HOUSTON, Aug. 11, 2008 (PRIME NEWSWIRE) -- 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).
Three Months Ended Six Months Ended
June 30, June 30,
2008 2007 2008 2007
------- ------- -------- -------
(In millions, except operating
and price data)
Revenues $ 630.5 $ 433.6 $1,142.6 $ 782.4
Product purchases 555.2 371.7 997.3 666.2
Operating expense, excluding DD&A 14.7 11.8 27.3 23.9
Depreciation and amortization
expense 18.4 17.6 36.7 35.7
General and administrative expense 5.7 4.6 10.9 8.0
Gain on sale of assets -- (0.3) (0.1) (0.3)
------- ------- -------- -------
Income from operations 36.5 28.2 70.5 48.9
Interest expense, net (8.0) (5.2) (16.7) (7.8)
Interest expense, allocated
from Parent -- (2.7) -- (16.2)
Loss on mark-to-market derivative
instruments -- (6.2) -- (21.0)
Deferred income tax expense (0.3) (0.3) (0.7) (0.7)
------- ------- -------- -------
Net income $ 28.2 $ 13.8 $ 53.1 $ 3.2
======= ======= ======== =======
Financial data:
Operating margin $ 60.7 $ 50.1 $ 118.1 $ 92.3
Adjusted EBITDA 55.5 45.5 108.2 84.8
Distributable cash flow 40.1 33.0 79.6 51.6
Operating data:
Gathering throughput, MMcf/d 463.9 453.1 463.4 439.2
Plant natural gas inlet, MMcf/d 435.2 427.1 436.4 412.5
Gross NGL production, MBbl/d 44.5 43.2 44.1 41.1
Natural gas sales, BBtu/d 410.0 414.6 414.2 397.5
NGL sales, MBbl/d 39.1 36.5 38.5 34.8
Condensate sales, MBbl/d 3.7 3.7 3.7 3.6
Average realized prices:
Natural Gas, $/MMBtu
Average realized sales price $ 10.52 $ 7.29 $ 9.22 $ 6.97
Impact of hedging (0.05) 0.06 -- 0.07
------- ------- -------- -------
Average realized price $ 10.47 $ 7.36 $ 9.22 $ 7.04
======= ======= ======== =======
NGL, $/gal
Average realized sales price $ 1.46 $ 0.97 $ 1.38 $ 0.90
Impact of hedging (0.11) (0.01) (0.09) --
------- ------- -------- -------
Average realized price $ 1.35 $ 0.96 $ 1.29 $ 0.90
======= ======= ======== =======
Condensate, $/ Bbl
Average realized sales price $106.17 $ 59.36 $ 96.84 $ 55.34
Impact of hedging (5.06) 0.90 (3.46) 1.36
------- ------- -------- -------
Average realized price $101.11 $ 60.26 $ 93.38 $ 56.70
======= ======= ======== =======
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:
1. Continued to experience growth in new acreage dedications in North Texas and SAOU in the second quarter of 2008;
2. Well connection activity remains strong, especially in SAOU, where we expect to have a record number of well connections in 2008;
3. The expansion of the Chico plant's CO2 amine treater is under construction and should be online in the third quarter of 2008;
4. Approved the expenditure of approximately $11 million of related pipeline projects to handle additional Barnett growth near our Bryan Compressor Station in Wise County;
5. A significant butane storage project in LOU began receiving liquids from ConocoPhillips' Lake Charles refinery on May 8th;
6. We extended our footprint into new active areas in SAOU with the purchase of third party pipelines and rights of way; and
7. 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:
Three Months Ended Six Months Ended
June 30, June 30,
2008 2007(a) 2008 2007(a)
----- ----- ----- -----
(In millions)
Reconciliation of "distributable
cash flow" to "net income":
Net income $28.2 $13.8 $53.1 $ 3.2
Depreciation and amortization
expense 18.4 17.6 36.7 35.7
Deferred income tax expense 0.4 0.3 0.7 0.7
Amortization of debt issue costs 0.5 0.3 0.9 1.0
Loss on mark-to-market derivative
instruments -- 6.1 -- 21.0
Maintenance capital expenditures (7.4) (5.1) (11.8) (10.0)
----- ----- ----- -----
Distributable Cash Flow $40.1 $33.0 $79.6 $51.6
===== ===== ===== =====
(a) Distributable cash flow for the three and six months ended June
30, 2007 reflects allocated interest from Parent of $2.7 million
and $16.2 million, respectively.
