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Targa Resources Partners LP and Targa Resources Corp. Report Third Quarter 2014 Financial Results

HOUSTON, Nov. 4, 2014 (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 2014 results.

Targa Resources Partners – Third Quarter 2014 Financial Results

Third quarter 2014 net income attributable to Targa Resources Partners was $128.3 million compared to $59.7 million for the third quarter of 2013. Net income per diluted limited partner unit was $0.78 for the third quarter of 2014 compared to $0.30 for the third quarter of 2013. The Partnership reported earnings before interest, income taxes, depreciation and amortization and other non-cash items ("Adjusted EBITDA") of $246.7 million for the third quarter of 2014 compared to $155.9 million for the third quarter of 2013.

The Partnership's distributable cash flow for the third quarter 2014 of $192.5 million corresponds to distribution coverage of approximately 1.5 times the $130.9 million in total distributions to be paid on November 14, 2014 (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")).

"Our record third quarter 2014 EBITDA reflects the continued success of our diversified midstream platform with record operating margin in our predominately fee-based Logistics and Marketing division and with record operating margin and natural gas inlet volumes in our Field Gathering and Processing segment," said Joe Bob Perkins, Chief Executive Officer of the general partner of the Partnership and of the Company.

On October 23, 2014, the Partnership announced a cash distribution for the third quarter 2014 of $0.7975 per common unit, or $3.19 per unit on an annualized basis, representing an increase of approximately 2% over the distribution for the second quarter 2014 and 9% over the distribution for the third quarter 2013. The cash distribution will be paid on November 14, 2014 on all outstanding common units to holders of record as of the close of business on November 3, 2014. The total distribution paid will be $130.9 million, with $82.0 million to the Partnership's third-party limited partners and $48.9 million to TRC for its ownership of common units, incentive distribution rights ("IDRs") and its 2% general partner interest in the Partnership.

Targa Resources Corp. – Third Quarter 2014 Financial Results

TRC reported net income available to common shareholders of $30.7 million for the third quarter 2014 compared to $16.3 million for the third quarter 2013. The net income per diluted common share was $0.73 for the third quarter of 2014 compared to $0.39 for the third quarter of 2013.

The Company, which as of September 30, 2014 owned a 2% general partner interest in the Partnership (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.

Third quarter 2014 distributions to be paid on November 14, 2014 by the Partnership to the Company will be $48.9 million, with $10.3 million, $36.0 million and $2.6 million paid with respect to common units, IDRs and general partner interests, respectively.

On October 23, 2014, TRC declared a quarterly dividend of $0.7325 per share of its common stock for the three months ended September 30, 2014, or $2.93 per share on an annualized basis, representing increases of approximately 6% over the previous quarter's dividend and 29% over the dividend for the third quarter of 2013. Total cash dividends of approximately $30.8 million will be paid November 17, 2014 on all outstanding common shares to holders of record as of the close of business on November 3, 2014.

The Company's distributable cash flow for the third quarter 2014 was $31.0 million compared to $31.0 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 Partners Third Quarter 2014 - Capitalization, Liquidity and Financing

Total funded debt of the Partnership as of September 30, 2014 was $3,045.2 million including $575.0 million outstanding under the Partnership's $1.2 billion senior secured revolving credit facility, $237.6 million outstanding under the Partnership's accounts receivable securitization facility, and $2,232.6 million of senior unsecured notes, net of unamortized discounts.

As of September 30, 2014, after giving effect to $42.0 million in outstanding letters of credit, the Partnership had available revolver capacity of $583.0 million and $72.4 million of cash on hand, resulting in total liquidity of $655.4 million.

In October 2014, the Partnership privately placed $800.0 million in aggregate principal amount of 4⅛% senior unsecured notes due 2019 resulting in net proceeds of $791.5 million. The net proceeds were used to reduce borrowings under the Partnership's senior secured credit facility and the accounts receivable securitization facility and for general partnership purposes.

Giving effect to the October 2014 notes offering, the Partnership's pro forma liquidity as of September 30, 2014 was $1,446.9 million.

The Partnership continues to estimate that its total growth capital expenditures for 2014 will be $780.0 million on a gross basis and now estimates that maintenance capital expenditures net to the Partnership's interest will be $80.0 million.

Targa Resources Corp. Third Quarter 2014 - Capitalization, Liquidity and Financing

Total funded debt of the Company as of September 30, 2014, excluding debt of the Partnership, was $92.0 million in borrowings outstanding under its $150.0 million senior secured revolving credit facility due 2017. This resulted in $58.0 million in available revolver capacity as of September 30, 2014.

