HOUSTON, March 31, 2008 (PRIME NEWSWIRE) -- Targa Resources Partners LP ("Targa Resources Partners" or the "Partnership") (Nasdaq:NGLS) today announced its financial results for the three months and year ended December 31, 2007. For the fourth quarter of 2007, the Partnership reported (i) net income of $22.7 million as determined under Generally Accepted Accounting Principles ("GAAP") for entities under common control (excluding results of operations for periods prior to the acquisition of a business by the Partnership, fourth quarter net income was $17.6 million or 42 cents per unit on a fully diluted basis); (ii) income from operations of $34.5 million and (iii) earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments ("Adjusted EBITDA") of $52.6 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).
For the full year 2007, the Partnership reported (i) net income of $40.3 million, as determined under GAAP for entities under common control (excluding results of operations for periods prior to the acquisition of a business by the Partnership, 2007 net income was $27.5 million or 81 cents per unit on a fully diluted basis); (ii) income from operations of $113.4 million and (iii) Adjusted EBITDA of $185.8 million.
In accordance with the accounting treatment for entities under common control, the results of operations for the year ended December 31, 2007 include the combined results for the full twelve months of both the North Texas system and the combined SAOU and LOU Systems ("SAOU" and "LOU", respectively). For the year ended December 31, 2006, the Partnership's results include the full year historical results of the combined SAOU and LOU Systems and of North Texas.
Operating results attributable to the unitholders of the Partnership include the results of the North Texas system subsequent to the Partnership's February 14, 2007 IPO, and the combined results of SAOU and LOU subsequent to the acquisition of these businesses by the Partnership on October 24, 2007.
The Partnership acquired the SAOU System located in the Permian Basin and the LOU System located in southwest Louisiana from Targa Resources, Inc. ("Targa") for approximately $705 million, subject to certain post-closing adjustments. In addition, the Partnership paid approximately $24.2 million to Targa for the termination of certain hedge transactions. The Partnership financed the acquisition with the proceeds from its public offering of 13,500,000 units and borrowings under its increased $750 million senior secured revolving credit facility. On November 20, 2007, the Partnership closed the partial exercise of the over-allotment option granted to the underwriters for an additional 1,800,000 common units.
On January 24, 2008, the board of Targa Resources Partners' general partner (the "Board") declared a cash distribution of $0.3975 per unit, or $1.59 per unit on an annualized basis, for the fourth quarter of 2007 payable to all unitholders. Distributable cash flow for the fourth quarter of 2007 was $36.7 million, including the results of SAOU and LOU for the full quarter, which corresponds to distribution coverage of 1.96 times for the 47.1 million units outstanding on December 31, 2007 (as compared to a weighted average of 41.8 million units reported for the fourth quarter in accordance with GAAP). Distributable cash flow was $29.6 million excluding results of operations for SAOU and LOU for the period prior to their acquisition on October 24, 2007. 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).
In addition, management informed the Board at its most recent meeting that it will recommend an increase in the first quarter 2008 distribution (which will be paid in the second quarter of 2008) to 41.75 cents per unit, or $1.67 per unit on an annualized basis. Management believes the Board will be supportive of this recommendation, although any distribution increase remains subject to final Board approval following a review of first quarter financial results.
Note on Entities Under Common Control
Targa's contribution of North Texas to us in connection with our February 14, 2007 IPO and our acquisition of SAOU and LOU from Targa on October 24, 2007 are treated as transfers of net assets between entities under common control under GAAP. This treatment has the following impact on the presentation of the Partnership's financial results:
* The underlying assets of North Texas and of SAOU and LOU were transferred to the Partnership at their recorded carrying values on the balance sheet of the common parent (Targa) with no step-up in book basis. * The combined SAOU and LOU Systems became the predecessor for the Partnership as they were the first entities owned by the common parent. Our financial information has been restated accordingly. * The historical results for the North Texas System are included starting with its acquisition by the common parent on October 31, 2005. * Debt allocated from the parent along with related interest expense and financing costs are recorded in the financial statements until the contribution to or acquisition by us of the relevant business (February 14, 2007 for North Texas and October 24, 2007 for the SAOU and LOU Systems ).
