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Targa Resources Partners LP and Targa Resources Corp. Report Third Quarter 2012 Financial Results

HOUSTON, Nov. 1, 2012 (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 third quarter 2012 results. Third quarter 2012 net income attributable to Targa Resources Partners was $24.2 million and income per diluted limited partner unit was $0.08. The results include a $15.4 million non-cash loss related to the write-off of the Partnership's investment in the Yscloskey plant which was damaged by Hurricane Isaac. Excluding this non-cash loss, net income attributable to Targa Resources Partners was $39.6 million or $0.25 per diluted limited partner unit compared to reported net income of $35.9 million or $0.31 per diluted limited partner unit for the third quarter of 2011. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments ("Adjusted EBITDA") of $116.2 million for the third quarter of 2012 compared to $107.3 million for the third quarter of 2011.

The Partnership's distributable cash flow for the third quarter 2012 of $77.1 million corresponds to distribution coverage of approximately 1.0 times the $76.7 million in total distributions to be paid on November 14, 2012 (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").

"The 8% increase in third quarter Adjusted EBITDA compared to last year, despite a lower commodity price environment and the hurricane impact, demonstrates the strength of industry fundamentals, the diversity of our businesses and the benefits of the growth projects that we have placed in service over the last year," said Joe Bob Perkins, CEO of the general partner of the Partnership and of Targa Resources Corp. "We have added meaningfully to our portfolio of announced organic growth projects, and now have over $1.6 billion in growth expenditures in process. Approximately half of this investment will be contributing to our results by year-end 2013 and several large projects will be on-line during 2014, all of which provides visibility on EBITDA growth through 2014 and beyond. Our portfolio of potential projects to add to the announced list is rich and active."

On October 11, 2012, the Partnership announced a cash distribution for the third quarter 2012 of 66.25¢ per common unit, or $2.65 per unit on an annualized basis, representing an increase of approximately 3% over the second quarter 2012 and 14% over the distribution for the third quarter 2011. The cash distribution will be paid on November 14, 2012 on all outstanding common units to holders of record as of the close of business on October 22, 2012. The total distribution paid will be $76.7 million, with $50.5 million to the Partnership's third-party limited partners, and $26.2 million to TRC for its ownership of common units, incentive distribution rights ("IDRs") and its 2% general partner interest in the Partnership.

Targa Resources Partners - Capitalization, Liquidity and Financing Update

Total funded debt at the Partnership as of September 30, 2012 was $1,661.7 million including $280.0 million outstanding under the Partnership's $1.1 billion senior secured revolving credit facility, $209.1 million of 8 1/4% senior unsecured notes due 2016, $72.7 million of 11 1/4% senior unsecured notes due 2017, $250.0 million of 7 7/8% senior unsecured notes due 2018, $483.6 million of 6 7/8% senior unsecured notes due 2021, $400.0 million of 6 3/8% senior unsecured notes due 2022, and $33.7 million of unamortized discounts.

As of September 30, 2012, after giving effect to $47.4 million in outstanding letters of credit, the Partnership had available revolver capacity of $772.6 million and $88.9 million of cash resulting in total liquidity of $861.5 million.

On October 3, 2012 the Partnership entered into a Second Amended and Restated Credit Agreement that amends and replaces its existing variable rate Senior Secured Credit Facility due July 2015 to provide a variable rate Senior Secured Credit Facility due October 3, 2017 (the "TRP Revolver"). The TRP Revolver increases available commitments to $1.2 billion from $1.1 billion and allows the Partnership to request increases up to an additional $300.0 million in commitments.

On October 19, 2012, the Partnership issued a call notice for full redemption of its 8 1/4% senior unsecured notes due July 2016 at a redemption price of 104.125% plus accrued interest through the redemption date of November 19, 2012. As of September 30, 2012, the outstanding balance on the 8 1/4% notes was $209.1 million. The redemption will result in a premium paid on the redemption of $8.6 million and a write-off of $2.6 million of unamortized debt issue costs.

On October 25, 2012, the Partnership privately placed $400.0 million in aggregate principal amount of 5¼% Senior Unsecured Notes due May 2023 (the "5¼% Notes") at 99.5% of par value. The 5¼% Notes resulted in approximately $398.0 million of gross proceeds ($393.5 million of net proceeds), which will be used to repay the Partnership's 8¼% senior unsecured notes, reduce borrowings under the Partnership's senior secured credit facility and for general partnership purposes.

Pro forma for amendment of the senior secured credit facility, the redemption of the 8 1/4% senior unsecured notes and the issuance of the 5¼% Notes, the Partnership had available revolver capacity of over $1.0 billion.

The Partnership estimates that its total capital expenditures for 2012 will be approximately $680 million gross. This amount includes approximately $600 million related to expansions and business acquisitions.

Targa Resources Corp. - Third Quarter 2012 Financial Results

Targa Resources Corp., the parent of Targa Resources Partners, today reported its third quarter 2012 results. The Company, which at September 30, 2012 owned a 2% general partner interest (held through its 100% ownership interest in the general partner of the Partnership), all of the IDRs and 12,945,659 common units of the Partnership, presents its results consolidated with those of the Partnership.

The Company reported net income available to common shareholders of $8.7 million for the third quarter 2012 compared with a net income available to common shareholders of $4.9 million for the third quarter 2011. The net income per diluted common share was $0.21 in the third quarter of 2012 compared to $0.12 for the third quarter of 2011.