The Company's cash balance, excluding cash held by the Partnership and its subsidiaries, was $6.4 million as of September 30, 2014, resulting in total liquidity of $64.4 million.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 10:30 a.m. Eastern time (9:30 a.m. Central time) on November 4, 2014 to discuss third quarter 2014 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 92634976. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following the completion of the Webcast through the Investors section of the Partnership's website. An updated investor presentation will also be available in the Events and Presentations section of the Partnership's and the Company's websites following the completion of the conference call.

Targa Resources Partners – Consolidated Financial Results of Operations
Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
($ in millions, except per unit data and operating statistics)
Revenues $ 2,288.3 $ 1,466.1 $ 6,583.7 $ 4,210.5
Product purchases 1,880.5 1,169.0 5,412.2 3,387.9
Gross margin (1) 407.8 297.1 1,171.5 822.6
Operating expenses 112.8 97.6 323.6 279.7
Operating margin (2) 295.0 199.5 847.9 542.9
Depreciation and amortization expenses 87.5 68.9 252.8 198.5
General and administrative expenses 40.4 35.4 115.3 105.7
Other operating (income) expenses (4.3) 4.2 (5.3) 8.3
Income from operations 171.4 91.0 485.1 230.4
Interest expense, net (36.0) (32.6) (104.1) (95.6)
Equity earnings 4.7 5.6 13.8 10.1
Gain (loss) on debt redemptions and amendments -- (7.4) -- (14.7)
Other income (expense) (0.6) 9.1 (0.6) 15.3
Income tax (expense) benefit (1.3) (0.7) (3.7) (2.5)
Net income 138.2 65.0 390.5 143.0
Less: Net income attributable to noncontrolling interests 9.9 5.3 30.9 18.1
Net income attributable to Targa Resources Partners LP $ 128.3 $ 59.7 $ 359.6 $ 124.9
Net income attributable to general partner 38.6 28.1 108.2 76.1
Net income attributable to limited partners 89.7 31.6 251.4 48.8
Net income attributable to Targa Resources Partners LP $ 128.3 $ 59.7 $ 359.6 $ 124.9
Basic net income per limited partner unit $ 0.78 $ 0.30 $ 2.21 $ 0.47
Diluted net income per limited partner unit 0.78 0.30 2.20 0.47
Financial data:
Adjusted EBITDA (3) $ 246.7 $ 155.9 $ 705.1 $ 414.6
Distributable cash flow (4) 192.5 110.8 557.0 275.4
Capital expenditures 142.9 284.5 533.8 727.1
Operating data:
Crude oil gathered, MBbl/d 99.2 52.4 86.0 40.8
Plant natural gas inlet, MMcf/d (5),(6) 2,170.3 2,126.5 2,111.2 2,092.0
Gross NGL production, MBbl/d 157.6 142.3 152.2 135.6
Export volumes, MBbl/d (7) 205.9 55.2 160.5 47.1
Natural gas sales, BBtu/d (6) 923.7 988.0 890.5 930.8
NGL sales, MBbl/d 441.6 303.9 401.6 289.4
Condensate sales, MBbl/d 4.8 3.7 4.4 3.7
__________
(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 attributable to Targa Resources Partners LP before: interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and debt redemptions, early debt extinguishments and asset disposals, non-cash risk management activities related to derivative instruments and changes in the fair value of the Badlands acquisition contingent consideration and the non-controlling interest portion of depreciation and amortization expenses. 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 risk management activities related to derivative instruments, debt repurchases, and redemptions, early debt extinguishments and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs) and changes in the fair value of the Badlands acquisition contingent consideration. 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, other than in Badlands, where it represents total wellhead gathered volumes.
(6) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
(7) Export volumes represent the quantity of NGL products delivered to third party customers at our Galena Park Marine terminal that are destined for international markets.

Targa Resources Partners – Review of Consolidated Third Quarter Results

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

Revenues, including the impact of hedging, increased primarily due to higher NGL and condensate volumes ($598.8 million), higher NGL and natural gas commodity sales prices ($123.2 million) and higher fee-based and other revenues ($141.6 million).

Higher consolidated gross margin in 2014 reflects increased export activities and higher fractionation fees in our Logistics and Marketing segments and increased Field Gathering and Processing throughput volumes associated with system expansions, as well as higher natural gas prices. This significant growth in our asset base brought a higher level of operating expenses in 2014. See "Targa Resources Partners – Review of Segment Performance" for additional information regarding changes in gross margin and operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses reflects increased amortization of the Badlands intangible assets and higher depreciation related to major organic investments placed in service during the last twelve months, including continuing development at Badlands, the international export expansion project, High Plains and Longhorn plants and CBF Train 4 and other system expansions.

Higher general and administrative expenses reflect increased compensation related costs to support our expanding business operations.