Review of Fourth Quarter Results
Three Months Three Months
Ended Ended
Dec. 31, 2007 Dec. 31, 2006
------------ ------------
(in millions of dollars,
except operating and
price data)
Revenues $ 474.0 $ 359.7
Product purchases 402.8 306.6
Operating expense, excluding DD&A 14.2 13.0
Depreciation and amortization expense 18.1 18.1
General and administrative expense 4.4 6.9
Loss (gain) on sale of assets -- --
------------ ------------
Income from operations $ 34.5 $ 15.1
============ ============
Financial data:
Operating margin $ 57.1 $ 40.1
Adjusted EBITDA $ 52.6 $ 33.2
Operating data:
Gathering throughput, MMcf/d 465.0 424.7
Plant natural gas inlet, MMcf/d 446.3 409.1
Gross NGL production, MBbl/d 44.4 41.7
Natural gas sales, BBtu/d 430.5 403.8
NGL sales, MBbl/d 38.5 35.3
Condensate sales, MBbl/d 3.3 3.4
Natural Gas, per MMBtu
Average realized sales price $ 6.51 $ 6.19
Impact of hedging 0.07 0.07
------------ ------------
Average realized price $ 6.58 $ 6.26
============ ============
NGL, per gal
Average realized sales price $ 1.32 $ 0.79
Impact of hedging (0.06) --
------------ ------------
Average realized price $ 1.26 $ 0.79
============ ============
Condensate, per Bbl
Average realized sales price $ 83.04 $ 55.18
Impact of hedging (1.71) 1.72
------------ ------------
Average realized price $ 81.33 $ 56.90
============ ============
Revenues were $474.0 million for the three-month period ended December 31, 2007, 32% higher than revenues of $359.7 million for the three months ended December 31, 2006. Income from operations for the fourth quarter of 2007 increased to $34.5 million from $15.1 million in 2006.
Net income for the fourth quarter 2007 was $22.7 million versus a net loss of $7.9 million for the same period 2006. The net loss in 2006 is principally due to interest expense totaling $22.5 million that is related to debt that was allocated to North Texas and to the SAOU and LOU Systems by Targa prior to the acquisition of these businesses by the Partnership.
For the quarter ended December 31, 2007, gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines) increased by 9% to 465.0 MMcf/d compared to 424.7 MMcf/d for the same period in 2006. For the same periods, plant natural gas inlet (the volume of natural gas passing through the meter located at the inlet of a processing plant) was 9% higher at 446.3 MMcf/d compared to 409.1 MMcf/d in 2006.
Gross NGL production of 44.4 MBbl/d for the three months ended December 31, 2007 was 6% higher than NGL production of 41.7 MBbl/d for the three months ended December 31, 2006. Natural gas sales volumes increased 7% to 430.5 BBtu/d in the three months ended December 31, 2007 as compared to the 403.8 BBtu/d sold in the 2006 period. Additionally, NGL sales of 38.5 MBbl/d for the fourth quarter of 2007 were 9% higher than the 35.3 MBbl/d sold in the same 2006 period.
Average realized natural gas price increased 32 cents per MMBtu from $6.26 per MMBtu for the three months ended December 31, 2006, to $6.58 per MMBtu for the twelve months ended December 31, 2007, including the impact of our hedging program. Average realized NGL prices were higher by 47 cents or 60% at $1.26 per gallon in 2007 and average realized condensate prices were $24.43 per barrel higher, or 43%, for 2007 at $81.33 per barrel, including the impacts of our hedging program.
