009 was 3% lower than gross NGL production of 44.1 MBbl/d for the first six months of 2008. These decreases result primarily from the impact of lower producer and discretionary volumes at our LOU system, somewhat offset by increases at our North Texas and SAOU systems as well as startup of a new discretionary volume source at LOU during the second quarter.
Natural gas sales volumes decreased 11% to 366.8 BBtu/d for the first half of 2009 as compared to 414.2 BBtu/d for the year earlier period. 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. NGL sales volumes were 38.5 MBbl/d for the first six months of 2009, unchanged from the 2008 period. Condensate sales volumes decreased by 0.5 MBbl/d, or 14%, to 3.2 MBbl/d for the first half of 2009.
The average realized natural gas price decreased by $5.19 per MMBtu, or 56%, to $4.03 per MMBtu for the second quarter of 2009 compared to $9.22 per MMBtu for the same period in 2008. The average realized price for NGLs decreased by $0.68 per gallon, or 53%, to $0.61 per gallon for the second quarter of 2009 compared to $1.29 per gallon for the same period in 2008. The average realized price for condensate decreased by $46.40 per barrel, or 50%, to $46.98 per barrel for the second quarter of 2009 compared to $93.38 per barrel for the second quarter of 2008. Realized prices reflect the impact of our hedging program.
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Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| (In millions) | ||||||||||||||||
| Revenues | $ | 240.7 | $ | 630.5 | $ | 479.7 | $ | 1,142.6 | ||||||||
| Product purchases | 185.6 | 555.2 | 380.1 | 997.3 | ||||||||||||
| Operating expense, excluding DD&A | 11.9 | 14.7 | 24.8 | 27.3 | ||||||||||||
| Depreciation and amortization expense | 19.0 | 18.4 | 37.9 | 36.7 | ||||||||||||
| General and administrative expense | 7.6 | 5.7 | 12.9 | 10.9 | ||||||||||||
| Gain on asset sales | - | - | - | (0.1 | ) | |||||||||||
| Income from operations | 16.6 | 36.5 | 24.0 | 70.5 | ||||||||||||
| Interest expense, net | (9.8 | ) | (8.0 | ) | (19.7 | ) | (16.7 | ) | ||||||||
| Deferred income tax expense | (0.3 | ) | (0.3 | ) | (0.6 | ) | (0.7 | ) | ||||||||
| Other | 0.1 | - | 0.7 | - | ||||||||||||
| Net income | $ | 6.6 | $ | 28.2 | $ | 4.4 | $ | 53.1 | ||||||||
| Financial data: | ||||||||||||||||
| Operating margin | $ | 43.2 | $ | 60.6 | $ | 74.8 | $ | 118.0 | ||||||||
| Adjusted EBITDA | 46.9 | 55.4 | 92.3 | 108.2 | ||||||||||||
| Distributable cash flow | 35.6 | 40.5 | 69.1 | 80.6 | ||||||||||||
| Operating data: | ||||||||||||||||
| Gathering throughput, MMcf/d | ||||||||||||||||
| LOU System | 189.5 | 194.2 | 167.7 | 195.2 | ||||||||||||
| SAOU System | 99.4 | 99.2 | 100.6 | 98.5 | ||||||||||||
| North Texas System | 186.4 | 170.5 | 184.2 | 169.8 | ||||||||||||
| 475.3 | 463.9 | 452.5 | 463.5 | |||||||||||||
| Plant natural gas inlet, MMcf/d | ||||||||||||||||
| LOU System | 181.9 | 182.9 | 161.4 | 184.0 | ||||||||||||
| SAOU System | 93.0 | 91.9 | 92.2 | 91.1 | ||||||||||||
| North Texas System | 179.8 | 164.2 | 178.0 | 163.3 | ||||||||||||
| 454.7 | 439.0 | 431.6 | 438.4 | |||||||||||||
| Gross NGL production, MBbl/d | ||||||||||||||||
| LOU System | 9.0 | 10.2 | 8.3 | 10.5 | ||||||||||||
| SAOU System | 14.3 | 14.4 | 14.3 | 14.3 | ||||||||||||
| North Texas System | 20.9 | 19.1 | 20.3 | 19.3 | ||||||||||||
| 44.2 | 43.7 | 42.9 | 44.1 | |||||||||||||
| Natural gas sales, BBtu/d | 378.3 | 410.0 | 366.8 | 414.2 | ||||||||||||
| NGL sales, MBbl/d | 39.8 | 39.1 | 38.5 | 38.5 | ||||||||||||
| Condensate sales, MBbl/d | 3.1 | 3.7 | 3.2 | 3.7 | ||||||||||||
| Average realized prices: | ||||||||||||||||
| Natural gas, $/MMBtu | 3.55 | 10.47 | 4.03 | 9.22 | ||||||||||||
| NGLs, $/gal | 0.66 | 1.35 | 0.61 | 1.29 | ||||||||||||
| Condensate, $/ Bbl | 53.40 | 101.11 | 46.98 | 93.38 | ||||||||||||
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Acquisition of the Downstream Business
