updated 2/24/2011 7:16:47 AM ET 2011-02-24T12:16:47

HOUSTON, Feb. 24, 2011 (GLOBE NEWSWIRE) -- Targa Resources Partners LP (NYSE:NGLS) ("Targa Resources Partners" or the "Partnership") and Targa Resources Corp. (NYSE:TRGP) ("TRC or the "Company") today reported fourth quarter and full year 2010 results. Fourth quarter 2010 net income attributable to Targa Resources Partners was $35.9 million while net income attributable to limited partners was $0.39 per diluted limited partner unit, compared to a net income of $25.4 million and net income attributable to limited partners of $0.52 per diluted limited partner unit for the fourth quarter of 2009. Net income for the fourth quarters of 2010 and 2009 included $10.2 million and $25.3 million in non-cash charges related to derivative instruments, respectively. The fourth quarter 2009 also included $16.6 million in affiliate and allocated interest expense for periods prior to the acquisitions of the Downstream Business, the Permian assets, Coastal Straddles, Versado and VESCO by the Partnership. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments ("Adjusted EBITDA") of $115.8 million for the fourth quarter of 2010 compared to $123.0 million for the fourth quarter of 2009.

For the full year 2010, net income attributable to Targa Resources Partners was $109.1 million and net income attributable to limited partners was $0.92 per diluted limited partner unit, compared to a net loss of $12.1 million and net income attributable to limited partners of $0.86 per diluted limited partner unit for 2009. Net income for the full year 2010 and 2009 included $6.4 million and $95.5 million in non-cash charges related to derivative instruments, respectively. The 2010 and 2009 full year also included $29.4 million and $107.7 million in affiliate and allocated interest expense, respectively, for periods prior to the acquisitions of the Downstream Business, the Permian assets, Coastal Straddles, Versado and VESCO by the Partnership. The Partnership reported "Adjusted EBITDA" of $396.1 million for the full year 2010 compared to $400.6 million for the full year of 2009.

Distributable cash flow for the fourth quarter of 2010 of $76.0 million corresponds to distribution coverage of approximately 1.4 times the $53.5 million in total distributions paid on February 14, 2011 (see the section of this release entitled "Targa Resources Partners - Non-GAAP Financial Measures" for a discussion of Adjusted EBITDA, gross margin, operating margin and distributable cash flow, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles ("GAAP").

"We are very pleased with our fourth quarter operating and financial results," said Rene Joyce, Chief Executive Officer of the Partnership's general partner and of Targa Resources Corp. "Our declared fourth quarter 2010 distribution rate represents an impressive 6% increase over the distribution rate for fourth quarter of 2009, an accomplishment largely a result of having purchased all of the remaining assets from TRC during the year at attractive prices and also a result of the strong performance of our businesses.

"We believe that with our scale and diversity in key producing oil and gas basins and in Mont Belvieu, Texas, a key hub for natural gas liquids logistics services, and with strong pro forma year end liquidity of approximately $900 million, the Partnership is well positioned to continue to capitalize on attractive growth opportunities. Looking forward to 2011, we are focused on successful execution of growth projects under construction in both divisions, completing new commercial and acquisition negotiations that are in process, and developing additional growth projects and acquisition opportunities."

On January 21, 2011, the Partnership announced a cash distribution for the fourth quarter of 2010 of 54.75¢ per common unit, or $2.19 per unit on an annualized basis. The cash distribution was paid on February 14, 2011 on all outstanding common units to holders of record as of the close of business on February 3, 2011. The total distribution paid was $53.5 million with $40.0 million paid to our public common unitholders and $6.4 million, $1.0 million and $6.0 million paid to TRC for its common unit ownership, general partner interests and incentive distribution rights.

Targa Resources Partners - Capitalization, Liquidity and Financing Update

Total funded debt at the Partnership as of December 31, 2010 was approximately $1,445.4 million including $765.3 million outstanding under the Partnership's $1.1 billion senior secured revolving credit facility, $209.1 million of 8¼% senior unsecured notes due 2016, $221.0 million of 11¼% senior unsecured notes due 2017 (the "11¼% Notes") and $250 million of 7⅞% senior unsecured notes due 2018.

On January 24, 2011, the Partnership completed a public offering of 8,000,000 common units representing limited partner interests in the Partnership, providing net proceeds of $259.3 million. Pursuant to the exercise of the underwriters' overallotment option on February 3, 2011, the Partnership sold an additional 1,200,000 common units, providing net proceeds of approximately $38.9 million. In addition, the general partner contributed $6.3 million for 187,755 general partner units to maintain its 2% interest. The net proceeds from the offering were used to reduce borrowings under the Partnership's senior secured credit facility.

On February 2, 2011, the Partnership closed on a private placement of $325 million in aggregate principal amount of 6⅞% Senior Notes due 2021 ("the 6⅞% Notes") resulting in net proceeds of $319.3 million.

On February 4, 2011 the Partnership exchanged $158.6 million principal amount of 11¼% Notes for $158.6 million principal amount of 6⅞% Notes in a private exchange offer to certain eligible holders of the 11¼% Notes. In conjunction with the exchange the Partnership paid a premium in cash of $28.6 million. The debt covenants related to the remaining $72.7 million of face value 11¼% Notes due 2017 were removed as the Partnership received sufficient consents in connection with the exchange offer to amend the indenture. With the exchange offer, the total principal outstanding of the 6⅞% Senior Notes due 2021 is $483.6 million.

Pro forma for the completion of the unit offering, note offering and exchange, the Partnership had available revolver capacity of $828.6 million, after giving effect to $101.3 million in outstanding letters of credit, and $76.3 million of cash resulting in total liquidity of $904.9 million at December 31, 2010.