The decrease in other operating expense primarily relates to losses on asset disposals recorded in 2013, compared to a gain on an insurance settlement recorded in 2014.

The increase in interest expense was primarily driven by lower capitalized interest allocated to our major expansion projects and higher outstanding borrowings, partially offset by lower overall interest rates.

Losses on debt redemptions and amendments during 2013 were attributable to premiums paid and write-offs of debt issue costs in connection with a partial redemption of the 6⅜% Notes.

The other income in 2013 was attributable to the reduction of the contingent consideration liability associated with the Badlands acquisition.

Net income attributable to noncontrolling interests increased as our joint ventures experienced higher earnings in 2014.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

The changes in our results of operations for the nine months were primarily driven by the same factors as the three month factors noted above. Revenues, including the impact of hedging, increased due to higher NGL and condensate volumes ($1,396.6 million), higher natural gas and NGL commodity sales prices ($717.8 million) and higher fee-based and other revenues ($362.2 million).

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 during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.

The Partnership reports its operations in two divisions: (i) 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.

Field Gathering and Processing

The Field Gathering and Processing segment's assets are located in North Texas, the Permian Basin of West Texas and New Mexico and North Dakota.

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,
2014 2013 2014 2013
($ in millions, except operating statistics and price amounts)
Gross margin $ 145.6 $ 113.5 $ 428.7 $ 315.3
Operating expenses 47.6 42.9 138.9 123.5
Operating margin $ 98.0 $ 70.6 $ 289.8 $ 191.8
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Sand Hills 166.7 153.4 164.4 156.0
SAOU (4) 207.0 163.9 183.4 152.8
North Texas System (5) 361.8 310.9 350.3 287.7
Versado 172.2 159.3 165.9 163.6
Badlands (6) 44.9 18.0 39.2 18.3
952.6 805.5 903.2 778.4
Gross NGL production, MBbl/d (3)
Sand Hills 17.6 17.9 18.1 17.6
SAOU 25.9 23.7 25.1 22.4
North Texas System 39.7 31.8 36.9 30.9
Versado 22.0 19.6 20.8 19.9
Badlands 4.0 1.8 3.5 1.7
109.2 94.8 104.4 92.5
Crude oil gathered, MBbl/d 99.2 52.4 86.0 40.8
Natural gas sales, BBtu/d (3) 478.7 404.4 453.4 374.5
NGL sales, MBbl/d 82.4 72.4 79.5 70.1
Condensate sales, MBbl/d 3.9 3.5 3.6 3.4
Average realized prices (7):
Natural gas, $/MMBtu 3.80 3.32 4.21 3.46
NGL, $/gal 0.75 0.78 0.79 0.73
Condensate, $/Bbl 85.08 101.93 88.17 93.11
________
(1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.
(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 and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
(4) Includes volumes from the 200 MMcf/d cryogenic High Plains plant which started commercial operations in June 2014.
(5) Includes volumes from the 200 MMcf/d cryogenic Longhorn plant which started commercial operations in May 2014.
(6) Badlands natural gas inlet represents the total wellhead gathered volume.
(7) Average realized prices exclude the impact of hedging settlements presented in Other.

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

Gross margin improvements in Field Gathering and Processing were fueled by expansion-driven throughput increases and higher natural gas sales prices partially offset by lower NGL and condensate sales prices. The increase in plant inlet volumes was driven by system expansions and by increased producer activity which increased available supply across our areas of operation. The third quarter of 2014 also benefited from the start-up of commercial operations in May at the Longhorn Plant in North Texas and in June at the High Plains Plant in SAOU. Operational issues affected Sand Hills and Versado volumes although to a lesser extent in comparison to the third quarter of 2013. Badlands crude oil and natural gas volumes increased significantly as a result of our continuing investment to expand and improve gathering and gas processing capabilities. Higher NGL sales reflect our expanding operations.

Higher operating expenses were driven by volume growth and system expansions and included additional labor costs, ad valorem taxes and compression and system maintenance expenses.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

The nine month results were impacted by the same factors as discussed above for the three month comparison of 2014 to 2013 with the addition of higher NGL sales prices and the impact of severe cold weather in the first quarter of 2014, which constrained throughput volumes and increased operating expenses. Higher NGL sales were also affected by the CBF planned curtailment during the second and third quarter of 2013 which resulted in a temporary build of y-grade inventory.