For the Six Months Ended June 30, 2007
-------------------------------------------
Post
Acquisi-
Pre-Acquisition tion
-------------------------- -------
SAOU-LOU North Texas
Jan 1, 2007 Jan 1, 2007
to to
TRP LP June 30, 2007 Feb 13, 2007 TRP LP
------ ------------- ------------ ------
(In millions)
Net income (loss) $ 3.2 $ 3.9 $(6.9) $ 6.2
Depreciation and
amortization expense 35.7 7.2 6.9 21.6
Deferred income tax
expense 0.7 -- -- 0.7
Amortization of debt
issue costs 1.0 0.7 -- 0.3
Loss on mark-to-market
derivative instruments 21.0 21.0 -- --
Maintenance capital
expenditures (10.0) (4.8) (1.5) (3.7)
----- ----- ----- -----
Distributable Cash Flow $51.6 $28.0 $(1.5) $25.1
===== ===== ===== =====
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.
Three Months Ended Six Months Ended
June 30, June 30,
2008 2007 2008 2007
------ ------ ------ ------
Reconciliation of Non-GAAP
Measures
--------------------------
Reconciliation of "Adjusted
EBITDA" to net cash provided
by operating activities:
Net cash provided by
operating activities $ 46.6 $ 25.3 $ 99.4 $ 68.9
Allocated interest expense
from parent -- 2.4 -- 15.2
Interest expense, net 7.5 5.2 15.8 7.9
Changes in operating
working capital which
used (provided) cash:
Accounts receivable and
other 43.5 25.0 48.9 7.9
Accounts payable (1.1) 0.2 0.1 (2.6)
Accrued liabilities (41.0) (12.6) (56.0) (12.5)
------ ------ ------ ------
Adjusted EBITDA $ 55.5 $ 45.5 $108.2 $ 84.8
====== ====== ====== ======
Reconciliation of "Adjusted
EBITDA" to net income (loss):
Net income (loss) 28.2 $ 13.8 $ 53.1 $ 3.2
Add:
Allocated interest
expense, net -- 2.7 -- 16.2
Interest expense, net 8.0 5.2 16.7 7.9
Deferred income tax
expense 0.4 0.3 0.7 0.7
Depreciation and amorti-
zation expense 18.4 17.6 36.7 35.7
Risk Management
Activities 0.5 5.9 1.0 21.1
------ ------ ------ ------
Adjusted EBITDA $ 55.5 $ 45.5 $108.2 $ 84.8
====== ====== ====== ======
Reconciliation of "operating
margin" to net income (loss):
Net income (loss) $ 28.2 $ 13.8 $ 53.1 $ 3.2
Add:
Depreciation and amorti-
zation expense 18.4 17.6 36.7 35.7
Deferred income tax
expense 0.4 0.3 0.7 0.7
Allocated interest
expense, net -- 2.7 -- 16.2
Interest expense, net 8.0 5.2 16.7 7.9
Non-cash gain related to
derivative instruments -- 6.1 -- 21.0
General and administra-
tive expense 5.7 4.4 10.9 7.6
------ ------ ------ ------
Operating margin $ 60.7 $ 50.1 $118.1 $ 92.3
====== ====== ====== ======
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
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2008 2007
---------- ----------
(Unaudited)
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 31,988 $ 50,994
Receivables from third parties 84,847 59,346
Receivables from affiliated companies 107,367 87,547
Inventory 2,350 1,624
Assets from risk management activities 1,926 8,695
Other current assets 395 269
---------- ----------
Total current assets 228,873 208,475
Property, plant and equipment, at cost 1,455,834 1,433,955
Accumulated depreciation (210,923) (174,361)
---------- ----------
Property, plant and equipment, net 1,244,911 1,259,594
Debt issue costs 12,321 6,588
Long-term assets from risk management
activities 3,362 3,040
Other assets 2,285 2,275
---------- ----------
Total assets $1,491,752 $1,479,972
========== ==========
LIABILITIES AND
PARTNERS' CAPITAL
Current liabilities:
Accounts payable $ 5,616 $ 5,693
Accrued liabilities 198,820 142,836
Liabilities from risk management
activities 115,293 44,003
---------- ----------
Total current liabilities 319,729 192,532
---------- ----------
Long-term debt 575,000 626,300
Long-term liabilities from risk
management activities 153,697 43,109
Deferred income taxes 1,259 559
Other long-term liabilities 3,451 3,266
Commitments and contingencies
Partners' capital:
Common unitholders (34,652,000 and
34,636,000 units issued and outstanding
at June 30, 2008 and December 31,
2007, respectively) 778,039 770,207
Subordinated unitholders (11,528,231 units
issued and outstanding at June 30, 2008
and December 31, 2007) (82,431) (84,999)
General partner (942,455 and 942,128 units
issued and outstanding at June 30, 2008
and December 31, 2007, respectively) 8,424 4,234
Accumulated other comprehensive loss (265,416) (75,236)
---------- ----------
Total partners' capital 438,616 614,206