The Partnership expects 2011 net capital expenditures to approximate $230 million with maintenance capital expenditures accounting for approximately 25% of the total. In addition, the Partnership estimates that it will invest approximately $20 million in 2011 for its pro rata share of the Gulf Coast Fractionators expansion.

Targa Resources Corp. - Fourth Quarter 2010 Financial Results

Targa Resources Corp., the parent of Targa Resources Partners LP, today reported its fourth quarter and full year 2010 results. The Company, which at December 31, 2010 owned a 2.0% general partner interest (held through its 100% ownership interest in the general partner of the Partnership), all of the incentive distribution rights ("IDRs") and 11,645,659 common units of the Partnership, presents its results consolidated with those of the Partnership.

The Company reported a net loss attributable to the Company of $7.8 million and $15 million for its fourth quarter and full year 2010, respectively, compared with a net income of $16.3 million and $29.3 million for its fourth quarter and full year 2009. The fourth quarter 2010 includes approximately $20 million that reflect increased professional services and special compensation expense related to Targa Resources Corp.'s December IPO.

Total fourth quarter 2010 distributions paid in the first quarter on February 14, 2011 by the Partnership to the Company totaled approximately $13.4 million with $6.4 million, $1.0 million and $6.0 million paid with respect to common unit ownership, general partner interests and incentive distribution rights, respectively. TRC's total distributions received with respect to the fourth quarter of 2010 were approximately 14% higher than those received for the third quarter of 2010.

On January 21, 2011, the Company declared a quarterly cash dividend of 6.16¢ per common share, or $1.03 per common share on an annualized basis, representing a prorated dividend for the portion of the fourth quarter of 2010 that the Company was public. Total cash dividends of approximately $2.6 million were paid February 21, 2011 on all outstanding common shares to holders of record as of the close of business on February 3, 2011.

Targa Resources Corp. - Capitalization, Liquidity and Financing Update

Total funded debt of the Company as of December 31, 2010, excluding debt of the Partnership, was $89.3 million. The Company also has access to the full amount of a $75 million senior secured revolving credit facility due 2014.

The Company's cash balance, excluding cash held at the Partnership and the Partnership's subsidiaries, was approximately $112 million as of December 31, 2010.

On December 6, 2010 the Company priced its initial public offering of 18,831,250 shares of its common stock at $22.00 per share, including 2,456,250 shares from the exercise in full of the underwriters over-allotment option. As of December 31, 2010 there were 42,292,348 common shares outstanding.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a conference call for investors and analysts at 10:30 a.m. Eastern Time (9:30 a.m. Central Time) on February 24, 2011 to discuss fourth quarter and full year 2010 financial results. The conference call can be accessed via Webcast through the Events and Presentations section of the Partnership's website at www.targaresources.com , by going directly to http://ir.targaresources.com/events.cfm?company=LP or by dialing 877-881-2598. The pass code for the dial-in is 43705187. 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. Telephone replay access numbers are 800-642-1687 or 706-645-9291 with pass code 43705187 and will remain available, along with the Webcast, until March 10, 2011.

Targa Resources Partners - Consolidated Financial Results of Operation

With the closing of the acquisitions of the Downstream Business in 2009, the Permian assets, Coastal Straddles, Versado and VESCO in 2010, and in accordance with the accounting treatment for entities under common control, the results of operations of the Partnership include the historical results of the Downstream Business, Permian assets, Coastal Straddles, Versado and VESCO for all periods presented.

  Three Months Ended Year Ended
  December 31, December 31,
   2010   2009   2010   2009 
  (In millions, except per unit data)
Revenues (1)  $ 1,521.9  $ 1,383.2  $ 5,460.2  $ 4,503.8
Product purchases   1,300.3  1,168.3  4,688.0  3,792.9
Gross margin   221.6  214.9  772.2  710.9
Operating expenses  69.3  52.3  259.5  234.4
Operating margin  152.3  162.6  512.7  476.5
Depreciation and amortization expense  47.9  41.7  176.2  166.7
General and administrative expense  42.4  36.6  122.4  118.5
Other  (3.3)  0.2  (3.3)  (3.6)
Income from operations  65.3  84.1  217.4  194.9
Other income (expense):        
Interest expense, net  (25.0)  (33.5)  (110.8)  (159.8)
Equity in earnings of unconsolidated investment  1.6  1.8  5.4  5.0
Gain (loss) on debt repurchases  --   (1.5)  --   (1.5)
Gain (loss) on mark-to-market derivative instruments  --   (18.8)  26.0  (30.9)
Other  0.8  1.0  --   0.7
Income tax expense  (0.1)  (0.3)  (4.0)  (1.2)
Net income   42.6  32.8  134.0  7.2
Less: Net income attributable to noncontrolling interest  6.7  7.4  24.9  19.3
Net income attributable to Targa Resources Partners LP  $ 35.9  $ 25.4  $ 109.1  $ (12.1)
         
Net income (loss) attributable to predecessor operations  $ --   $ (10.6)  $ 25.8  $ (66.7)
Net income attributable to general partner  6.1  3.7  18.1  10.4
Net income attributable to limited partners  29.8  32.3  65.2  44.2
Net income attributable to Targa Resources Partners LP  $ 35.9  $ 25.4  $ 109.1  $ (12.1)
         
Basic and diluted net income per limited partner unit  $ 0.39  $ 0.52  $ 0.92  $ 0.86
         
Financial data:        
Adjusted EBITDA (2)  $ 115.8  $ 123.0  $ 396.1  $ 400.6
Distributable cash flow (3)  76.0  96.4  276.0  312.2
         
(1) Includes business interruption insurance revenues of $7.3 million and $13.3 million for the three months and year ended December 31, 2009 recognized in periods prior to the conveyances of assets to the Partnership from the Company. These conveyances were accounted for under common control accounting. There were no business interruption proceeds received by the Partnership in 2010, as these amounts were retained by the Company under the terms of the applicable purchase and sale agreements.
(2) Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash gain or loss related to derivative instruments. 
(3) Distributable cash flow is net income attributable to Targa Resources Partners plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for losses/(gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures.  