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, accessing natural gas from the Gulf Coast and the Gulf of Mexico. With the strategic location of its assets in Louisiana, the Partnership has access to the Henry Hub, the largest natural gas hub in the U.S., and to 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,
2014 2013 2014 2013
($ in millions, except operating statistics and price amounts)
Gross margin $ 32.3 $ 33.6 $ 102.2 $ 96.1
Operating expenses 13.2 12.5 35.2 34.9
Operating margin $ 19.1 $ 21.1 $ 67.0 $ 61.2
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
LOU 293.1 354.8 308.4 338.0
VESCO 533.9 505.6 514.9 510.9
Other Coastal Straddles 390.9 466.1 384.7 469.5
1,217.9 1,326.5 1,208.0 1,318.4
Gross NGL production, MBbl/d (3)
LOU 9.2 11.3 9.6 9.6
VESCO 27.3 23.0 26.3 20.3
Other Coastal Straddles 11.9 13.2 11.9 13.2
48.4 47.5 47.8 43.1
Natural gas sales, BBtu/d (3) 252.7 294.3 266.5 285.0
NGL sales, MBbl/d 40.8 43.2 41.5 40.0
Condensate sales, MBbl/d 0.7 0.3 0.7 0.4
Average realized prices:
Natural gas, $/MMBtu 4.04 3.61 4.58 3.72
NGL, $/gal 0.80 0.80 0.86 0.82
Condensate, $/Bbl 102.88 107.21 100.04 107.19
__________
(1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.
(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 and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

The decrease in Coastal Gathering and Processing gross margin was primarily due to less favorable frac spread and lower throughput volumes at LOU and the Coastal Straddles partially offset by new higher GPM VESCO throughput volumes. The decrease in plant inlet volumes at LOU and Coastal Straddles was largely attributable to the reduced availability of short-term, higher GPM off-system volumes at LOU and the decline of leaner other off-system supply volumes.

The increase in operating expenses was primarily due to higher system maintenance costs at LOU.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

The increase in Coastal Gathering and Processing gross margin was primarily due to new higher GPM volumes at VESCO, the availability of short-term higher GPM off-system volumes at LOU and higher NGL sales prices partially offset by less favorable frac spread. The decrease in plant inlet volumes was largely attributable to the decline in leaner other off-system supply volumes. Gross NGL production at VESCO during the first nine months of 2013 was impacted by a NGL takeaway pipeline volume constraint.

The increase in operating expenses was primarily due to higher system maintenance costs at LOU.

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, including services for exporting LPG 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 Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas and Lake Charles, Louisiana.

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,
2014 2013 2014 2013
($ in millions, except operating statistics)
Gross margin $ 164.4 $ 100.1 $ 449.1 $ 271.2
Operating expenses 45.8 29.6 125.1 92.3
Operating margin $ 118.6 $ 70.5 $ 324.0 $ 178.9
Operating statistics, MBbl/d (1):
Fractionation volumes (2) 368.6 316.4 342.7 277.2
LSNG treating volumes 24.8 9.6 24.2 18.2
Benzene treating volumes 24.8 8.1 24.2 15.2
_______
(1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.
(2) Fractionation volumes reflect those volumes settled under fractionation contracts, not including reservation fee volumes.

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

Logistics Assets gross margin was significantly higher due to increased LPG export activity and increased fractionation activities, despite the continued impact of ethane rejection. LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 205.9 MBbl/d in the third quarter of 2014 compared to 55.2 MBbl/d for the same period last year. This increase was driven by the first phase of our international export expansion project, which was placed into service September 2013, and by our second phase expansion project which added incremental capacity and operational efficiency in the second quarter of 2014 and became fully operational in the third quarter of 2014. Higher fractionation volumes in the third quarter of 2014 were primarily due to the commencement of CBF Train 4 commercial operations during the third quarter of 2013. Treating volumes were up significantly due to higher customer throughput. Higher gross margin also includes the impact of higher fuel prices which have an offsetting effect in higher operating expenses.

Higher operating expenses reflect the expansion of our export and fractionation facilities and increased power and fuel costs as described above. Partially offsetting these factors were higher system product gains in 2014.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

The nine month results were impacted by the same factors as discussed above for the quarter. LPG export volumes averaged 160.5 MBbl/d for the nine months ended September 2014 compared to 47.1 MBbl/d for the same nine month period of 2013. In addition, the nine months ended September 2014 also included higher reservation fees for both fractionation and LPG export activities.

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 the Partnership's natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing LPG 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; (4) providing propane, butane and services to LPG exporters; and (5) marketing natural gas available to the Partnership from its Gathering and Processing division and the purchase and resale and other value added activities related to third-party 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,
2014 2013 2014 2013
($ in millions, except operating statistics and price amounts)
Gross margin $ 73.8 $ 43.4 $ 217.2 $ 125.5
Operating expenses 12.2 10.9 37.7 31.5
Operating margin $ 61.6 $ 32.5 $ 179.5 $ 94.0
Operating statistics (1):
NGL sales, MBbl/d 444.3 306.7 405.5 291.2
Average realized prices:
NGL realized price, $/gal 0.95 0.88 1.00 0.88
________
(1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

Marketing and Distribution gross margin increased primarily due to higher LPG export activity (which benefits both Logistics Assets and Marketing and Distribution segments), higher barge utilization and higher terminal activity.