Review of Year End Results
Year Ended Year Ended
Dec. 31, 2007 Dec. 31, 2006
------------ ------------
(in millions of dollars,
except operating and
price data)
Revenues $ 1,661.5 $ 1,738.5
Product purchases 1,406.8 1,517.7
Operating expense, excluding DD&A 50.9 49.1
Depreciation and amortization expense 71.8 69.9
General and administrative expense 18.9 16.1
Loss (gain) on sale of assets (0.3) --
------------ ------------
Income from operations $ 113.4 $ 85.7
============ ============
Financial data:
Operating margin $ 203.8 $ 171.7
Adjusted EBITDA $ 185.8 $ 154.1
Operating data:
Gathering throughput, MMcf/d 452.0 433.8
Plant natural gas inlet, MMcf/d 429.2 419.6
Gross NGL production, MBbl/d 42.6 42.4
Natural gas sales, BBtu/d 410.2 489.4
NGL sales, MBbl/d 36.4 36.0
Condensate sales, MBbl/d 3.6 3.3
Natural Gas, per MMBtu
Average realized sales price $ 6.58 $ 6.66
Impact of hedging 0.08 0.02
------------ ------------
Average realized price $ 6.66 $ 6.68
============ ============
NGL, per gal
Average realized sales price $ 1.05 $ 0.86
Impact of hedging (0.02) (0.01)
------------ ------------
Average realized price $ 1.03 $ 0.85
============ ============
Condensate, per Bbl
Average realized sales price $ 65.43 $ 59.28
Impact of hedging 0.19 0.59
------------ ------------
Average realized price $ 65.62 $ 59.87
============ ============
For the year ended December 31, 2007 revenues were $1,661.5 million, a 4.4% decline from $1,738.5 million for the year ended December 31, 2006. The decrease was primarily due to a decrease in affiliate-related volumes, somewhat offset by increases in prices, fees and other revenues. Income from operations increased by 32% to $113.4 million in 2007 from $85.7 million in 2006, driven by an improvement in third party volumes and a stronger pricing environment.
Net income for the year ended December 31, 2007 increased 347% to $40.3 million versus $11.6 million for 2006. The 2007 net income includes $19.4 million of interest expense allocated from Targa to North Texas and to the SAOU and LOU Systems prior to their acquisition by the Partnership, and $22.0 million of interest for borrowings under our credit facility. Net income for 2006 reflects $88.0 million of allocated interest expense from Targa.
For the year ended December 31, 2007, gathering throughput was up 4.2% at 452.0 MMcf/d and plant natural gas inlet was up 2.3% at 429.2 MMcf/d, compared to 2006 throughput of 433.8MMcf/d and 419.6 MMcf/d respectively.
Gross NGL production of 42.6 MBbl/d for the year ended 2007 was slightly higher than the comparable 2006 production of 42.4 MBbl/d, primarily driven by additional well connections partially offset by the natural decline in field production. Natural gas sales of 410.2 BBtu/d for the year ended December 31, 2007 were down 19% from the 489.4 BBtu/d of natural gas sales during the same period 2006, primarily due to a decrease in purchases from affiliates and increases in take-in-kind volumes by producers, offset by a net increase in wellhead supply attributable to additional well connections. Finally, NGL and condensate sales for the year ended December 31, 2007 were up 1% at 36.4 MBbl/d and up 9% at 3.6 MBbl/d compared to 2006 levels of 36.0 MBbl/d and 3.3 MBbl/d respectively.
Average realized natural gas price decreased 2 cents per MMBtu from $6.68 per MMBtu for the twelve months ended December 31, 2006, to $6.66 per MMBtu for the twelve months ended December 31, 2007, including the impact of our hedging program. Average realized NGL prices were higher by 18 cents or 21% at $1.03 per gallon in 2007 and average realized condensate prices were $5.75 per barrel higher, or 10%, for 2007 at $65.62 per barrel, including the impacts of our hedging program.
Contract Mix, Hedges and Realized Prices
For the year ended December 31, 2007, approximately 79% of the Partnership's gathered volumes were processed under percent-of-proceeds contracts, 19% were wellhead purchases or keep-whole, with the remaining volumes processed under hybrid or fee based contract types comprising 1% each. Under percent-of-proceeds contracts, we receive a portion of the natural gas and/or NGLs as payment for our services. As a result, we are exposed to price risk on the portion of commodities that we receive as payment, which we refer to as our equity volumes. To mitigate the impact of commodity price fluctuations on our business, we enter into hedging contracts. Average realized prices are discussed above.