Targa Resources Partners - Review of Consolidated Fourth Quarter Results

Three Months Ended December 31, 2010 Compared to Three Months Ended December 31, 2009

Revenue increased $138.7 million due to higher commodity prices ($101.2 million) and higher natural gas and NGL sales volumes ($51.0 million) offset by lower condensate sales volumes ($8.1 million) and lower fee-based and other revenues ($5.4 million). 

The $6.7 million increase in gross margin reflects higher revenue of $138.7 million offset by higher product purchase costs of $132.0 million.

For additional information regarding the period to period changes in gross margin, see "Targa Resources Partners - Review of Segment Performance"

The $17.0 million increase in operating expenses was primarily due to increased compensation and benefit costs, increased non-capitalized maintenance costs, and higher professional services fees.

The increase in depreciation and amortization expense is primarily attributable to an impairment taken on an asset in the fourth quarter of 2010 as well as incremental depreciation on capital expenditures in 2010.

The increase in general and administrative expense reflects primarily higher compensation costs and higher professional fees.

The decrease in interest expense was primarily due to lower interest rates on third party debt than on affiliate debt associated with predecessor operations.

Targa Resources Partners - Review of Consolidated Full Year Results

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Revenues increased $956.4 million due to higher realized commodity prices of $1,221.9 million, lower NGL and condensate sales volumes of $364.1 million, partially offset by higher natural gas sales volumes of $117.4 million, lower fee-based and other revenues of $5.5 million, and lower business interruption insurance proceeds of $13.3 million.

The increase in gross margin reflects higher revenue of $956.4 million partially offset by an increase in product purchase costs of $895.1 million. For information regarding period to period changes in gross margin, see "Targa Resources Partners - Review of Segment Performance".

The increase in operating expenses of $25.1 million was primarily due to increased compensation and benefits expenses, increased maintenance costs and environmental spending, partially offset by lower contract services and professional fees. See "Targa Resources Partners – Review of Segment Performance" for additional discussion regarding changes in operating expenses.

The increase in depreciation and amortization expenses of $9.5 million was primarily attributable to assets acquired in 2009 that had a full year period of depreciation in 2010, and incremental depreciation on capital expenditures of $143.6 million that occurred during 2010.

General and administrative expenses increased $3.9 million reflecting outside services expenses.   

The $49.0 million decrease in interest expense was primarily due to an overall reduction in long-term debt of $379.6 million and lower interest rates on existing debt.

The gain on mark-to-market derivative instruments for 2010 compared to a loss for 2009 was primarily due to the treatment of commodity hedges related to the Permian assets and Versado that were allocated to the Partnership through common control accounting. These allocated hedges did not qualify for hedge accounting prior to the Partnership's acquisition of the underlying assets and therefore the change in fair value of these instruments was recorded in earnings using the mark-to-market method. The use of mark-to-market accounting caused non-cash earnings volatility due to changes in the underlying commodity price indices. During 2010, the Partnership recorded mark-to-market gain, compared to 2009, when the Partnership recorded mark-to-market loss due to these changes in commodity price indices.

Targa Resources Partners - Review of Segment Performance

The following discussion of segment performance includes inter-segment revenues. The Partnership views segment operating margin as an important performance measure of the core profitability of its operations. This measure is a key component of internal financial reporting and is reviewed for consistency and trend analysis. For a discussion of operating margin, see "Targa Resources Partners -- Non-GAAP Financial Measures -- Operating Margin." Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation. For all operating statistics presented, the numerator is the total volume or sales for the period and the denominator is the number of calendar days for the period.

In connection with the April 2010 acquisition of the Company's interest in the Permian assets and Coastal Straddles and its impact on the Partnership's structure used for internal management purposes, an updated evaluation of the Partnership's reportable segments was performed during the second quarter of 2010. As a result, the Partnership's operations are now presented under four reportable segments: (1) Field Gathering and Processing, (2) Coastal Gathering and Processing, (3) Logistics Assets and (4) Marketing and Distribution.

Field Gathering and Processing Segment

The Field Gathering and Processing segment gathers and processes natural gas from the Permian Basin in West Texas and Southeast New Mexico, and the Fort Worth Basin, including the Barnett Shale, in North Texas. The segment's processing plants include nine owned and operated facilities.

The following table provides summary data regarding results of operations of this segment for the periods indicated:

   Three Months Ended

December 31, 
 Year Ended

December 31, 
   2010   2009   2010   2009 
   ($ in millions) 
Gross margin  $ 88.4  $ 81.2  $ 338.8  $ 268.3
Operating expenses  (28.6)  (21.4)  (102.2)  (85.1)
Operating margin  $ 59.8  $ 59.8  $ 236.6  $ 183.2
         
Operating statistics:        
Plant natural gas inlet, MMcf/d        
Permian  133.9  119.1  128.7  118.2
SAOU  107.2  89.7  99.8  91.5
North Texas System  189.9  165.7  180.4  173.6
Versado  173.6  196.6  178.8  198.6
   604.6  571.1  587.7  581.9
         
Gross NGL production, MBbl/d        
Permian  15.5  13.7  14.8  13.4
SAOU  16.2  13.8  15.3  14.1
North Texas System  21.7  19.3  20.7  20.1
Versado  20.6  22.0  20.4  22.2
   74.0  68.8  71.2  69.8
         
Natural gas sales, BBtu/d (1)  262.7  238.8  258.6  219.6
NGL sales, MBbl/d (1)  59.4  58.7  56.6  56.2
Condensate sales, MBbl/d (1)  2.6  2.6  2.9  3.2
Average realized prices (2):        
Natural gas, $/MMBtu  3.54  4.00  4.11  3.69
NGL, $/gal  1.00  0.87  0.93  0.69
Condensate, $/Bbl  81.18  73.23  75.48  55.84
 
(1) Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the applicable period.
(2) Average realized prices do not include the impact of hedging activities.