Third quarter 2012 distributions to be paid on November 14, 2012 by the Partnership to the Company will be $26.2 million, with $8.6 million, $16.1 million and $1.5 million paid with respect to common units, IDRs and general partner interests, respectively.

On October 11, 2012, TRC declared a quarterly dividend of 42.25¢ per share of its common stock for the three months ended September 30, 2012, or $1.69 per share on an annualized basis, representing increases of approximately 7% over the previous quarter's dividend and 37% over the dividend for the third quarter of 2011. Total cash dividends declared of approximately $17.3 million will be paid November 15, 2012 on all outstanding common shares to holders of record as of the close of business on October 22, 2012.

The Company's distributable cash flow for the third quarter 2012 of $21.9 million corresponds to dividend coverage of approximately 1.2 times the $18.0 million in total declared dividends for the quarter (see the section of this release entitled "Targa Resources Corp. - Non-GAAP Financial Measures" for a discussion of distributable cash flow and reconciliations of this measure to its most directly comparable financial measure calculated and presented in accordance with GAAP).

Targa Resources Corp. - Capitalization, Liquidity and Financing Update

Total funded debt of the Company as of September 30, 2012, excluding debt of the Partnership, was $89.3 million. The Company also had access to the full amount of its $75.0 million senior secured revolving credit facility due 2014.

The Company's cash balance, excluding cash held at the Partnership and its subsidiaries, was $31.8 million as of September 30, 2012, resulting in total liquidity of $106.8 million.

On October 3, 2012 the Company entered into a Credit Agreement that replaced its existing variable rate Senior Secured Credit Facility due July 2014 with a new variable rate Senior Secured Credit Facility (the "TRC Revolver"). The TRC Revolver increases available commitments to the Company to $150.0 million from $75.0 million and allows the Company to request increases in commitments up to an additional $100.0 million.

On October 3, 2012, using $75 million in borrowings from the TRC Revolver and $13.8 million cash on hand, the Company paid $88.8 million to acquire the remaining $89.3 million of outstanding borrowings under the TRC Holdco Loan Facility, resulting in a pretax gain of $0.5 million. In addition, the Company wrote-off $0.3 million of associated unamortized deferred debt issue costs.

Pro forma for the TRC Revolver and the repayment of the TRC Holdco Loan Facility, the Company had total liquidity of $93 million.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 1:00 p.m. Eastern Time (12:00 p.m. Central Time) on November 1, 2012 to discuss third quarter 2012 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 40262350. 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 and the Company's website.

Targa Resources Partners – Consolidated Financial Results of Operations

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
(In millions except per unit data)
Revenues $1,392.9 $1,712.7 $4,356.8 $5,053.8
Product purchases 1,153.0 1,485.5 3,611.7 4,364.5
Gross margin (1) 239.9 227.2 745.1 689.3
Operating expenses 78.3 76.5 227.1 214.1
Operating margin (2) 161.6 150.7 518.0 475.2
Depreciation and amortization expense 47.9 45.0 142.1 132.2
General and administrative expense 33.5 33.7 100.0 98.6
Other operating (income) expense 18.9 (0.3) 18.8 (0.4)
Income from operations 61.3 72.3 257.1 244.8
Interest expense, net (29.0) (25.7) (87.8) (80.4)
Equity earnings (losses) (2.2) 2.2 (0.3) 5.2
Loss on mark-to-market derivative instruments -- (1.8) -- (5.0)
Other (1.1) (0.6) (1.6) (0.8)
Income tax expense (0.9) (1.5) (2.7) (5.2)
Net income 28.1 44.9 164.7 158.6
Less: Net income attributable to noncontrolling interest 3.9 9.0 23.5 29.6
Net income attributable to Targa Resources Partners LP $24.2 $ 35.9 $141.2 $129.0
Net income attributable to general partner 16.7 9.5 46.2 26.0
Net income attributable to limited partners 7.5 26.4 95.0 103.0
Net income attributable to Targa Resources Partners LP $24.2 $35.9 $141.2 $129.0
Basic and diluted net income per limited partner unit $0.08 $0.31 $1.07 $1.23
Financial data:
Adjusted EBITDA (3) $116.2 $107.3 $384.4 $344.6
Distributable cash flow (4) 77.2 65.4 267.6 229.5
Operating data:
Plant natural gas inlet, MMcf/d (5)(6) 1,968.6 2,087.0 2,094.3 2,152.8
Gross NGL production, MBbl/d 123.4 121.4 126.6 122.2
Natural gas sales, BBtu/d (6) 981.8 799.7 924.4 746.6
NGL sales, MBbl/d 282.0 258.9 277.1 265.1
Condensate sales, MBbl/d 3.6 3.2 3.5 3.2

__________

(1) Gross margin is a non-GAAP financial measure and is discussed under "Targa Resources Partners – Non-GAAP Financial Measures."

(2) Operating margin is a non-GAAP financial measure and is discussed under "Targa Resources Partners – Non-GAAP Financial Measures."

(3) Adjusted EBITDA is net income before: interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and asset disposals, and non-cash risk management activities related to derivative instruments. This is a non-GAAP financial measure and is discussed under "Targa Resources Partners – Non-GAAP Financial Measures."

(4) Distributable cash flow is 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 non-cash losses (gains) on mark-to-market derivative contracts, debt repurchases and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs). This is a non-GAAP financial measure and is discussed under "Targa Resources Partners – Non-GAAP Financial Measures."