On July 27, 2009 the Partnership agreed to acquire Targa Resources, Inc.’s (“Targa”) natural gas liquids business (the “Downstream Business”) for aggregate consideration of $530 million, subject to certain adjustments. As part of the transaction, Targa agreed to provide distribution support to the Partnership in the form of a reduction in the reimbursement of allocated general and administrative expense if necessary for a 1.0 times distribution coverage ratio, calculated using the current distribution rate of $0.5175 per limited partner unit and subject to maximum support of $8 million in any quarter. The distribution support will be in effect for the nine quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011.
Consideration to Targa will include 25% of the transaction value in newly issued common and general partner units of the Partnership, the maximum equity component permitted under Targa’s financing agreements. The equity will consist of 8,527,615 common units and 174,033 general partner units valued at $15.227 per unit (calculated using the volume weighted average trading price for the 10-day period through and including July 17, 2009). Pro forma for the transaction, Targa will own 20,055,846 common units (35.9%) and 1,117,141 general partner units (2%). The remaining 75% of the transaction value, or approximately $397.5 million, will be in cash, funded through borrowings under the Partnership’s senior secured revolving credit facility.
For the full year ending December 31, 2009, the Downstream Business is expected to generate Adjusted EBITDA of approximately $80 to $85 million (see the section of this release entitled “Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA and reconciliations of such measures to the comparable GAAP measures). We estimate maintenance capital expenditures associated with the Downstream Business will be approximately $10 million and $5 million for the twelve and four month period ending December 31, 2009, respectively.
The transaction, which is subject to standard closing conditions, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the "HSR Act") is anticipated to close in the third quarter of this year.
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Capitalization and Liquidity Update
Total funded debt as of June 30, 2009 was approximately $657 million including approximately $448 million outstanding under our $850 million senior secured revolving credit facility and $209 million of 8.25 percent senior unsecured notes due 2016. As of June 30, 2009, we had approximately $378 million in capacity available under our credit facility after giving effect to the Lehman default and the issuance of approximately $13 million of letters of credit. As of June 30, 2009, we had approximately $38 million of cash, bringing total liquidity to approximately $416 million.
On July 6, 2009 the Partnership closed a $250 million offering of 11.25 percent senior unsecured notes due 2017. The 11.25 percent notes were issued at 94.973 percent of the face amount, resulting in gross proceeds of $237 million. On July 29, 2009, we executed a Commitment Increase Supplement (the “Supplement”) to our existing senior secured credit facility. The Supplement increased the commitments under our credit facility by $127.5 million, bringing the total commitments to $977.5 million. We may request additional commitments under our credit facility of up to $22.5 million, which would increase the total commitments under our credit facility to $1 billion.
After giving effect to the recent notes offering, the Supplement and the acquisition of the Downstream Business, pro forma liquidity would be approximately $301 million as of June 30, 2009. In addition to a strong liquidity position, the Partnership is within its financial covenants and has no near term maturities under its credit facility or senior unsecured notes.