Three Months Ended December 31, 2010 Compared to Three Months Ended December 31, 2009

The $7.2 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices ($22.2 million), an increase in natural gas and NGL sales volumes ($11.3 million) and fee-based and other revenues ($2.1 million) partially offset by a decrease in condensate revenue ($0.1 million) and increased commodity purchase costs ($28.3 million). The increased volumes were largely attributable to new well connects at North Texas, SAOU, and Permian assets, partially offset by production declines caused by unplanned downtime due to a water tank rupture in the third quarter at Versado's Eunice plant.

The $7.2 million increase in operating expenses for 2010 compared to 2009 was primarily due to increases in system maintenance expenses, primarily attributable to increased system volumes and unplanned repairs at the Eunice plant.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The $70.5 million increase in gross margin for 2010 was primarily due to higher commodity sales price ($303.9 million), higher natural gas and NGL sales volumes ($22.6 million) and higher fee based and other revenue of $4.5 million offset by lower condensate sales volumes ($6.8 million) and higher product purchases of $253.6 million. The increased natural gas and NGL sales volumes were due primarily to higher natural gas and NGL production.

The increase in operating expenses was primarily due to higher system maintenance expenses ($8.2 million), higher compensation and benefit costs ($4.7 million) and higher contract and professional service expenses ($2.0 million).

Coastal Gathering and Processing Segment

The Coastal Gathering and Processing segment assets are located in the onshore region of the Louisiana Gulf Coast and the Gulf of Mexico. With the strategic location of the Partnership's assets in Louisiana, it has access to the Henry Hub, the largest natural gas hub in the U.S., and a substantial NGL distribution system with access to markets throughout Louisiana and the southeast U.S.

The following table provides summary data regarding results of operations of this segment for the periods indicated:

   Three Months Ended

December 31, 
 Year Ended

December 31, 
   2010   2009   2010   2009 
   ($ in millions, except price data) 
Gross margin  $ 44.9  $ 45.0  $ 151.2  $ 132.7
Operating expenses  (12.0)  (8.1)  (43.4)  (43.0)
Operating margin  $ 32.9  $ 36.9  $ 107.8  $ 89.7
         
Operating statistics:        
Plant natural gas inlet, MMcf/d (2)      
LOU  166.9  200.5  184.6  180.8
Coastal Straddles  972.6  1,105.5  1,068.4  1,014.0
VESCO  439.3  387.6  427.3  363.0
   1,578.8  1,693.6  1,680.3  1,557.8
         
Gross NGL production, MBbl/d        
LOU  6.5  8.4  7.2  8.5
Coastal Straddles  18.2  20.8  19.7  17.2
VESCO  23.9  23.8  23.2  22.8
   48.6  53.0  50.1  48.5
         
Natural gas sales, BBtu/d (1)  258.8  285.9  293.6  258.4
Condensate sales, MBbl/d (1)  0.1  1.8  0.5  1.6
Average realized prices:        
Natural gas, $/MMBtu  3.91  4.29  4.48  4.00
NGL, $/gal  1.13  0.98  1.03  0.77
Condensate, $/Bbl  83.65  47.30  78.82  53.31
         
(1) Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the applicable period and the denominator is the number of calendar days during the applicable period.
(2) The majority of the Coastal Straddles plant volumes are gathered on third party offshore pipeline systems and delivered to the plant inlets.

Three Months Ended December 31, 2010 Compared to Three Months Ended December 31, 2009

Gross margin for 2010 was flat when compared to 2009 due to an increase in commodity sales prices ($13.6 million) and decreases in product purchase costs ($13.5 million), offset by a decrease in commodity sales volumes ($21.5 million) and fee-based and other revenues ($5.6 million). Natural gas sales volumes decreased due to decreased sales to affiliates and to the Partnership's industrial customers. NGL sales volumes decreased primarily due to reduced plant inlet volumes resulting from a decline in traditional wellhead and offshore supply volumes. 

The $3.9 million increase in operating expenses for 2010 was primarily due to higher system maintenance expenses.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The $18.5 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices ($230.3 million) and an increase in natural gas and NGL sales volumes ($88.3 million) partially offset by decreases in condensate sales volumes ($21.8 million) and fee-based and other revenues ($11.3 million) and an increase in commodity sales purchases ($266.8 million). Natural gas sales volumes increased due to increased sales to affiliates for resale partially offset by a small decrease in demand from our industrial customers. NGL sales volumes increased primarily due to the straddle plants recovering operations in the first two quarters of 2010 after Hurricanes Gustav and Ike disrupted operations in 2008.

Logistics Assets Segment

The Logistics Assets Segment uses its platform of integrated assets to fractionate, store, treat and transport typically under fee-based and margin-based arrangements. For NGLs to be used by refineries, petrochemical manufacturers, propane distributors and other industrial end-users, they must be fractionated into their component products and delivered to various points throughout the U.S. The Partnership's logistics assets are generally connected to and supplied, in part, by its Natural Gas Gathering and Processing assets and are primarily located at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana.

The following table provides summary data regarding results of operations of this segment for the periods indicated:

   Three Months Ended

December 31, 
 Year Ended

December 31, 
   2010   2009   2010   2009 
   ($ in millions, except price data) 
Gross margin  $ 50.8  $ 46.3  $ 172.3  $ 156.2
Operating expenses  (19.9)  (19.5)  (88.5)  (81.9)
Operating margin  $ 30.9  $ 26.8  $ 83.8  $ 74.3
         
Operating statistics:         
Fractionation volumes, MBbl/d  243.9  222.8  230.8  217.2
Treating volumes, MBbl/d  18.8  32.0  18.0  21.9

Three Months Ended December 31, 2010 Compared to Three Months Ended December 31, 2009

The $ 4.5 million improvement in gross margin was primarily due to increased fractionation volumes and fees.