(5) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(6) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

Targa Resources Partners – Review of Consolidated Third Quarter Results

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

Revenues, including the impacts of hedging, decreased due to the impact of lower realized prices on commodities ($579.8 million), partially offset by higher commodity sales volumes ($190.4 million), petroleum product revenues ($52.7 million), and higher fee-based and other revenues ($16.9 million).

The increase in operating margin reflects a higher gross margin, partially offset by higher operating expenses. The increase in gross margin resulted from higher volumes and fee revenues more than offset by lower realized sales prices and lower product purchase costs due to the weaker commodity price environment. The increase in the Partnership's operating costs was primarily due to its expansion and acquisition activities. See "Targa Resources Partners – Review of Segment Performance" for additional information regarding changes in the components of operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses was primarily due to the impact of new assets placed in service as well as assets associated with business acquisitions.

General and administrative expenses were flat.

Other operating (income) expense reflects a $15.4 million loss due to a write-off of the Partnership's investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant. Additionally, other operating (income) expense includes $3.3 million in costs associated with the clean-up and repairs necessitated by Hurricane Isaac at the Partnership's Coastal Straddle plants.

The increase in interest expense was the result of higher borrowings ($4.7 million) and higher effective interest rate ($1.7 million), offset by higher capitalized interest ($3.1 million) attributable to the Partnership's expansion capital expenditures.

Operations at the Partnership's non-operated equity investment, Gulf Coast Fractionators ("GCF"), continued to be impacted by the planned shutdown of operations that started during the second quarter and was completed in the third quarter associated with GCF's 43 MBbl/d capacity expansion. The facility's operations were also hampered by start-up issues associated with the expansion. This resulted in a loss for the quarter from this equity investment.

The mark-to-market loss in 2011 was attributable to interest rate swaps that were de-designated during the second quarter of that year. Consequently, the Partnership discontinued hedge accounting on those swaps, so changes in fair value and cash settlements were recorded as mark-to-market loss. The Partnership terminated all of its interest rate swaps in September 2011.

The decrease in net income attributable to noncontrolling interests reflects the impact of the weaker price environment on Versado and Venice, as well as the disruption of operations at Venice due to Hurricane Isaac.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Revenues, including the impacts of hedging, decreased due to the impact of lower realized prices on commodities ($1,318.2 million), partially offset by higher commodity sales volumes ($409.9 million), petroleum product revenues ($152.5 million), and higher fee-based and other revenues ($58.8 million).

The increase in operating margin reflects a higher gross margin, partially offset by higher operating expenses. The increase in gross margin resulted from higher volumes and fee revenues more than offset by lower realized sales prices and lower product purchase costs due to the weaker commodity price environment. The increase in the Partnership's operating costs was primarily due to its expansion and acquisition activities. See "Targa Resources Partners – Review of Segment Performance" for additional information regarding changes in the components of operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses was primarily due to the impact of new assets placed in service as well as assets associated with business acquisitions.

General and administrative expenses were flat.

Other operating (income) expense relates to the Yscloskey plant closure and Hurricane Isaac repair costs as discussed above.

The increase in interest expense was the result of higher borrowings ($8.6 million) and higher effective interest rate ($5.2 million), offset by higher capitalized interest ($6.4 million) attributable to the Partnership's expansion capital expenditures.

Operations at the Partnership's non-operated equity investment, Gulf Coast Fractionators, variance is explained above. This resulted in a loss for 2012 from this equity investment.

Mark-to-market loss variance is explained above.

The decrease in net income attributable to noncontrolling interests reflects the impact of the weaker price environment on Versado and Venice, as well as the disruption of operations at Venice due to Hurricane Isaac.

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.

The Partnership reports its operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two reportable segments - (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing, consisting of two reportable segments - (a) Logistics Assets and (b) Marketing and Distribution. The financial results of the Partnership's commodity hedging activities are reported in Other.

Natural Gas Gathering and Processing Segments

Field Gathering and Processing

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 September 30, Nine Months Ended September 30,
2012 2011 2012 2011
($ in millions)
Gross margin $84.0 $102.4 $271.2 $299.3
Operating expenses 30.2 30.6 90.6 86.3
Operating margin $53.8 $71.8 $180.6 $213.0
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2), (3)
Sand Hills 154.6 139.6 143.7 131.6
SAOU 126.0 114.3 121.1 110.0
North Texas System 246.5 210.7 237.9 197.4
Versado 159.2 163.6 166.3 165.4
686.3 628.2 669.0 604.4
Gross NGL production, MBbl/d
Sand Hills 17.8 16.6 16.8 15.5
SAOU 19.5 17.8 18.8 17.1
North Texas System 26.6 22.9 26.1 22.2
Versado 19.0 17.8 19.3 18.3
82.9 75.1 81.0 73.1
Natural gas sales, BBtu/d (3) 333.5 295.8 319.9 281.2
NGL sales, MBbl/d 68.7 60.2 67.1 58.9
Condensate sales, MBbl/d 3.4 3.0 3.3 2.9
Average realized prices (4):
Natural gas, $/MMBtu 2.59 4.03 2.40 3.96
NGL, $/gal 0.79 1.29 0.90 1.22
Condensate, $/Bbl 86.82 85.99 90.40 91.99

________

(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 quarter and the denominator is the number of calendar days during the quarter.