Capitalization
In conjunction with the Partnership's IPO, we entered into a five-year, $500 million senior secured revolving credit facility (the "Credit Facility"), and borrowed $294.5 million. Concurrent with the acquisition of the SAOU and LOU Systems on October 24, 2007, we entered into a Commitment Increase Supplement to the Credit Agreement, increasing our aggregate commitments under the Credit Agreement by $250 million to an aggregate total of $750 million. Furthermore, we entered into the First Amendment to Credit Agreement (the "Amendment"). The Amendment increased by $250 million the maximum amount of increases to the aggregate commitments that may be requested by us. The Amendment allows us to request commitments under the Credit Agreement, as supplemented and amended, up to $1 billion.
Total funded debt at December 31, 2007 was approximately $626.3 million, approximately 50.5% of total book capitalization. In the first quarter of 2008, the Partnership repaid $50.0 million under the Credit Facility, bringing total debt to $576.3 million.
Recent Activities
Activity continues to remain strong in all areas of operations, and total volumes continue to increase steadily. Additional recent activities include:
1. We continue to add significant acreage dedications in North
Texas and SAOU.
2. Work on several potential prospects to expand the gathering
footprint and bring additional processable gas to LOU and to
add take away capacity to North Texas is ongoing.
3. We have successfully executed or extended several key
industrial sales contracts in LOU.
4. Efforts toward securing long term options to optimize take away
capacity from the Chico plant which could serve as an alternative
to the capital project announced earlier are progressing.
5. Additionally, expansion of the Chico plant's CO2 amine treater
continues as expected to assist with increasing CO2 levels from
area production.
6. We achieved a record number of well connections in SAOU (131
connections in 2007 versus 123 in 2006) with continued strong
drilling activity.
7. Finally, the Partnership expects to commission a significant
butane storage project in LOU in the second quarter of 2008.
In addition, we are pursuing or evaluating multiple organic growth projects and expect capital expenditures to approximate $60 million in 2008.
Conference Call
Targa Resources Partners will host a conference call for investors and analysts at 10 a.m. ET (9 a.m. CT) on March 31, 2008 to discuss fourth quarter and year end 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 800-257-7063. The pass code is 11107692. 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 April 14, 2008.
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.
Use of Non-GAAP Financial Measures
This press release and accompanying schedules include non-GAAP financial measures of distributable cash flow 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, 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.
We compensate 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:
For the Year Ended December 31, 2007
---------------------------------------------
Post
Acquis-
Pre-Acquisition ition
-------------------------- ------
SAOU-LOU North Texas
Jan 1, 2007 Jan 1, 2007
to to
TRP LP Oct 23, 2007 Feb 13, 2007 TRP LP
------ ------------ ------------ ------
(in millions)
Reconciliation of
"Distributable Cash
Flow" to net income
Net income (loss) $ 40.3 $ 19.1 $ (6.9) $ 28.1
Depreciation and
amortization
expense 71.8 11.7 6.9 53.2
Deferred income tax
expense 1.5 -- -- 1.5
Amortization of debt
issue costs 1.8 0.9 -- 0.9
Loss/(gain) on
mark-to-market
derivative contracts 30.2 30.2 -- --
Maintenance capital
expenditures (21.5) (5.9) (1.5) (14.1)
------ ------ ------ ------
Distributable Cash
Flow $124.1 $ 56.0 $ (1.5) $ 69.6
====== ====== ====== ======
For the Three Months Ended
December 31, 2007
-----------------------------------
Post
Pre- Acquis-
Acquisition ition
-------------- ------
SAOU-LOU
Oct 1, 2007 to
TRP LP Oct 23, 2007 TRP LP
------ -------------- ------
(in millions)
Reconciliation of "Distributable
Cash Flow" to net income
Net income (loss) 22.7 $ 4.7 $18.0
Depreciation and amortization
expense 18.1 0.9 17.2
Deferred income tax expense 0.4 (0.1) 0.5
Amortization of debt issue
costs 0.4 -- 0.4
Loss/(gain) on mark-to-market
derivative contracts 1.9 1.9 --
Maintenance capital
expenditures (6.8) (0.4) (6.4)
----- ----- -----
Distributable Cash Flow $36.7 $ 7.0 $29.7
===== ===== =====
Adjusted EBITDA -- We define Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by our management and by external 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.