The $0.4 million increase in operating expenses was primarily due to higher maintenance activities partially offset by a well emptying gain at the Cedar Bayou Fractionator.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The $16.1 million increase in gross margin reflects higher fractionation and treating fees ($20.4 million) higher terminalling and storage revenue ($2.6 million), offset by lower fee-based and other revenues ($6.9 million). The increase in fractionation volumes is as result of the capacity in the Partnership's fractionating facilities being at or near capacity. The Partnership is expanding our fractionating capacity at the Cedar Bayou and Gulf Coast Fractionating plants to meet increased market demand.

The $6.6 million increase in operating expenses was primarily due to higher compensation costs ($5.0 million) and higher general maintenance supplies ($3.0 million).

Marketing and Distribution Segment

The Marketing and Distribution segment transports, distributes and markets NGLs via terminals and transportation assets across the U.S. The Partnership owns or commercially manages terminal facilities in a number of states, including Texas, Louisiana, Arizona, Nevada, California, Florida, Alabama, Mississippi, Tennessee, Kentucky and New Jersey. The geographic diversity of the Partnership's assets provides direct access to many NGL customers as well as markets via trucks, barges, rail cars and open-access regulated NGL pipelines owned by third parties. The Marketing and Distribution segment consists of (i) NGL Distribution and Marketing, (ii) Wholesale Marketing, (iii) Refinery Services, (iv) Commercial Transportation and (v) Natural Gas Marketing.

The following table provides summary data regarding results of operations of this segment for the periods indicated:

   Three Months Ended

December 31, 
 Year Ended

December 31, 
   2010   2009   2010   2009 
   ($ in millions, except price data) 
Gross margin  $ 43.1  $ 39.4  $ 125.4  $ 128.9
Operating expenses  (11.4)  (10.0)  (44.9)  (45.9)
Operating margin  $ 31.7  $ 29.4  $ 80.5  $ 83.0
         
Operating statistics:         
Natural gas sales, BBtu/d  649.3  547.7  634.9  510.3
NGL sales, MBbl/d  262.5  260.2  246.7  276.1
Natural gas realized price, $/gal  3.76  4.19  4.31  3.65
NGL realized price, $/gal  1.21  1.05  1.10  0.80

Three Months Ended December 31, 2010 Compared to Three Months Ended December 31, 2009

The $3.7 million increase in gross margin reflects the impact of higher commodity prices on revenues and increased natural gas and NGL sales volumes, offset by increased product purchases.

Natural gas sales volumes are higher due to increased purchases for resale. NGL sales volumes are higher due primarily to increased spot sales to third party customers.

The increase in operating expense was primarily attributable to higher compensation and benefit expense and higher contract labor expense.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The $3.5 million decrease in gross margin was due to increased commodity prices of $1,287.9 million and higher natural gas volumes of $166.2 million offset by lower NGL volumes of $359.8 million, lower fee-based and other revenues of $20.4 million, and increased product purchases of $1,077.2 million. Lower 2010 margins at inventory locations were primarily due to the 2009 impact of higher margins on forward sales agreements that were fixed at relatively high 2008 prices, along with spot fractionation volumes and associated fees. These items were partially offset by higher marketing fees on contract purchase volumes due to overall higher 2010 market prices. Margin on transportation activity decreased due to expiration of a barge contract partially offset by increased truck activity.

Natural gas sales volumes are higher due to increased purchases for resale. NGL sales volumes are lower due to a change in contract terms with a petrochemical supplier that had a minimal impact to gross margin.

Operating expenses were essentially flat.

Other

Other includes the impact on operating margin of the Partnership's derivatives hedging activities.

Three Months Ended December 31, 2010 Compared to Three Months Ended December 31, 2009

The Partnership's cash flow hedging program decreased gross margin by $12.7 million during 2010 versus 2009, due to higher commodity prices which resulted in lower revenues from settlements on derivative contracts, as well as the impact of lower volumes hedged.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The Partnership's cash flow hedging program decreased gross margin by $42.3 million during 2010 versus 2009, due to higher commodity prices which resulted in lower revenues from settlements on derivative contracts, as well as the impact of lower volumes hedged.

About Targa Resources Partners and Targa Resources Corp.

Targa Resources Corp. owns a 2% general partner interest (which the Company holds through its 100% ownership interest in the general partner of the Partnership), all of the outstanding incentive distribution rights ("IDRs") and a portion of the outstanding limited partner interests in Targa Resources Partners LP.

Targa Resources Partners is a publicly traded Delaware limited partnership that is a leading provider of midstream natural gas and natural gas liquid services in the United States. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas and storing, fractionating, treating, transporting and selling natural gas liquids, or NGLs, and NGL products. The Partnership owns an extensive network of integrated gathering pipelines and gas processing plants and currently operates along the Louisiana Gulf Coast primarily accessing the offshore region of Louisiana, the Permian Basin in West Texas and Southeast New Mexico and the Fort Worth Basin in North Texas. Additionally, the Partnership's natural gas liquids logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana with terminals and transportation assets across the United States. Targa Resources Partners is managed by its general partner, Targa Resources GP LLC, which is indirectly wholly owned by Targa Resources Corp.