(2) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(3) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(4) Average realized prices exclude the impact of hedging activities presented in Other.

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

The decrease in gross margin was primarily due to lower natural gas and NGL sales prices, partially offset by higher throughput volumes. The increase in plant inlet volumes was largely attributable to new well connects, particularly at North Texas, Sand Hills and SAOU.

Operating expenses were relatively flat as additional compression related expenses due to system expansions and higher system maintenance and repair costs were offset by lower costs at Versado due to operational issues that impacted 2011.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

The decrease in gross margin was primarily due to lower natural gas and NGL sales prices, partially offset by higher throughput volumes. The increase in plant inlet volumes was largely attributable to new well connects, particularly at North Texas, Sand Hills and SAOU, partially offset by pipeline curtailments and operational issues.

The increase in operating expenses was primarily due to additional compression related expenses due to system expansions and higher system maintenance and repair costs.

Coastal Gathering and Processing

The Coastal Gathering and Processing segment assets are located in the onshore and near offshore 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 United States.

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

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
($ in millions)
Gross margin $31.7 $52.9 $127.2 $156.6
Operating expenses (1) 13.7 13.1 34.9 34.8
Operating margin $18.0 $39.8 $92.3 $121.8
Operating statistics (2):
Plant natural gas inlet, MMcf/d (3),(4)
LOU(5) 324.5 170.7 245.0 169.5
Coastal Straddles 607.7 828.4 735.5 897.8
VESCO 350.0 459.7 444.8 481.0
1,282.2 1,458.8 1,425.3 1,548.3
Gross NGL production, MBbl/d
LOU 8.9 7.7 8.4 7.1
Coastal Straddles 14.8 16.4 16.0 17.2
VESCO 16.9 22.2 21.1 24.8
40.6 46.3 45.5 49.1
Natural gas sales, BBtu/d (4) 317.2 256.6 304.8 261.0
NGL sales, MBbl/d 38.4 41.6 42.1 43.0
Condensate sales, MBbl/d 0.2 0.2 0.2 0.3
Average realized prices (6):
Natural gas, $/MMBtu 2.87 4.21 2.59 4.24
NGL, $/gal 0.85 1.35 0.99 1.30
Condensate, $/Bbl 96.07 107.72 107.17 102.38

__________

(1) Costs associated with the clean-up and repair of Coastal Straddle plants resulting from the impact of Hurricane Isaac are reported as Other Operating Expenses and thus are not reflected in operating margin at the Coastal Gathering and Processing Segment level.

(2) 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 quarter and the denominator is the number of calendar days during the quarter.

(3) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(4) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(5) Includes operations from the Big Lake processing plant acquired July 2012.

(6) Average realized prices exclude the impact of hedging activities presented in Other.

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

The decrease in gross margin was primarily due to lower commodity sales prices, less favorable frac spread and lower throughput volumes. The decrease in plant inlet volumes was largely attributable to the decline in offshore and off-system supply volumes and the impact of Hurricane Isaac in August and September 2012 at the Coastal Straddle plants. The decrease was partially offset by an increase at LOU in supply volumes and the July 2012 acquisition of the Big Lake plant and gas purchased for processing at VESCO and Lowry. Natural gas sales volumes increased due to an increase in demand from industrial customers and increased sales to other reportable segments for resale.

The increase in operating expenses was primarily due to higher system maintenance and repair costs partially offset by lower utilities, power and catalysts costs.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

The decrease in gross margin for year to date compared to 2011 was influenced by the factors described above for the three months. In addition, plant inlet volumes in the second quarter 2012 were impacted by planned operational outages at VESCO.

The impact of the Yscloskey plant is not material to the results of the Coastal Gathering and Processing Segment as it contributed approximately 2.7% of the Coastal Segment's gross NGL production for 2012, which accounted for less than 1% of operating margin for the nine months.

Operating expenses were flat as higher system maintenance and repair costs were offset by lower utilities, power and catalysts costs and higher refunds of operating expenses after ownership adjustments at non-operated joint ventures.

Logistics and Marketing Segments

Logistics Assets

The Logistics Assets segment is involved in transporting, storing and fractionating mixed NGLs; storing, terminaling and transporting finished NGLs; and storing and terminaling refined petroleum products and crude oil. The Partnership's logistics assets are generally connected to, and supplied in part by, its Natural Gas Gathering and Processing segments and are predominantly located at Mont Belvieu, Texas and Southwestern Louisiana. This segment also includes the activities associated with the 2011 acquisitions of refined petroleum products and crude oil storage and terminaling facilities.

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

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
($ in millions)
Gross margin $74.5 $57.5 $208.0 $157.0
Operating expenses 24.1 27.4 68.8 71.1
Operating margin $50.4 $30.1 $139.2 $85.9
Operating statistics (1):
Fractionation volumes, MBbl/d 293.3 290.4 299.4 260.1
Treating volumes, MBbl/d (2) 24.8 23.3 23.7 20.5

________

(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 quarter and the denominator is the number of calendar days during the quarter.

(2) Includes the volumes related to the natural gasoline hydrotreater at the Mt. Belvieu facility.

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

Gross margin increased significantly due to higher treating, fractionation, terminaling and export activities. Gross margin improved due to higher treating volumes attributable to the benzene and depentanizer operations which started up in the first quarter 2012. Exporting and terminaling contributed to gross margin improvements as a result of substantially higher exports and the impact of the October 2011 Sound Terminal acquisition. Higher fractionation fees were partially offset by the impact of lower fuel prices which pass through to expenses.