Operating expenses increased primarily due to higher barge utilization.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Marketing and Distribution gross margin increased primarily due to higher LPG export activity (which benefits both Logistics Assets and Marketing and Distribution segments), higher Wholesale and NGL marketing activities, higher barge utilization and higher terminal activity. Gross margin during 2014 reflects the impact of a reduced benefit associated with a prior year contract settlement.

Operating expenses increased primarily due to higher barge and railcar utilization and higher terminal activity.

Other

Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
(In millions)
Gross margin $ (2.3) $ 4.8 $ (12.4) $ 17.0
Operating margin $ (2.3) $ 4.8 $ (12.4) $ 17.0

Other contains the financial effects of our hedging program on operating margin as it represents the cash settlements on our derivative contracts. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow. We have hedged the commodity price associated with a portion of our 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 percent of proceeds or liquid processing arrangements by entering into derivative instruments. Because we are essentially forward-selling a portion of our plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

The following table provides a breakdown of the change in Other operating margin:

Three Months Ended September 30, 2014 Three Months Ended September 30, 2013
(In millions, except volumetric data and price amounts)

Volume
Settled
Price
Spread
(1)(2)


Gain (Loss)

Volume
Settled
Price
Spread
(1)(2)


Gain (Loss)
Natural Gas (BBtu) 6.1 $ (0.02) $ (0.1) 3.8 $ 0.94 $ 3.6
NGL (Mgal) 7.3 0.07 0.5 21.8 0.15 3.3
Crude Oil (MMBbl) 0.2 (5.36) (1.1) 0.2 (12.59) (2.4)
Non-Hedge Accounting (3) (1.6) 0.5
Ineffectiveness (4) -- (0.2)
$ (2.3) $ 4.8
Nine Months Ended September 30, 2014 Nine Months Ended September 30, 2013
(In millions, except volumetric data and price amounts)

Volume
Settled
Price
Spread
(1)(2)


Gain (Loss)

Volume
Settled
Price
Spread
(1)(2)


Gain (Loss)
Natural Gas (BBtu) 15.9 $ (0.44) $ (6.9) 8.5 $ 0.96 $ 8.2
NGL (Mgal) 15.9 0.04 0.7 64.8 0.17 11.3
Crude Oil (MMBbl) 0.7 (7.74) (5.3) 0.5 (5.21) (2.6)
Non-Hedge Accounting (3) (1.0) 0.4
Ineffectiveness (4) 0.1 (0.3)
$ (12.4) $ 17.0
______________
(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
(2) Price spread on Natural Gas volumes is $/MMBtu, NGL volumes is $/gal and Crude volumes is $/Bbl.
(3) Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes.
(4) Ineffectiveness primarily relates to certain crude hedging contracts.

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 formed in October 2006 by its parent, Targa Resources Corp., to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. The Partnership is a leading provider of midstream natural gas and natural gas liquid services in the United States. In addition, the Partnership provides crude oil gathering and crude oil and petroleum product terminaling services. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting, terminaling and selling NGLs and NGL products; gathering, storing, and terminaling crude oil; and storing and terminaling petroleum products. The Partnership reports its operations in two divisions: (i) 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.

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 risk management activities related to derivative instruments, debt repurchases and redemptions, early debt extinguishments and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs) and changes in the fair value of the Badlands acquisition contingent consideration. This measure includes any impact of noncontrolling interests.

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 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).

Distributable cash flow is a non-GAAP financial measure. 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. It 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,
2014 2013 2014 2013
(In millions)
Reconciliation of net income attributable to Targa
Resources Partners LP to distributable cash flow:
Net income attributable to Targa Resources Partners LP $ 128.3 $ 59.7 $ 359.6 $ 124.9
Depreciation and amortization expenses 87.5 68.9 252.8 198.5
Deferred income tax expense (benefit) 0.4 -- 1.1 0.8
Amortization in interest expense 2.2 3.8 8.8 11.8
(Gain) loss on debt redemptions and amendments -- 7.4 -- 14.7
Change in contingent consideration -- (9.1) -- (15.3)
(Gain) loss on sale or disposition of assets (4.4) (0.7) (5.6) 3.1
Risk management activities 1.5 (0.3) 0.9 (0.2)
Maintenance capital expenditures (21.9) (17.0) (55.6) (60.5)
Other (1) (1.1) (1.9) (5.0) (2.4)
Targa Resources Partners LP distributable cash flow $ 192.5 $ 110.8 $ 557.0 $ 275.4
_______
(1) Includes the noncontrolling interest portion of maintenance capital expenditures, and depreciation and amortization expenses.