The principal executive offices of Targa Resources Corp. and Targa Resources Partners are located at 1000 Louisiana, Suite 4300, Houston, TX 77002 and its telephone number is 713-584-1000. For more information please go to www.targaresources.com

Targa Resources Partners - Non-GAAP Financial Measures

This press release includes the non-GAAP financial measures Adjusted EBITDA, gross margin, operating margin and distributable cash flow. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. 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 -- The Partnership defines distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for losses/(gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures. Distributable cash flow is a significant performance metric used by the Partnership and by external users of its financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by the Partnership (prior to the establishment of any retained cash reserves by the board of directors of the Partnership's general partner) to the cash distributions it expects to pay its 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 financial measure for the Partnership's unitholders since it serves as an indicator of the Partnership's success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Partnership is generating cash flow at a level that can sustain or support an increase in its 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 the Partnership's use of distributable cash flow is to measure the ability of its assets to generate cash flow sufficient to make distributions to its investors. The GAAP measure most directly comparable to distributable cash flow is net income. Distributable cash flow should not be considered as an alternative to GAAP net income. 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 the Partnership's results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in the Partnership's industry, the Partnership's 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 insights into its decision making processes.

The following table presents a reconciliation of net income to distributable cash flow for the periods indicated:

  Three Months Ended

December 31,
Year Ended

December 31,
  2010 2009 2010 2009
  ($ in millions)
Reconciliation of net income (loss) to Targa Resources        
Partners LP to distributable cash flow:        
Net income attributable to Targa Resources Partners LP  $ 35.9  $ 25.4  $ 109.1  $ (12.1)
Add:        
Allocated and affiliate interest expense  --   16.6  $ 29.4  $ 107.7
Depreciation and amortization expense  47.9  41.7  176.2  166.7
Deferred income tax expense   0.9  --   1.2  0.9
Amortization of debt issue costs  3.0  0.1  6.6  3.9
Extinguishment of debt issue costs  (0.8)  1.1  --   1.5
 Risk management activities  10.2  25.3  6.4  95.5
Maintenance capital expenditures  (22.0)  (11.1)  (50.5)  (44.5)
Reimbursements        
Other (1)  0.9  (2.7)  (2.4)  (7.4)
Distributable cash flow  $ 76.0  $ 96.4  $ 276.0  $ 312.2
 
(1)  Other includes reimbursements of certain environmental maintenance capital expenditures by Targa and the noncontrolling interest percentage of our unconsolidated investment's depreciation, interest expense and maintenance capital expenditures.  

Adjusted EBITDA -- The Partnership defines 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 management and by external users of the Partnership's financial statements such as investors, commercial banks and others, to assess: (1) the financial performance of the Partnership's assets without regard to financing methods, capital structure or historical cost basis; (2) the Partnership's operating performance and return on capital 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 the Partnership's assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to unitholders. The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income attributable to Targa Resources Partners. The Partnership's non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and 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 the Partnership's results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in the Partnership's industry, the Partnership's 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 its decision-making processes.

  Three Months Ended

December 31,
Year Ended

December 31,
  2010 2009 2010 2009
  ($ in millions)
 

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
       
Net cash provided by operating activities   $ 131.2  $ 119.3  $ 371.2  $ 422.9
Net income attributable to noncontrolling interest  (6.7)  (7.4)  (24.9)  (19.3)
Interest expense, net (1)  22.0  13.4  74.8  44.8
Gain (loss) on debt repurchases  --   (1.5)  --   (1.5)
Termination of commodity derivatives  --   --   --   -- 
Current income tax expense  (0.8)  0.3  2.8  0.3
Other (2)  (4.6)  1.5  (14.7)  (10.6)
Changes in operating working capital which used (provided) cash:        
Accounts receivable and other assets  111.5  74.6  71.2  57.0
Accounts payable and other liabilities  (136.8)  (77.2)  (84.3)  (93.0)
Adjusted EBITDA   $ 115.8  $ 123.0  $ 396.1  $ 400.6
 
(1) Net of amortization of debt issuance costs of $3.0 million and $6.6 million for the three months and year ended December 31, 2010 and $0.1 million and $3.9 million for the three months and year ended December 31, 2009. Also net of amortization of discount and premium included in interest expense of less than $0.01 million for 2010 and $1.1 million and $3.4 million for the three months and year ended December 31, 2009. Excludes affiliate and allocated interest expense.
(2) Includes non-controlling interest percentage of the Partnership's unconsolidated investment's depreciation, interest expense and maintenance capital expenditures, equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock based compensation and gain (loss) on sale of assets.
     
  Three Months Ended

December 31,
Year Ended

December 31,
  2010 2009 2010 2009
  ($ in millions)
Reconciliation of net income (loss) attributable to Targa Resources Partners

LP to Adjusted EBITDA:
       
Net income (loss) to Targa Resources Partners LP  $ 35.9  $ 25.4  $ 109.1  $ (12.1)
Add:        
Interest expense, net (1)  25.0  33.5  110.8  159.8
Income tax expense  0.1  0.3  4.0  1.2
Depreciation and amortization expense   47.9  41.7  176.2  166.7
Risk management activities  10.2  25.3  6.4  95.5
Noncontrolling interest adjustment  (3.3)  (3.2)  (10.4)  (10.5)
Adjusted EBITDA   $ 115.8  $ 123.0  $ 396.1  $ 400.6
 
(1) Includes affiliate and allocated interest expense  

Gross Margin. With respect to the Partnership's Natural Gas Gathering and Processing segments, the Partnership defines gross 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. With respect to the Partnership's Logistics Assets segment, it defines gross margin as total revenues, which consists primarily of service fee revenues. With respect to the Partnership's Marketing and Distribution segment, it defines gross margin as total revenues, which consists primarily of service fee revenues and NGL sales, less cost of sales, which consists primarily of NGL purchases and changes in inventory valuation.

Operating Margin. With respect to the Partnership's Natural Gas Gathering and Processing segments, its Logistics Assets segment and its Marketing and Distribution segment, the Partnership defines operating margin as gross margin less operating expenses.