Operating expenses decreased due to favorable system product gains and lower fuel costs (which have a corresponding impact on revenues), partially offset by an increase in operating costs associated with the October 2011 Sound Terminal acquisition.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

The increase in gross margin was primarily due to higher fractionation and treating volumes, increased export and storage fees, and the impact of the 2011 petroleum logistics acquisitions. Higher fractionation volumes and fees were primarily attributable to the Cedar Bayou facility Train 3 expansion which came on line in mid-year 2011 (partially offset by the impact of lower fuel prices which pass through to expenses). Treating fees increased due to the operational startup of the benzene treating unit in the first quarter of 2012 and increased hydrotreating and depentanizer fees associated with increased volumes. Exporting and terminaling increased due to the same factors as described above.

The decrease in operating expenses was primarily due to favorable system product gains and lower fuel costs (which have a corresponding impact on revenues), partially offset by higher maintenance costs, increased operating costs due to greater hydrotreating and benzene unit run times, and the impact of a full nine months in 2012 of operating costs associated with petroleum logistics operations acquired in April and October of 2011.

Marketing and Distribution

The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes: (1) marketing of the Partnership's natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to the Partnership from its Natural Gas Gathering and Processing division and the purchase and resale of natural gas in selected United States markets.

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

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
($ in millions)
Gross margin $35.4 $30.1 $106.2 $116.0
Operating expenses 10.0 10.4 28.4 33.2
Operating margin $25.4 $19.7 $77.8 $82.8
Operating statistics (1):
Natural gas sales, BBtu/d 1,182.2 962.1 1,100.9 829.1
NGL sales, MBbl/d 289.4 264.5 282.2 267.3
Average realized prices:
Natural gas, $/MMBtu 2.80 4.10 2.54 4.15
NGL realized price, $/gal 0.88 1.32 1.00 1.32

________

(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 quarter and the denominator is the number of calendar days during the quarter.

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

The increase in gross margin was due to an increase in LPG export activity, favorable short-term wholesale propane marketing opportunities driven by regional supply conditions, and improved transportation opportunities. These favorable factors more than offset the effect of a weaker price environment. Export cargo volumes increased significantly and loading revenues increased compared to the same period last year.

Operating expenses were essentially flat due to increased truck operating costs offset by lower barge operating and maintenance costs.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

The decrease in gross margin was primarily due to a weaker price environment in 2012, partially offset by increased LPG export activity. Export cargo volumes increased significantly and export loading revenues increased compared to the same period last year. As in 2011, gross margin benefited from receipt of a contract settlement payment related to a multi-year contract propane exchange agreement ($3.8 million received year to date 2012 versus $7.5 million in 2011). The contract, as restructured, may result in the receipt of future payments in the fourth quarter and over the remaining term of the contract.

Operating expenses decreased due to significantly lower barge activity in 2012 compared to 2011, partially offset by increased truck operating costs.

Other

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
($ in millions)
Gross margin $14.0 $ (10.8) $28.1 $(28.4)
Operating margin $14.0 $ (10.8) $28.1 $(28.4)

Other contains the financial effects of the Partnership's hedging program on operating margin. It typically represents the cash settlements on the Partnership's derivative contracts. Other also includes deferred gains or losses on previously terminated or de-designated hedge contracts that are reclassified to revenues upon the occurrence of the underlying physical transactions.

The primary purpose of the Partnership's commodity risk management activities is to manage its exposure to commodity price risk and reduce volatility in its operating cash flow due to fluctuations in commodity prices. The Partnership has hedged the commodity price associated with a portion of its expected (i) natural gas equity volumes in Field Gathering and Processing Operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing as well as in the LOU portion of the Coastal Gathering and Processing Operations that result from its percent of proceeds processing arrangements by entering into derivative instruments. Because the Partnership is essentially forward selling a portion of its plant equity volumes, these hedge positions will move favorably in periods of falling prices and unfavorably in periods of rising prices.

The following table provides a breakdown of the Partnership's hedge revenue by product:

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
(In millions)
Natural gas $8.0 $6.4 $26.9 $14.2
NGL 6.0 (15.8) 3.5 (38.0)
Crude oil -- (1.4) (2.3) (4.6)
$14.0 $(10.8) $28.1 $(28.4)

The increase in gross margin from the Partnership's risk management activities was primarily due to lower natural gas and NGL prices.

About Targa Resources Corp. and Targa Resources Partners

Targa Resources Corp. is a publicly traded Delaware corporation that 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 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; storing, fractionating, treating, transporting and selling natural gas liquids, or NGLs, and NGL products; and storing and terminaling refined petroleum products and crude oil. 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 onshore and near 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 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 their 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 Partnership's non-GAAP financial measures distributable cash flow, Adjusted EBITDA, gross margin and operating margin. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. The Partnership's 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 non-cash losses (gains) on mark-to-market derivative contracts, debt repurchases and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs). The impact of noncontrolling interests is included in this measure.

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 and research analysts 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 and external users of the Partnership's financial statements 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 GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Partners LP. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors 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 attributable to Targa Resources Partners LP 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 measure, understanding the differences between the measures and incorporating these insights into its decision making processes.