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 and redemptions, early debt extinguishments and asset disposals; non-cash risk management activities related to derivative instruments; changes in the fair value of the Badlands acquisition contingent consideration and the non-controlling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by the Partnership and by external users of the Partnership's financial statements such as investors, commercial banks and others. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.

The 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.

Adjustment EBITDA is a non-GAAP financial measure. 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 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, 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 measure and incorporating these insights into its decision-making processes.

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

Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
(In millions)
Reconciliation of net cash provided by Targa Resources
Partners LP operating activities to Adjusted EBITDA:
Net cash provided by operating activities $ 114.9 $ 99.5 $ 571.8 $ 295.2
Net income attributable to noncontrolling interests (9.9) (5.3) (30.9) (18.1)
Interest expense, net (1) 33.9 28.8 95.3 83.8
Current income tax expense (benefit) 0.9 0.7 2.6 1.7
Other (2) (6.8) (10.4) (20.7) (16.7)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivables, inventories and other assets 114.8 124.9 155.9 93.4
Accounts payable and other liabilities (1.1) (82.3) (68.9) (24.7)
Targa Resources Partners LP Adjusted EBITDA $ 246.7 $ 155.9 $ 705.1 $ 414.6
_________
(1) Net of amortization of debt issuance costs, discount and premium included in interest expense of $2.1 million and $3.8 million for the three months ended September 30, 2014 and 2013, and $8.8 million and $11.8 million for the nine months ended September 30, 2014 and 2013.
(2) Includes equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock-based compensation and noncontrolling interest portion of depreciation and amortization expenses.

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,
2014 2013 2014 2013
(In millions)
Reconciliation of net income attributable to
Targa Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP $ 128.3 $ 59.7 $ 359.6 $ 124.9
Interest expense, net 36.0 32.6 104.1 95.6
Income tax expense (benefit) 1.3 0.7 3.7 2.5
Depreciation and amortization expenses 87.5 68.9 252.8 198.5
(Gain) loss on sale or disposition of assets (4.4) (0.7) (5.6) 3.1
(Gain) loss on debt redemptions and amendments -- 7.4 -- 14.7
Change in contingent consideration -- (9.1) -- (15.3)
Risk management activities 1.5 (0.3) 0.9 (0.2)
Noncontrolling interests adjustment (1) (3.5) (3.3) (10.4) (9.2)
Targa Resources Partners LP Adjusted EBITDA $ 246.7 $ 155.9 $ 705.1 $ 414.6
__________
(1) Noncontrolling interest portion of depreciation and amortization expenses.

Gross MarginThe Partnership defines gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as the Partnership's contract mix and commodity hedging program. The Partnership defines Gathering and Processing gross margin as total operating revenues from (1) the sale of natural gas, condensate, crude and NGLs, (2) natural gas and crude oil gathering and service fee revenues and (3) settlement gains and losses on commodity hedges, less product purchases, which consist primarily of producer payments and other natural gas and crude purchases. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees, NGL and natural gas sales, less cost of sales, which consists primarily of NGL and natural gas 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 definitions 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,
2014 2013 2014 2013
(In millions)
Reconciliation of Targa Resources Partners LP gross
margin and operating margin to net income:
Gross margin $ 407.8 $ 297.1 $ 1,171.5 $ 822.6
Operating expenses (112.8) (97.6) (323.6) (279.7)
Operating margin 295.0 199.5 847.9 542.9
Depreciation and amortization expenses (87.5) (68.9) (252.8) (198.5)
General and administrative expenses (40.4) (35.4) (115.3) (105.7)
Interest expense, net (36.0) (32.6) (104.1) (95.6)
Income tax (expense) benefit (1.3) (0.7) (3.7) (2.5)
Gain (loss) on sale or disposition of assets 4.4 0.7 5.6 (3.1)
Gain (loss) on debt redemptions and amendments -- (7.4) -- (14.7)
Change in contingent consideration -- 9.1 -- 15.3
Other, net 4.0 0.7 12.9 4.9
Targa Resources Partners LP net income $ 138.2 $ 65.0 $ 390.5 $ 143.0