The GAAP measure most directly comparable to gross margin and operating margin is net income. The Partnership's non-GAAP financial measures of gross margin and operating margin should not be considered as alternatives to GAAP net income. Gross Margin and operating margin are not presentations made in accordance with GAAP and have important limitations as analytical tools. You should not consider gross margin and operating margin in isolation or as substitutes for analysis of the Partnership's results as reported under GAAP. Because gross margin and operating margin excludes some, but not all, items that affect net income and are defined differently by different companies, the Partnership's definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into its decision-making processes. Management reviews gross margin and 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 gross margin and operating margin as important performance measures of the core profitability of the Partnership's operations.

  Three Months Ended

December 31,
Year Ended

December 31,
  2010 2009 2010 2009
  ($ in millions)
Reconciliation of gross margin and operating margin to net income (loss):        
Gross margin  $ 221.6  $ 214.9  $ 772.2  $ 710.9
Operating expenses  (69.3)  (52.3)  (259.5)  (234.4)
Operating margin   152.3  162.6  512.7  476.5
Depreciation and amortization expenses  (47.9)  (41.7)  (176.2)  (166.7)
General and administrative expenses  (39.1)  (36.8)  (119.1)  (114.9)
Interest expense, net  (25.0)  (33.5)  (110.8)  (159.8)
Income tax (benefit) expense  (0.1)  (0.3)  (4.0)  (1.2)
Gain (loss) on debt repurchases  0.8  --   --   (1.5)
Risk management activities  --   (18.8)  26.0  (30.9)
Equity in earnings of unconsolidated investments  1.6  1.8  5.4  5.0
Other, net  --   (0.5)  --   0.7
Net income  $ 42.6  $ 32.8  $ 134.0  $ 7.2

Forward-Looking Statements

Certain statements in this release are "forward-looking statements". All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Partnership and the Company expect, believe or anticipate 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 the Partnership's and the Company's control, which could cause results to differ materially from those expected by management of the Partnership and the Company. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas and natural gas liquids, the timing and success of business development efforts; and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Partnership's and the Company's filings with the Securities and Exchange Commission, including their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. Neither the Partnership nor the Company undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

CONSOLIDATED BALANCE SHEET DATA
(In millions) December 31, December 31,
  2010 2009
ASSETS
Current assets:    
Cash and cash equivalents  $ 76.3  $ 90.9
Trade receivables  466.1  405.5
Inventory  50.3  39.3
Assets from risk management activities  25.2  32.9
Other current assets  2.9  1.9
Total current assets  620.8  570.5
Property, plant and equipment, net  2,495.2  2,526.6
Long-term assets from risk management activities  18.9  13.8
Other assets  51.5  41.8
Total assets  $ 3,186.4  $ 3,152.7
LIABILITIES AND PARTNERS' CAPITAL    
Current liabilities:    
Accounts payable and accrued liabilities  $ 575.6  $ 474.8
Liabilities from risk management activities  34.2  29.2
Total current liabilities  609.8  504.0
Long-term debt payable to third parties  1,445.4  908.4
Long-term debt allocated from Targa Resources Corp.  --   151.8
Long-term debt payable to Targa Resources Corp.  --   764.8
Long term liabilities from risk management activities  32.8  43.8
Other long-term liabilities  49.3  51.6
Total liabilities  2,137.3  2,424.4
Owner's equity:     
Targa Resources Partners LP owner's equity  919.8  604.8
Noncontrolling interest in subsidiary  129.3  123.5
Total owners' equity  1,049.1  728.3
Total liabilities and owners' equity  $ 3,186.4  $ 3,152.7
         
         
CONSOLIDATED STATEMENTS OF OPERATIONS        
(In millions, except per unit data)        
  Three Months Ended Year Ended
  December 31, December 31,
  2010 2009 2010 2009
REVENUES  $ 1,521.9  $ 1,383.2  $ 5,460.2  $ 4,503.8
Product purchases  1,300.3  1,168.3  4,688.0  3,792.9
Operating expenses  69.3  52.3  259.5  234.4
Depreciation and amortization expense  47.9  41.7  176.2  166.7
General and administrative expense  42.4  36.6  122.4  118.5
Other  (3.3)  0.2  (3.3)  (3.6)
Total costs and expenses  1,456.6  1,299.1  5,242.8  4,308.9
INCOME FROM OPERATIONS  65.3  84.1  217.4  194.9
Other income (expense):        
Interest expense from affiliate  --   (13.5)  (23.8)  (97.7)
Interest expense allocated from Parent  --   (3.1)  (5.6)  (10.0)
Other interest expense, net  (25.0)  (16.9)  (81.4)  (52.1)
Equity in earnings of unconsolidated investments  1.6  1.8  5.4  5.0
Gain (loss) on debt repurchases  --   (1.5)  --   (1.5)
Gain (loss) on mark-to-market derivative instruments  --   (18.8)  26.0  (30.9)
Other income (expense)  0.8  1.0  --   0.7
Income (loss) before income taxes  42.7  33.1  138.0  8.4
Income tax (expense) benefit  (0.1)  (0.3)  (4.0)  (1.2)
NET INCOME   42.6  32.8  134.0  7.2
Less: Net income to noncontrolling interest  6.7  7.4  24.9  19.3
NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP  $ 35.9  $ 25.4  $ 109.1  $ (12.1)
         
Net loss attributable to predecessor operations  $ --   $ (10.6)  $ 25.8  $ (66.7)
Net income attributable to general partner  6.1  3.7  18.1  10.4
Net income attributable to limited partners  29.8  32.3  65.2  44.2
Net income attributable to Targa Resources Partners LP  $ 35.9  $ 25.4  $ 109.1  $ (12.1)
         