The following table presents a reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow for the periods indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
(In millions)
Reconciliation of net income attributable to Targa
Resources Partners LP to distributable cash flow:
Net income attributable to Targa Resources Partners LP $24.2 $35.9 $141.2 $129.0
Depreciation and amortization expenses 47.9 45.0 142.1 132.2
Deferred income tax expense 0.4 (0.9) 1.2 0.6
Amortization in interest expense 4.5 2.5 13.6 8.1
Loss on sale or disposal of assets 15.6 -- 15.5 --
Risk management activities 1.6 2.0 3.8 6.0
Maintenance capital expenditures (16.2) (24.7) (48.0) (57.2)
Other (1) (0.8) 5.6 (1.8) 10.8
Targa Resources Partners LP distributable cash flow $77.2 $65.4 $267.6 $229.5

_______

(1) Includes reimbursements of certain environmental maintenance capital expenditures by TRC and the noncontrolling interest portion of maintenance capital expenditures, depreciation and amortization expense.

Adjusted EBITDA - The Partnership defines Adjusted EBITDA as net income attributable to Targa Resources Partners LP before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases, asset disposals and non-cash risk management activities 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.

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 investors.

The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income attributable to Targa Resources Partners LP. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income attributable to Targa Resources Partners LP. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors 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 attributable to Targa Resources Partners LP 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.

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 insights into its decision-making processes.

The following table presents a reconciliation of net cash provided by operating activities to Targa Resources Partners LP Adjusted EBITDA for the periods indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
(In millions)
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:

Net cash provided by operating activities $90.5 $(61.3) $315.5 $191.3
Net income attributable to noncontrolling interests (3.9) (9.0) (23.5) (29.6)
Interest expense, net (1) 24.5 24.7 74.2 73.7
Current income tax expense 0.5 2.4 1.5 4.6
Other (2) (5.3) 18.8 (14.5) 10.8
Changes in operating assets and liabilities which used (provided) cash:

Accounts receivable and other assets
42.6 105.4 (166.1) 169.8

Accounts payable and other liabilities
(32.7) 26.3 197.3 (76.0)
Adjusted EBITDA $116.2 $107.3 $384.4 $344.6

_________

(1) Net of amortization of debt issuance costs, discount and premium included in interest expense of $4.5 million and $13.6 million for the three and nine months ended September 30, 2012, and $1.0 million and $6.7 million for the three and nine months ended September 30, 2011.

(2) Includes equity earnings (loss) from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock based compensation and loss on sale or disposal of assets.

The following table presents a reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA for the periods indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
(In millions)
Reconciliation of net income attributable to
Targa Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP $24.2 $35.9 $141.2 $129.0
Add:
Interest expense, net 29.0 25.7 87.8 80.4
Income tax expense 0.9 1.5 2.7 5.2
Depreciation and amortization expenses 47.9 45.0 142.1 132.2
Loss on sale or disposal of assets 15.6 -- 15.5 --
Risk management activities 1.6 2.0 3.8 6.0
Noncontrolling interests adjustment (1) (3.0) (2.8) (8.7) (8.2)
Adjusted EBITDA $116.2 $107.3 $384.4 $344.6

__________

(1) Noncontrolling interest portion of depreciation and amortization expenses.

Gross Margin – The Partnership defines gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as by the Partnership's contract mix and hedging program. The Partnership defines Natural Gas Gathering and Processing gross margin as total operating revenues from the sales of natural gas and NGLs plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees and NGL sales, less cost of sales, which consists primarily of NGL purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash flow hedge settlements are reported in Other.

Operating Margin - Operating margin is an important performance measure of the core profitability of the Partnership's operations. The Partnership defines operating margin as gross margin less operating expenses.

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income, and have important limitations as analytical tools. Investors 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 exclude some, but not all, items that affect net income and are defined differently by different companies in the Partnership's industry, 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 reviews business segment gross margin and operating margin monthly as a core internal management process. The Partnership believes that investors benefit from having access to the same financial measures that its management uses in evaluating its operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by the Partnership and by external users of the Partnership's financial statements, including investors and commercial banks to assess:

  • the financial performance of the Partnership's assets without regard to financing methods, capital structure or historical cost basis;
  • the Partnership's operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
  • the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making processes.

The following table presents a reconciliation of gross margin and operating margin to net income for the periods indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
(In millions)
Reconciliation of gross margin and operating margin to net income:
Gross margin $239.9 $227.2 $745.1 $689.3
Operating expenses (78.3) (76.5) (227.1) (214.1)
Operating margin 161.6 150.7 518.0 475.2
Depreciation and amortization expenses (47.9) (45.0) (142.1) (132.2)
General and administrative expenses (33.5) (33.7) (100.0) (98.6)
Interest expense, net (29.0) (25.7) (87.8) (80.4)
Income tax expense (0.9) (1.5) (2.7) (5.2)
Gain (loss) on sale or disposal of assets (18.9) 0.3 (18.8) 0.4
Other, net (3.3) (0.2) (1.9) (0.6)
Net income $28.1 $44.9 $164.7 $158.6

Targa Resources Corp. - Non-GAAP Financial Measures

This press release includes the Company's non-GAAP financial measure distributable cash flow. Distributable cash flow should not be considered as an alternative to GAAP measures such as net income or any other GAAP measure of liquidity or financial performance.