---------- ----------
Total liabilities and partners' capital $1,491,752 $1,479,972
========== ==========
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended Six Months Ended
June 30, June 30,
2008 2007 2008 2007
-------- -------- --------- --------
(Unaudited)
(In thousands, except per unit amounts)
Revenues from third parties $243,138 $175,149 $ 438,210 $315,339
Revenues from affiliates 387,382 258,466 704,379 467,057
-------- -------- --------- --------
Total operating revenues 630,520 433,615 1,142,589 782,396
Costs and expenses:
Product purchases from
third parties 478,890 310,465 854,515 564,619
Product purchases from
affiliates 76,269 61,236 142,794 101,580
Operating expenses 14,701 11,795 27,271 23,947
Depreciation and amortiza-
tion expense 18,421 17,619 36,669 35,657
General and administrative
expense 5,715 4,632 10,916 7,986
Other -- --
Gain on sale of assets (1) (315) (75) (315)
Loss (gain) on sale of assets -- -- -- --
-------- -------- --------- --------
593,995 405,432 1,072,090 733,474
-------- -------- --------- --------
Income from operations 36,525 28,183 70,499 48,922
Other income (expense):
Interest expense, net (7,976) (5,154) (16,694) (7,859)
Interest expense allocated
from Parent -- (2,732) -- (16,175)
Loss on mark-to-market
derivative instruments -- (6,122) -- (21,002)
Other 20 (16) 36 5
-------- -------- --------- --------
Income before income taxes 28,569 14,159 53,841 3,891
Deferred income tax expense 363 348 700 707
-------- -------- --------- --------
Net income 28,206 13,811 53,141 3,184
Net income (loss) attributable
to predecessor operations -- 9,771 -- (3,009)
-------- -------- --------- --------
Net income allocable to
partners 28,206 4,040 53,141 6,193
Net income attributable to
general partner interests 3,384 81 5,230 124
-------- -------- --------- --------
Net income available to common
and subordinated unitholders $ 24,822 $ 3,959 $ 47,911 $ 6,069
======== ======== ========= ========
Basic net income per common
and subordinated unit $ 0.54 $ 0.13 $ 1.04 $ 0.20
======== ======== ========= ========
Diluted net income per common
and subordinated unit $ 0.54 $ 0.13 $ 1.04 $ 0.20
======== ======== ========= ========
Basic average number of common
and subordinated units
outstanding 46,154 30,848 46,152 30,848
Diluted average number of
common and subordinated
units outstanding 46,163 30,855 46,160 30,854
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended June 30,
2008 2007
--------- ---------
(Unaudited)
(In thousands)
Cash flows from operating activities
Net income $ 53,141 $ 3,184
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation 36,607 35,596
Amortization 1,038 1,173
Accretion of asset retirement obligations 72 204
Deferred income tax expense 700 707
Risk management activities 1,011 21,087
Gain on sale of assets (75) (315)
Changes in operating assets and liabilities:
Accounts receivable (45,321) (7,151)
Inventory (726) (270)
Other (2,992) (503)
Accounts payable (77) 2,641
Accrued liabilities 55,984 12,549
--------- ---------
Net cash provided by operating activities 99,362 68,902
--------- ---------
Cash flows from investing activities
Purchases of property, plant and equipment (17,586) (23,352)
Other (4,150) (30)
--------- ---------
Net cash used in investing activities (21,736) (23,382)
--------- ---------
Cash flows from financing activities
Proceeds from equity offerings -- 380,768
Costs incurred in connection with
public offerings (72) (3,175)
General partner contributions 8 --
Distributions (38,678) (5,315)
Proceeds from borrowings under
credit facility -- 342,500
Proceeds from issuance of senior notes 250,000 --
Costs incurred in connection with
financing arrangements (6,590) (4,145)
Repayments of loans:
Affiliated -- (665,692)
Credit facility (301,300) (48,000)
Deemed Parent distributions -- (33,100)
--------- ---------
Net cash used in financing activities (96,632) (36,159)
--------- ---------
Net change in cash and cash equivalents (19,006) 9,361
Cash and cash equivalents, beginning
of period 50,994 --
--------- ---------
Cash and cash equivalents, end
of period $ 31,988 $ 9,361
========= =========
Supplemental cash flow information:
Net settlement of allocated
indebtedness and debt issue costs $ -- $ 239,065
Net contribution of affiliated receivables -- 38,856