Basic and diluted net income per limited partner unit  $ 0.39  $ 0.52  $ 0.92  $ 0.86
         
Basic and diluted weighted average limited  partner units outstanding  75.5  61.6  70.8  51.2
         
         
CONSOLIDATED CASH FLOW INFORMATION        
(In millions)        
  Three Months Ended Year Ended
  December 31, December 31,
  2010 2009 2010 2009
CASH FLOWS FROM OPERATING ACTIVITIES        
Net income  $ 42.6  $ 32.8  $ 134.0  $ 7.2
Adjustments to reconcile net income to net cash provided by operating activities:        
Amortization in interest expense  3.0  0.1  6.6  3.9
Amortization in general and administrative expense  0.1  0.1  0.4  0.3
Depreciation and amortization expense  43.0  40.2  171.3  165.2
Asset impairment charges  4.9  1.5  4.9  1.5
Interest expense on affiliate and allocated indebtedness  --   16.6  29.4  107.7
Accretion of asset retirement obligations  0.8  0.8  3.2  3.0
Deferred income tax expense  0.9  --   1.2  0.9
Equity in earnings of unconsolidated investments, net of distributions  2.2  (0.7)  3.3  -- 
Risk management assets  9.2  24.4  3.8  95.6
Loss on debt repurchases  --   1.5  --   1.5
Loss on extinguishment  (0.8)  (0.4)  --   -- 
Loss on sale of assets  --   (0.2)  --   0.1
Changes in operating assets and liabilities  25.3  2.6  13.1  36.0
Net cash provided by operating activities  131.2  119.3  371.2  422.9
CASH FLOWS FROM INVESTING ACTIVITIES        
Additions to property, plant and equipment  (54.5)  (23.9)  (137.0)  (95.9)
Other, net  --   3.3  2.1  1.3
Net cash used in investing activities  (54.5)  (20.6)  (134.9)  (94.6)
CASH FLOWS FROM FINANCING ACTIVITIES        
Proceeds from borrowings under credit facility  165.0  171.6  1,343.1  569.2
Repayments on credit facility  (153.0)  (202.8)  (1,057.0)  (577.7)
Proceeds from issuance of senior notes  --   --   250.0  237.4
Repayment of affiliated and allocated indebtedness  2.5  (0.1)  (737.7)  (397.5)
Repurchases of senior notes  --   --   --   (18.9)
Parent distributions  --   (14.4)  (102.5)  (151.9)
Proceeds from equity offerings  --   (0.4)  317.8  103.1
Costs incurred in connection with financing arrangements  --   0.2  (20.2)  (9.6)
General partner contributions  --   --   6.8  2.2
Distributions to unitholders  (46.2)  (35.3)  (164.0)  (114.3)
Distributions under common control  (21.5)  --   (68.1)  -- 
Distributions to noncontrolling interests  (1.7)  (3.4)  (19.1)  (22.6)
Net cash used in financing activities  (54.9)  (84.6)  (250.9)  (380.6)
Net change in cash and cash equivalents  21.8  14.1  (14.6)  (52.3)
Cash and cash equivalents, beginning of period  54.5  76.8  90.9  143.2
Cash and cash equivalents, end of period  $ 76.3  $ 90.9  $ 76.3  $ 90.9
         
         
CONSOLIDATED STATEMENTS OF OPERATIONS        
(In millions, except per unit data)        
  Three Months Ended Year Ended
  December 31, December 31,
  2010 2009 2010 2009
REVENUES  $ 1,527.2  $ 1,391.0  $ 5,469.2  $ 4,536.0
Product purchases  1,300.1  1,166.2  4,687.7  3,791.1
Operating expenses  69.8  52.3  260.2  235.0
Depreciation and amortization expense  48.6  42.4  185.5  170.3
General and administrative expense  63.4  36.8  144.4  120.4
Other  (4.3)  0.2  (4.7)  2.0
Total costs and expenses  1,477.6  1,297.9  5,273.1  4,318.8
INCOME FROM OPERATIONS  49.6  93.1  196.1  217.2
Other income (expense):        
Interest expense, net  (27.0)  (29.3)  (110.9)  (132.1)
Equity in earnings of unconsolidated investments  1.6  1.8  5.4  5.0
Gain (loss) on debt repurchases  --   --   (17.4)  (1.5)
Gain (loss) on early debt extinguishment  4.4  (0.7)  12.5  9.7
Gain on insurance claims  --   --   --   -- 
Gain (loss) on mark-to-market derivative instruments  --   (0.5)  (0.4)  0.3
Other income (expense)  (0.3)  (0.4)  0.5  1.2
Income (loss) before income taxes  28.3  64.0  85.8  99.8
Income tax (expense) benefit  (4.0)  (15.6)  (22.5)  (20.7)
NET INCOME   24.3  48.4  63.3  79.1
Less: Net income to noncontrolling interest  32.1  32.1  78.3  49.8
NET INCOME (LOSS) ATTRIBUTABLE TO TARGA RESOURCES CORP.  (7.8)  16.3  (15.0)  29.3
Dividends on Series B preferred stock  (1.1)  (4.6)  (9.5)  (17.8)
Undistributed earnings attributable to preferred shareholders  --   (11.5)  --   (11.5)
Distributions to common equivalents  --   --   (177.8)  -- 
Net income (loss) available to common shareholders  (8.9)  0.2  (202.3)  -- 
Net income (loss) available per common share  $ (0.68)  $ 0.05  $ (30.94)  $ -- 
Weighted average shares outstanding - basic and diluted  13.2  3.7  6.5  3.8
CONTACT: Investor Contact:
         (713) 584-1133
         
         Anthony Riley
         Director - Finance/Investor Relations
         
         Matthew Meloy
         Senior Vice President, Chief Financial Officer and Treasurer

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Source: Bankrate.com