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 tables present a reconciliation of net income of Targa Resources Corp. to distributable cash flow, and 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,
2014 2013 2014 2013
(In millions)
Reconciliation of Net Income attributable to
Targa Resources Corp. to Distributable Cash Flow
Net income of Targa Resources Corp. $ 120.4 $ 49.4 $ 330.7 $ 105.6
Less: Net income of Targa Resources Partners LP (138.2) (65.0) (390.5) (143.0)
Net loss for TRC Non-Partnership (17.8) (15.6) (59.8) (37.4)
TRC Non-Partnership income tax expense 14.2 12.3 49.9 27.8
Distributions from the Partnership (1) 48.9 38.6 139.2 107.5
Non-cash loss (gain) on hedges -- 0.1 -- 0.2
Depreciation - Non-Partnership assets 0.1 0.1 0.3 0.2
Current cash tax expense (2) (17.3) (1.9) (51.4) (15.2)
Taxes funded with cash on hand (3) 2.9 1.9 8.8 6.9
Distributable cash flow $ 31.0 $ 35.5 $ 87.0 $ 90.0
________
(1) Includes current quarter distributions.
(2) 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, 2014 and 2013, and includes $(2.0) million and $0.3 million adjustments to account for differences between taxes from cash available to distribute and book taxes for the three and nine months ended September 30, 2014.
(3) Current period portion of amount established at our IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes.
Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
(In millions)
Targa Resources Corp. Distributable Cash Flow
Distributions declared by Targa Resources Partners LP associated with:
General Partner Interests $ 2.6 $ 2.2 $ 7.5 $ 6.1
Incentive Distribution Rights 36.0 26.9 101.4 73.6
Common Units 10.3 9.5 30.3 27.8
Total distributions declared by Targa Resources Partners LP 48.9 38.6 139.2 107.5
Income (expenses) of TRC Non-Partnership
General and administrative expenses (2.6) (2.3) (7.1) (6.8)
Interest expense, net (0.9) (0.8) (2.4) (2.3)
Current cash tax expense (1) (17.3) (1.9) (51.4) (15.2)
Taxes funded with cash on hand (2) 2.9 1.9 8.8 6.9
Other income (expense) -- -- (0.1) (0.1)
Distributable cash flow $ 31.0 $ 35.5 $ 87.0 $ 90.0
__________
(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, 2014 and 2013, and includes $(2.0) million and $0.3 million adjustments to account for differences between taxes from cash available to distribute and book taxes for the three and nine months ended September 30, 2014.
(2) Current period portion of amount established at our 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, 2014 December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents $ 72.4 $ 57.5
Trade receivables 697.9 658.6
Inventories 251.2 150.7
Assets from risk management activities 5.0 2.0
Other current assets 7.4 7.1
Total current assets 1,033.9 875.9
Property, plant and equipment, net 4,689.4 4,345.4
Intangible assets, net 607.3 653.4
Long-term assets from risk management activities 1.7 3.1
Other long-term assets 84.9 93.6
Total assets $ 6,417.2 $ 5,971.4
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities $ 805.4 $ 773.6
Liabilities from risk management activities 3.6 8.0
Total current liabilities 809.0 781.6
Long-term debt 3,045.2 2,905.3
Long-term liabilities from risk management activities 1.2 1.4
Other long-term liabilities 70.4 64.7
Owners' equity:
Targa Resources Partners LP owner's equity 2,326.7 2,057.8
Noncontrolling interests in subsidiaries 164.7 160.6
Total owners' equity 2,491.4 2,218.4
Total liabilities and owners' equity $ 6,417.2 $ 5,971.4
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,
2014 2013 2014 2013
REVENUES $ 2,288.3 $ 1,466.1 $ 6,583.7 $ 4,210.5
Product purchases 1,880.5 1,169.0 5,412.2 3,387.9
Operating expenses 112.8 97.6 323.6 279.7
Depreciation and amortization expenses 87.5 68.9 252.8 198.5
General and administrative expenses 40.4 35.4 115.3 105.7
Other operating (income) expenses (4.3) 4.2 (5.3) 8.3
Total costs and expenses 2,116.9 1,375.1 6,098.6 3,980.1
INCOME FROM OPERATIONS 171.4 91.0 485.1 230.4
Other income (expense):
Interest expense, net (36.0) (32.6) (104.1) (95.6)
Equity earnings 4.7 5.6 13.8 10.1
Gain (loss) on debt redemptions and amendments -- (7.4) -- (14.7)
Other expense (0.6) 9.1 (0.6) 15.3
Income before income taxes 139.5 65.7 394.2 145.5
Income tax (expense) benefit (1.3) (0.7) (3.7) (2.5)
NET INCOME 138.2 65.0 390.5 143.0
Less: Net income attributable to noncontrolling interests 9.9 5.3 30.9 18.1
NET INCOME ATTRIBUTABLE TO TARGA
RESOURCES PARTNERS LP $ 128.3 $ 59.7 $ 359.6 $ 124.9