Distributable Cash Flow - The Company defines distributable cash flow as distributions due to it from the Partnership, less the Company's specific general and administrative costs as a separate public reporting entity, the interest carry costs associated with its debt and taxes attributable to the Company's earnings. Distributable cash flow is a significant performance metric used by the Company and by external users of the Company's financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by the Company to the cash dividends the Company expects to pay its shareholders. Using this metric, management and external users of the Company's financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash dividends. Distributable cash flow is also an important financial measure for the Company's shareholders since it serves as an indicator of the Company's success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Company is generating cash flow at a level that can sustain or support an increase in the Company's quarterly dividend rates. Distributable cash flow is also a quantitative standard used throughout the investment community because the share value is generally determined by the share's yield (which in turn is based on the amount of cash dividends the entity pays to a shareholder).

The economic substance behind the Company's use of distributable cash flow is to measure the ability of the Company's assets to generate cash flow sufficient to pay dividends to the Company's investors.

The GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Corp. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Corp. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of the Company's results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income attributable to Targa Resources Corp. and is defined differently by different companies in the Company's industry, the Company's definition of distributable cash flow may not be compatible 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 measure, understanding the differences between the measures and incorporating these insights into its decision making process.

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

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
(In millions)
Reconciliation of net income attributable to Targa Resources Corp. to Distributable Cash Flow
Net income of Targa Resources Corp. $19.0 $36.5 $131.7 $140.6
Less: Net income of Targa Resources Partners LP (28.1) (44.9) (164.7) (158.6)
Net loss for TRC Non-Partnership (9.1) (8.4) (33.0) (18.0)
Plus: TRC Non-Partnership income tax expense 5.1 5.9 22.0 13.3
Plus: Distributions from the Partnership 26.2 16.8 72.6 46.8
Plus: Non-cash loss (gain) on hedges (0.6) (0.9) (1.6) (3.8)
Plus: Depreciation - Non-Partnership assets 0.7 0.7 2.2 2.1
Less: Current cash tax expense (1) (2.6) 6.1 (15.2) 0.6
Plus: Taxes funded with cash on hand (2) 2.2 -- 6.6 5.1
Distributable cash flow $21.9 $20.2 $53.6 $46.1

________

(1) Excludes $1.2 million and $3.6 million of non-cash current tax expense arising from amortization of deferred long-term tax assets from drop down gains realized for tax purposes and paid in 2010 for the three and nine months ended September 30, 2012 and 2011.

(2) Current period portion of amount established at the Company's IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes.

The following table presents an alternative reconciliation of cash distributions declared by Targa Resources Partners LP to distributable cash flow of Targa Resources Corp. for the periods indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
Targa Resources Corp. Distributable Cash Flow (In millions)
Distributions declared by Targa Resources Partners LP associated with:
General Partner Interests $1.5 $1.2 $4.4 $3.5
Incentive Distribution Rights 16.1 8.8 43.2 23.4
Common Units 8.6 6.8 25.0 19.9
Total distributions declared by Targa Resources Partners LP 26.2 16.8 72.6 46.8
Income (expenses) of TRC Non-Partnership
General and administrative expenses (2.2) (1.7) (6.5) (6.5)
Interest expense, net (1.0) (1.1) (3.2) (2.9)
Current cash tax expense (1) (2.6) 6.1 (15.2) 0.6
Taxes funded with cash on hand (2) 2.2 -- 6.6 5.1
Other income (expense) (0.7) 0.1 (0.7) 3.0
Distributable cash flow $21.9 $20.2 $53.6 $46.1

________

(1) Excludes $1.2 million and $3.6 million of non-cash current tax expense arising from amortization of deferred long-term tax assets from drop down gains realized for tax purposes and paid in 2010 for the three and nine months ended September 30, 2012 and 2011.

(2) Current period portion of amount established at the Company's IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes.

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 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.

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED BALANCE SHEETS
(In millions)
September 30, December 31,
2012 2011
ASSETS
Current assets:
Cash and cash equivalents $88.9 $55.6
Trade receivables 415.9 575.9
Inventory 84.3 92.1
Assets from risk management activities 33.7 41.0
Other current assets 1.1 2.7
Total current assets 623.9 767.3
Property, plant and equipment, net 3,049.9 2,806.1
Long-term assets from risk management activities 11.1 10.9
Other assets 86.0 73.7
Total assets $3,770.9 $3,658.0
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities $519.7 $707.8
Liabilities from risk management activities 6.0 41.1
Total current liabilities 525.7 748.9
Long-term debt 1,661.7 1,477.7
Long-term liabilities from risk management activities 7.2 15.8
Other long-term liabilities 57.4 53.9
Owners' equity:
Targa Resources Partners LP owner's equity 1,371.9 1,222.8
Noncontrolling interests in subsidiaries 147.0 138.9
Total owners' equity 1,518.9 1,361.7
Total liabilities and owners' equity $3,770.9 $3,658.0


TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit amounts)
Three Months Ended Nine Months Ended
September 30, September 30,
2012 2011 2012 2011
REVENUES $1,392.9 $1,712.7 $4,356.8 $5,053.8