Three Three
Year Year Months Months
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2007 2006 2007 2006
------ ------ ------ ------
(in millions)
Reconciliation of "Adjusted
EBITDA" to net income:
Net income $ 40.3 $ 11.6 $ 22.7 $ (7.9)
Add:
Allocated interest expense,
net 19.4 88.0 0.4 22.5
Interest expense, net 22.0 -- 9.2 0.0
Deferred income tax expense 1.5 2.9 0.4 0.5
Depreciation and
amortization expense 71.8 69.9 18.1 18.1
Risk Management Activities 0.6 (1.5) (0.1) --
Noncash mark-to-market loss
(gain) 30.2 (16.8) 1.9 0.0
------ ------ ------ ------
Adjusted EBITDA $185.8 $154.1 $ 52.6 $ 33.2
====== ====== ====== ======
Reconciliation of "operating
margin" to net income:
Net income $ 40.3 $ 11.6 $ 22.7 $ (7.9)
Add:
Depreciation and
amortization expense 71.8 69.9 18.1 18.1
Deferred income tax expense 1.5 2.9 0.4 0.5
Allocated interest expense,
net 19.4 88.0 0.4 22.5
Interest expense, net 22.0 -- 9.2 0.0
Loss/(gain) on
mark-to-market derivative
contracts 30.2 (16.8) 1.9 0.0
General and administrative
expense 18.9 16.1 4.4 6.9
Gain on sale of assets (0.3) -- -- --
------ ------ ------ ------
Operating margin $203.8 $171.7 $ 57.1 $ 40.1
====== ====== ====== ======
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
December 31, December 31,
2007 2006
------------ ------------
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 50,994 $ --
Receivables from third parties 59,346 61,559
Receivables from affiliated companies 87,547 --
Inventory 1,624 958
Assets from risk management
activities 8,695 25,683
Other 269 --
------------ ------------
Total current assets 208,475 88,200
Property, plant and equipment, at cost 1,433,955 1,391,644
Accumulated depreciation (174,361) (103,073)
------------ ------------
Property, plant and equipment, net 1,259,594 1,288,571
Debt issue costs 6,588 --
Debt issue costs allocated from Parent -- 21,353
Long-term assets from risk management
activities 3,040 15,851
Other long-term assets 2,275 2,396
------------ ------------
Total assets $ 1,479,972 $ 1,416,371
============ ============
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable $ 5,693 $ 3,773
Accrued liabilities 142,836 109,337
Current maturities of debt allocated
from Parent -- 340,747
Liabilities from risk management
activities 44,003 3,296
------------ ------------
Total current liabilities 192,532 457,153
------------ ------------
Long-term debt allocated from Parent -- 706,597
Long-term debt 626,300 --
Long-term liabilities from risk
management activities 43,109 551
Other long-term liabilities 3,266 2,919
Deferred income tax liability 559 3,238
Commitments and contingencies (Note 13)
Partners' capital:
Common unitholders (34,636,000 units
issued and outstanding at
December 31, 2007) 770,207 --
Subordinated unitholders (11,528,231
units issued and outstanding at
December 31, 2007) (84,999) --
General partner (942,128 units issued
and outstanding at December, 2007) 4,234 --
Accumulated other comprehensive
income (loss) (75,236) 30,964
Net parent investment -- 214,949
------------ ------------
Total partners' capital 614,206 245,913
------------ ------------
Total liabilities and partners'
capital $ 1,479,972 $ 1,416,371
============ ============
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Three Three
Year Year Months Months
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2007 2006 2007 2006
---------- ---------- ---------- ----------
(in thousands, except per unit amounts)
Revenues from third
parties $ 630,773 $ 951,936 $ 166,447 $ 164,255
Revenues from
affiliates 1,030,696 786,589 307,588 195,424
---------- ---------- ---------- ----------
Total operating
revenues 1,661,469 1,738,525 474,035 359,679
Costs and expenses:
Product purchases
from third parties 1,215,733 1,194,751 351,622 257,310
Product purchases
from affiliates 191,064 322,917 51,214 49,194