Net income attributable to general partner $ 38.6 $ 28.1 $ 108.2 $ 76.1
Net income attributable to limited partners 89.7 31.6 251.4 48.8
Net income attributable to Targa Resources Partners LP $ 128.3 $ 59.7 $ 359.6 $ 124.9
Net income per limited partner unit - basic $ 0.78 $ 0.30 $ 2.21 $ 0.47
Net income per limited partner unit - diluted 0.78 0.30 2.20 0.47
Weighted average limited partner units outstanding - basic 115.1 106.7 113.9 104.2
Weighted average limited partner units outstanding - diluted 115.7 107.0 114.5 104.4
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED CASH FLOW INFORMATION
(In millions)
Nine Months Ended September 30,
2014 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 390.5 $ 143.0
Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization in interest expense 8.8 11.8
Compensation on equity grants 7.0 4.4
Depreciation and amortization expense 252.8 198.5
Accretion of asset retirement obligations 3.3 3.0
Deferred income tax expense (benefit) 1.1 0.8
Equity earnings of unconsolidated affiliate (13.8) (10.1)
Distributions of unconsolidated affiliate 13.8 10.1
Risk management activities 0.9 (0.2)
(Gain) loss on sale or disposal of assets (5.6) 3.1
(Gain) loss on debt redemptions and amendments -- 14.7
Changes in operating assets and liabilities (87.0) (83.9)
Net cash provided by operating activities 571.8 295.2
CASH FLOWS FROM INVESTING ACTIVITIES
Outlays for property, plant and equipment (571.7) (727.1)
Return of capital from unconsolidated affiliate 4.2 1.9
Other, net 6.3 (31.3)
Net cash used in investing activities (561.2) (756.5)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility 1,295.0 1,118.0
Repayments of credit facility (1,115.0) (1,338.0)
Proceeds from issuance of senior notes -- 625.0
Borrowings from accounts receivable securitization facility 88.9 261.6
Repayments of accounts receivable securitization facility (131.0) (93.6)
Redemption of senior notes -- (183.2)
Costs incurred in connection with financing arrangements (2.7) (13.6)
Repurchase of common units under compensation plans (4.8) --
Proceeds from equity offerings and general partner contributions 265.1 385.7
Distributions (364.4) (288.8)
Contributions from noncontrolling interests -- 4.2
Distributions to noncontrolling interests (26.8) (9.9)
Net cash provided by (used in) financing activities 4.3 467.4
Net change in cash and cash equivalents 14.9 6.1
Cash and cash equivalents, beginning of period 57.5 68.0
Cash and cash equivalents, end of period $ 72.4 $ 74.1
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,
2014 2013 2014 2013
REVENUES $ 2,288.3 $ 1,466.0 $ 6,583.7 $ 4,210.3
Product purchases 1,880.5 1,169.0 5,412.2 3,387.9
Operating expenses 112.8 97.6 323.7 279.8
Depreciation and amortization expenses 87.6 69.0 253.1 198.7
General and administrative expenses 43.0 37.7 122.4 112.5
Other operating income (4.3) 4.2 (5.3) 8.3
Total costs and expenses 2,119.6 1,377.5 6,106.1 3,987.2
INCOME FROM OPERATIONS 168.7 88.5 477.6 223.1
Other income (expense):
Interest expense, net (36.9) (33.4) (106.5) (97.9)
Equity earnings 4.7 5.6 13.8 10.1
Gain (loss) on debt redemption and amendments -- (7.4) -- (14.7)
Other (0.6) 9.1 (0.6) 15.3
Income before income taxes 135.9 62.4 384.3 135.9
Income tax (expense) benefit (15.5) (13.0) (53.6) (30.3)
NET INCOME 120.4 49.4 330.7 105.6
Less: Net income attributable to noncontrolling interests 89.7 33.1 253.9 61.0
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 30.7 $ 16.3 $ 76.8 $ 44.6
Net income available per common share - basic $ 0.73 $ 0.39 $ 1.83 $ 1.07
Net income available per common share - diluted $ 0.73 $ 0.39 $ 1.82 $ 1.06
Weighted average shares outstanding - basic 42.0 41.6 42.0 41.6
Weighted average shares outstanding - diluted 42.1 42.1 42.1 42.1
TARGA RESOURCES CORP.
FINANCIAL SUMMARY (unaudited)
KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS
(In millions)
September 30, 2014
Cash and cash equivalents:
TRC Non-Partnership $ 6.4
Targa Resources Partners 72.4
Total cash and cash equivalents $ 78.8
Long-term debt:
TRC Non-Partnership $ 92.0
Targa Resources Partners 3,045.2
Total long-term debt $ 3,137.2

CONTACT: Contact investor relations by phone at (713) 584-1133. Jennifer Kneale Director - Finance Matthew Meloy Senior Vice President, Chief Financial Officer and Treasurer

Source:Targa Resources Partners LP