Product purchases
1,153.0 1,485.5 3,611.7 4,364.5
Operating expenses 78.3 76.5 227.1 214.1
Depreciation and amortization expenses 47.9 45.0 142.1 132.2
General and administrative expenses 33.5 33.7 100.0 98.6
Other operating 18.9 (0.3) 18.8 (0.4)
Total costs and expenses 1,331.6 1,640.4 4,099.7 4,809.0
INCOME FROM OPERATIONS 61.3 72.3 257.1 244.8
Other income (expense):
Interest expense, net (29.0) (25.7) (87.8) (80.4)
Equity earnings (loss) (2.2) 2.2 (0.3) 5.2
Loss on mark-to-market derivative instruments -- (1.8) -- (5.0)
Other income (expense) (1.1) (0.6) (1.6) (0.8)
Income before income taxes 29.0 46.4 167.4 163.8
Income tax expense (0.9) (1.5) (2.7) (5.2)
NET INCOME 28.1 44.9 164.7 158.6
Less: Net income attributable to noncontrolling interests 3.9 9.0 23.5 29.6
NET INCOME ATTRIBUTABLE TO TARGA
RESOURCES PARTNERS LP
$24.2 $35.9 $141.2 $129.0
Net income attributable to general partner 16.7 9.5 46.2 26.0
Net income allocable to limited partners 7.5 26.4 95.0 103.0
Net income attributable to Targa Resources Partners LP $24.2 $35.9 $141.2 $129.0
Net income per limited partner unit - basic and diluted $0.08 $0.31 $1.07 $1.23
Basic weighted average limited partner units outstanding 89.2 84.8 88.8 83.9
Diluted weighted average limited partner units outstanding 89.3 84.8 88.9 83.9


TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED CASH FLOW INFORMATION
(In millions)
Nine Months Ended September 30,
2012 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $164.7 $158.6
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense 13.6 6.7
Compensation on equity grants 2.6 1.2
Depreciation and other amortization expense 142.1 132.2
Accretion of asset retirement obligations 2.9 2.7
Deferred income tax expense 1.2 0.6
Equity in earnings of unconsolidated investment, net of distributions 0.3 (1.4)
Risk management activities 3.8 (15.1)
Loss (gain) on sale or disposal of assets 15.5 (0.4)
Changes in operating assets and liabilities (31.2) (93.8)
Net cash provided by operating activities 315.5 191.3
CASH FLOWS FROM INVESTING ACTIVITIES
Outlays for property, plant and equipment (364.8) (211.4)
Business acquisition (25.8) (164.2)
Investment in unconsolidated affiliate (16.8) (11.9)
Return of capital from unconsolidated affiliate 2.3 --
Other, net 1.6 0.3
Net cash used in investing activities (403.5) (387.2)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility 720.0 1,426.0
Repayments of credit facility (938.0) (1,656.3)
Proceeds from issuance of senior notes 400.0 325.0
Cash paid on note exchange -- (27.7)
Proceeds from equity offerings 168.3 304.3
Distributions to unitholders (208.9) (165.9)
Costs incurred in connection with financing arrangements (4.5) (6.2)
Contributions from parent 0.9 9.1
Contributions from noncontrolling interest 3.2 --
Distribution to noncontrolling interests (19.7) (19.8)
Net cash provided by (used in) financing activities 121.3 188.5
Net change in cash and cash equivalents 33.3 (7.4)
Cash and cash equivalents, beginning of period 55.6 76.3
Cash and cash equivalents, end of period $88.9 $68.9


TARGA RESOURCES CORP.
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts)
Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
REVENUES $1,393.5 $1,713.6 $4,358.4 $5,060.5
Product purchases 1,153.0 1,485.5 3,611.8 4,364.5
Operating expenses 78.3 76.5 227.2 214.1
Depreciation and amortization expenses 48.6 45.7 144.3 134.3
General and administrative expenses 35.7 35.4 106.5 105.1
Other operating 18.9 (0.3) 18.8 (0.3)
Total costs and expenses 1,334.5 1,642.8 4,108.6 4,817.7
INCOME FROM OPERATIONS 59.0 70.8 249.8 242.8
Other income (expense):
Interest expense, net (30.0) (26.8) (91.0) (83.3)
Equity earnings (loss) (2.2) 2.2 (0.3) 5.2
Loss on mark-to-market derivative instruments -- (1.8) -- (5.0)
Other expenses (1.8) (0.5) (2.1) (0.6)
Income before income taxes 25.0 43.9 156.4 159.1
Income tax expense (6.0) (7.4) (24.7) (18.5)
NET INCOME 19.0 36.5 131.7 140.6
Less: Net income attributable to noncontrolling interest 10.3 31.6 104.8 118.4
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $8.7 $4.9 $26.9 $22.2
Net income available per common share – basic $0.21 $0.12 $0.66 $0.54
Net income available per common share diluted $0.21 $0.12 $0.64 $0.54
Weighted average shares outstanding – basic 41.0 41.0 41.0 41.0
Weighted average shares outstanding – diluted 41.9 41.5 41.8 41.4


TARGA RESOURCES CORP.
FINANCIAL SUMMARY (unaudited)

KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS


September 30,
2012
Cash and cash equivalents:

TRC Non-Partnership
$ 31.8
Targa Resources Partners 88.9
Total cash and cash equivalents $120.7
Long-term debt:
TRC Non-Partnership $89.3
Targa Resources Partners 1,661.7
Total long-term debt $1,751.0
CONTACT: Investor Relations (713) 584-1133 Matthew Meloy Senior Vice President, Chief Financial Officer and Treasurer Joe Brass Director, FinanceSource:Targa Resources Partners LP