We estimate capital expenditures to be approximately $40 million in 2009, down from our prior annual estimate because of the ongoing impacts from cost control programs and cost savings. 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 10 a.m. Eastern Time (9 a.m. Central Time) on August 6, 2009 to discuss second 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) 762-8779. The pass code is 4118629. 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 August 20, 2009. Replay access numbers are 303-590-3030 or 800-406-7325 with pass code 4118629.
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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
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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 to distributable cash flow for the Partnership for the periods indicated:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| Reconciliation of net income | (In millions) | |||||||||||||||
| to "distributable cash flow": | ||||||||||||||||
| Net income | $ | 6.6 | $ | 28.2 | $ | 4.4 | $ | 53.1 | ||||||||
| Depreciation and amortization expense | 19.0 | 18.4 | 37.9 | 36.7 | ||||||||||||
| Deferred income tax expense | 0.3 | 0.3 | 0.6 | 0.7 | ||||||||||||
| Amortization in interest expense | 0.6 | 0.5 | 1.2 | 0.9 | ||||||||||||
| Non-cash loss related to derivatives | 11.2 | 0.5 | 29.7 | 1.0 | ||||||||||||
| Maintenance capital expenditures | (2.1 | ) | (7.4 | ) | (4.7 | ) | (11.8 | ) | ||||||||
| Distributable cash flow | $ | 35.6 | $ | 40.5 | $ | 69.1 | $ | 80.6 | ||||||||
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,
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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.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| (In millions) | ||||||||||||||||
| Reconciliation of net cash provided by operating activities to Adjusted EBITDA: | ||||||||||||||||
| Net cash provided by operating activities | $ | 50.4 | $ | 46.6 | $ | 72.4 | $ | 99.4 | ||||||||
| Interest expense, net | 9.2 | 7.5 | 18.5 | 15.8 | ||||||||||||
| Changes in operating working capital | ||||||||||||||||
| which used (provided) cash: | ||||||||||||||||
| Accounts receivable and other assets | 1.6 | 43.4 | (4.8 | ) | 48.9 | |||||||||||
| Accounts payable and other liabilities | (14.3 | ) | (42.1 | ) | 6.2 | (55.9 | ) | |||||||||
| Adjusted EBITDA | $ | 46.9 | $ | 55.4 | $ | 92.3 | $ | 108.2 | ||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| (In millions) | ||||||||||||||||
| Reconciliation of net income to Adjusted EBITDA: | ||||||||||||||||
| Net income | $ | 6.6 | $ | 28.2 | $ | 4.4 | $ | 53.1 | ||||||||
| Add: | ||||||||||||||||
| Interest expense, net | 9.8 | 8.0 | 19.7 | 16.7 | ||||||||||||
| Deferred income tax expense | 0.3 | 0.3 | 0.6 | 0.7 | ||||||||||||
| Depreciation and amortization expense | 19.0 | 18.4 | 37.9 | 36.7 | ||||||||||||
| Non-cash loss related to derivatives | 11.2 | 0.5 | 29.7 | 1.0 | ||||||||||||
| Adjusted EBITDA | $ | 46.9 | $ | 55.4 | $ | 92.3 | $ | 108.2 | ||||||||
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Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| (In millions) | ||||||||||||||||
| Reconciliation of net income to operating margin: | ||||||||||||||||
| Net income | $ | 6.6 | $ | 28.2 | $ | 4.4 | $ | 53.1 | ||||||||
| Add: | ||||||||||||||||
| Depreciation and amortization expense | 19.0 | 18.4 | 37.9 | 36.7 | ||||||||||||
| Deferred income tax expense | 0.3 | 0.3 | 0.6 | 0.7 | ||||||||||||