Operating expenses 50,931 49,075 14,248 13,032
Depreciation and
amortization
expense 71,756 69,957 18,115 18,118
General and
administrative
expense 18,927 16,063 4,367 6,904
Other (296) -- 2 --
---------- ---------- ---------- ----------
1,548,115 1,652,763 439,568 344,558
---------- ---------- ---------- ----------
Income from
operations 113,354 85,762 34,467 15,121
Other expense:
Interest expense,
net 21,998 -- 9,159 --
Interest expense
allocated from
Parent 19,436 88,025 376 22,479
Loss/(gain) on
mark-to-market
derivative
contracts 30,221 (16,756) 1,852 15
Other (30) -- (13) --
---------- ---------- ---------- ----------
Income before income
taxes 41,729 14,493 23,093 (7,373)
Deferred income tax
expense 1,479 2,926 419 544
---------- ---------- ---------- ----------
Net income $ 40,250 $ 11,567 $ 22,674 $ (7,917)
========== ==========
Less net income
(loss) attributable
to predecessor
operations:
For the period
January 1, 2007 to
February 13, 2007
for North Texas (6,861)
For the period
January 1, 2007 to
October 23, 2007
for SAOU/LOU 19,045 4,670
---------- ----------
Total 12,184 4,670
---------- ----------
Net income allocable
to partners 28,066 18,004
General partner
interest in net
income for the period 561 360
---------- ----------
Net income available
to common and
subordinated
unitholders $ 27,505 $ 17,644
========== ==========
Basic net income per
common and
subordinated unit $ 0.81 $ 0.42
========== ==========
Diluted net income
per common and
subordinated unit $ 0.81 $ 0.42
========== ==========
Basic average number
of common and
subordinated units
outstanding 33,986 41,795
========== ==========
Diluted average
number of common and
subordinated units
outstanding 33,994 41,805
========== ==========
Note: Net income attributable to predecessor operations for three
months ended December 31, 2007 is for SAOU and LOU Systems for
period October 1, 2007 to October 23, 2007.
TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Year
Ended Ended
Dec. 31, Dec. 31,
2007 2006
---------- ----------
(In thousands)
Cash flows from operating activities
Net income $ 40,250 $ 11,567
Adjustments to reconcile net income
to net cash provided by operating
activities
Depreciation 71,632 69,832
Accretion of asset retirement
obligations 342 245
Amortization of intangibles 124 125
Amortization of debt issue costs 1,805 6,246
Noncash compensation 180 --
Gain on sale of assets (296) --
Deferred income tax expense 1,479 2,926
(Gain) loss on mark-to-market
derivative contracts 30,221 (16,756)
Risk management activities 530 (1,541)
Changes in operating assets and
liabilities: -- --
Accounts receivable 89,760 78,467
Inventory (666) 1,373
Other (273) 1,106
Accounts payable 1,920 (13,748)
Accrued liabilities 33,472 (15,408)
------------ ------------
Net cash provided by operating
activities 270,480 124,434
------------ ------------
Cash flows from investing activities
Purchases of property, plant and
equipment (41,088) (32,575)
Other 372 (317)
------------ ------------
Net cash used in investing
activities (40,716) (32,892)
------------ ------------
Cash flows from financing activities
Proceeds from equity offerings 777,471 --
Costs incurred in connection with
public offerings (4,640) --
Distributions to unit holders (31,221) --
Proceeds from borrowings under
credit facility 721,300 --
Costs incurred in connection with
financing arrangements (7,491) --
Repayments of loans: --
Affiliated (665,692) --
Credit facility (95,000) --
Distributions to Parent (873,497) (91,542)
------------ ------------
Net cash used in financing
activities (178,770) (91,542)
------------ ------------
Net change in cash and cash equivalents 50,994 --
------------ ------------
Cash and cash equivalents, beginning
of period -- --
------------ ------------
Cash and cash equivalents, end of
period $ 50,994 $ --
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