| Interest expense, net | 9.8 | 8.0 | 19.7 | 16.7 | ||||||||||||
| General and administrative and other expense | 7.5 | 5.7 | 12.2 | 10.8 | ||||||||||||
| Operating margin | $ | 43.2 | $ | 60.6 | $ | 74.8 | $ | 118.0 | ||||||||
| Reconciliation of non-GAAP Measures for the Downstream Business | ||||||||
| Twelve Months Ended | ||||||||
| December 31, 2009 | ||||||||
| (In millions) | ||||||||
| Low Range | High Range | |||||||
| Reconciliation of net income to Adjusted EBITDA | ||||||||
| Net income | $ | (5.6 | ) | $ | (0.6 | ) | ||
| Depreciation and amortization | 25.4 | 25.4 | ||||||
| Interest expense | 59.4 | 59.4 | ||||||
| Income tax expense | 0.8 | 0.8 | ||||||
| Adjusted EBITDA | $ | 80.0 | $ | 85.0 | ||||
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| Three Months | Six Months | |||||||
| Reconciliation of net income attributable to Targa | Ended | Ended | ||||||
| Resources, Inc. to operating margin: | June 30, 2009 | June 30, 2009 | ||||||
| (In millions) | ||||||||
| Net income attributable to Targa Resources, Inc. | $ | 13.5 | $ | 16.1 | ||||
| Add: | ||||||||
| Net income attibutable to noncontrolling interest | 8.3 | 6.6 | ||||||
| Depreciation and amortization expense | 42.1 | 83.7 | ||||||
| General and administrative expense | 28.1 | 51.9 | ||||||
| Interest expense, net | 22.1 | 47.8 | ||||||
| Income tax benefit | 6.5 | 6.4 | ||||||
| Other, net | 0.1 | (1.0 | ) | |||||
| Operating margin | $ | 120.7 | $ | 211.5 | ||||
| Natural Gas Gathering and Processing | $ | 84.6 | $ | 147.7 | ||||
| Logistics Assets | 22.8 | 31.8 | ||||||
| NGL Distribution and Marketing Services | 9.5 | 23.9 | ||||||
| Wholesale Marketing | 3.1 | 7.4 | ||||||
| Other | 0.7 | 0.7 | ||||||
| $ | 120.7 | $ | 211.5 | |||||
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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
Senior Manager - Finance/Investor Relations
Matt Meloy
Vice President - Finance and Treasurer
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| FINANCIAL SUMMARY (unaudited) | ||||||||
| CONSOLIDATED BALANCE SHEET DATA | ||||||||
| (In thousands) | ||||||||
| June 30, 2009 | December 31, 2008 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | 37,861 | $ | 81,768 | ||||
| Assets from risk management activities | 65,950 | 91,816 | ||||||
| Other current assets | 77,605 | 81,926 | ||||||
| Total current assets | 181,416 | 255,510 | ||||||
| Property, plant and equipment, net | 1,222,261 | 1,244,337 | ||||||
| Long-term assets from risk management activities | 34,426 | 68,296 | ||||||
| Other assets | 12,670 | 12,763 | ||||||
| Total assets | $ | 1,450,773 | $ | 1,580,906 | ||||
| LIABILITIES AND PARTNERS' CAPITAL | ||||||||
| Accounts payable and accrued liabilities | $ | 80,940 | $ | 94,840 | ||||
| Liabilities from risk management activities | 12,156 | 11,664 | ||||||
| Total current liabilities | 93,096 | 106,504 | ||||||
| Long-term debt | 656,845 | 696,845 | ||||||
| Long term liabilities from risk management activities | 11,540 | 9,679 | ||||||
| Other long-term liabilities | 6,268 | 5,514 | ||||||
| Total liabilities | 767,749 | 818,542 | ||||||
| Partners' capital | 683,024 | 762,364 | ||||||
| Total liabilities and partners' capital | $ | 1,450,773 | $ | 1,580,906 | ||||
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| FINANCIAL SUMMARY (unaudited) | ||||||||||||||||
| CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||||||||||
| (In thousands, except per unit data) | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| REVENUES | $ | 240,663 | $ | 630,520 | $ | 479,697 | $ | 1,142,589 | ||||||||
| COSTS AND EXPENSES: | ||||||||||||||||
| Product purchases | 185,601 | 555,159 | 380,165 | 997,309 | ||||||||||||
| Operating expenses | 11,907 | 14,701 | 24,810 | 27,271 | ||||||||||||
| Depreciation and amortization expense | 18,972 | 18,421 | 37,850 | 36,669 | ||||||||||||
| General and administrative expense | 7,544 | 5,715 | 12,865 | 10,916 | ||||||||||||
| Casualty loss adjustment | (13 | ) | - | (13 | ) | - | ||||||||||
| Gain on sale of assets | - | (1 | ) | - | (75 | ) | ||||||||||
| Total costs and expenses | 224,011 | 593,995 | 455,677 | 1,072,090 | ||||||||||||
| INCOME FROM OPERATIONS | 16,652 | 36,525 | 24,020 | 70,499 | ||||||||||||
| Other income (expense): | ||||||||||||||||
| Interest expense, net | (9,774 | ) | (7,976 | ) | (19,698 | ) | (16,694 | ) | ||||||||
| Other | - | 20 | 726 | 36 | ||||||||||||
| Income (loss) before income taxes | 6,878 | 28,569 | 5,048 | 53,841 | ||||||||||||
| Income tax expense | (300 | ) | (363 | ) | (600 | ) | (700 | ) | ||||||||
| NET INCOME | 6,578 | 28,206 | 4,448 | 53,141 | ||||||||||||
| Net income attributable to general partner | 2,066 | 3,384 | 3,956 | 5,230 | ||||||||||||
| Net income available to limited partners | $ | 4,512 | $ | 24,822 | $ | 492 | $ | 47,911 | ||||||||
| Basic and diluted net income per limited partner unit | $ | 0.10 | $ | 0.54 | $ | 0.01 | $ | 1.04 | ||||||||
| Basic and diluted average limited partner units outstanding | 46,212 | 46,180 | 46,209 | 46,173 | ||||||||||||
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| FINANCIAL SUMMARY (unaudited) | ||||||||
| CONSOLIDATED CASH FLOW INFORMATION | ||||||||
| (In thousands) | ||||||||
Six Months Ended June 30, | ||||||||
| 2009 | 2008 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
| Net income | $ | 4,448 | $ | 53,141 | ||||
| Adjustments to reconcile net income to net cash | ||||||||
| provided by operating activities: | ||||||||
| Depreciation, amortization and accretion | 39,381 | 37,717 | ||||||
| Deferred income tax expense | 600 | 700 | ||||||
| Risk management activities | 29,726 | 1,011 | ||||||
| Gain on sale of assets | - | (75 | ) | |||||
| Changes in operating assets and liabilities | (1,728 | ) | 6,868 | |||||
| Net cash provided by operating activities | 72,427 | 99,362 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
| Additions to property, plant and equipment | (23,450 | ) | (17,586 | ) | ||||
| Other | (32 | ) | (4,150 | ) | ||||
| Net cash used in investing activities | (23,482 | ) | (21,736 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
| Repayments on credit facility | (40,000 | ) | (301,300 | ) | ||||
| Proceeds from issuance of senior notes | - | 250,000 | ||||||
| Distributions to unitholders | (52,751 | ) | (38,678 | ) | ||||
| General partner contributions | 5 | 8 | ||||||
| Costs incurred in connection with public offerings | (106 | ) | (72 | ) | ||||
| Costs incurred in connection with financing arrangements | - | (6,590 | ) | |||||
| Net cash used in financing activities | (92,852 | ) | (96,632 | ) | ||||
| Net change in cash and cash equivalents | (43,907 | ) | (19,006 | ) | ||||
| Cash and cash equivalents, beginning of period | 81,768 | 50,994 | ||||||
| Cash and cash equivalents, end of period | $ | 37,861 | $ | 31,988 | ||||
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