Exhibit 99.1

 

Targa Resources Partners LP and Targa Resources Corp. Report

Second Quarter 2013 Financial Results

HOUSTON – August 1, 2013 - Targa Resources Partners LP (NYSE: NGLS) (“Targa Resources Partners” or the “Partnership”) and Targa Resources Corp. (NYSE: TRGP) (“TRC” or the “Company”) today reported second quarter 2013 results. Second quarter 2013 net income attributable to Targa Resources Partners was $26.3 million compared to $46.8 million for the second quarter of 2012. The Partnership reported earnings before interest, income taxes, depreciation and amortization and other non-cash items (“Adjusted EBITDA”) of $126.5 million for the second quarter of 2013 compared to $122.9 million for the second quarter of 2012.

The Partnership’s distributable cash flow for the second quarter 2013 of $79.0 million corresponds to distribution coverage of approximately 0.8 times the $102.4 million in total distributions to be paid on August 15, 2013 (see the section of this release entitled “Targa Resources Partners - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, gross margin, operating margin and distributable cash flow, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”)).

“We saw higher volumes across all of our Field Gathering & Processing systems as a result of the continued increase in producer activity in the Permian Basin, North Texas and the Bakken. The combination of higher volumes, increased margin from our downstream segment and strong fee-based margin contributions resulted in an increase in Adjusted EBITDA compared to the second quarter last year, despite significantly lower natural gas liquids prices in the quarter,” said Joe Bob Perkins, Chief Executive Officer of the general partner of the Partnership and of Targa Resources Corp. “We are excited about adding even more scale, diversity and fee-based margin to our business during the third and fourth quarters as we bring on contributions from our 100 MBbl/d Cedar Bayou Fractionator Train 4 expansion and our export expansion at Galena Park. These projects are part of the $1.7 billion in organic growth investments that will support continued distribution growth even in a challenging natural gas liquids price environment.”

On July 16, 2013, the Partnership announced a cash distribution for the second quarter 2013 of $0.7150 per common unit, or $2.86 per unit on an annualized basis, representing an increase of approximately 3% over the first quarter 2013 and 11% over the distribution for the second quarter 2012. The cash distribution will be paid on August 14, 2013 on all outstanding common units to holders of record as of the close of business on July 29, 2013. The total distribution paid will be $102.4 million, with $66.5 million to the Partnership’s third-party limited partners and $35.9 million to TRC for its ownership of common units, incentive distribution rights (“IDRs”) and its 2% general partner interest in the Partnership.

Targa Resources Partners - Capitalization, Liquidity and Financing Update

Total funded debt at the Partnership as of June 30, 2013 was $2,650.0 million including $225.0 million outstanding under the Partnership’s $1.2 billion senior secured revolving credit facility, $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, $300.0 million of 6 ³/₈% senior unsecured notes due 2022, $600.0 million of 5 ¹/₄% senior unsecured notes due 2023, $625 million of 4 ¹/₄% senior unsecured notes due 2023, $125.3 million outstanding under our accounts receivable securitization facility due 2014 and $31.6 million of unamortized discounts.

As of June 30, 2013, after giving effect to $47.9 million in outstanding letters of credit, the Partnership had available revolver capacity of $927.1 million and $72.7 million of cash, resulting in total liquidity of $999.8 million.

In May 2013, the Partnership privately placed $625 million of 4 ¹/₄% senior unsecured notes due 2023. Proceeds were used to reduce borrowings under the Partnership’s senior secured revolving credit facility and for general partnership purposes.

In June 2013 the Partnership paid $106.4 million plus accrued interest to redeem $100 million of the outstanding 6 ³/₈% senior unsecured notes due 2022.

During the six months ended June 30, 2013, the Partnership issued 5,971,395 common units representing net proceeds of approximately $260.3 million from equity issuances under equity distribution agreements, which allow the Partnership to periodically issue equity at prevailing market prices, less a commission. TRC also contributed $5.4 million to maintain its 2% general partnership interest.

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In July, 2013, the Partnership redeemed the outstanding principal amount of the 11 ¹/₄% senior unsecured notes due 2017 for $80.9 million, including accrued interest.

The Partnership estimates that its total growth capital expenditures for 2013 will be approximately $1.0 billion on a gross basis, and that maintenance capital expenditures net to the Partnership’s interest will be $85 million.

Targa Resources Corp. - Second Quarter 2013 Financial Results

Targa Resources Corp., the parent of Targa Resources Partners, reported its second quarter 2013 results. The Company, which as of June 30, 2013 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.

TRC reported net income available to common shareholders of $15.0 million for the second quarter 2013 compared with a net income available to common shareholders of $8.6 million for the second quarter 2012. The net income per diluted common share was $0.36 in the second quarter of 2013 compared to $0.21 for the second quarter of 2012.

Second quarter 2013 distributions to be paid on August 14, 2013 by the Partnership to the Company will be $35.9 million, with $9.3 million, $24.6 million and $2.0 million paid with respect to common units, IDRs and general partner interests, respectively.

On July 16, 2013, TRC declared a quarterly dividend of $0.5325 per share of its common stock for the three months ended June 30, 2013, or $2.13 per share on an annualized basis, representing increases of approximately 8% over the previous quarter’s dividend and 35% over the dividend for the second quarter of 2012. Total cash dividends of approximately $22.1 million will be paid August 15, 2013 on all outstanding common shares to holders of record as of the close of business on July 29, 2013.

The Company’s distributable cash flow for the second quarter 2013 was $29.5 million compared to $22.5 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 June 30, 2013, excluding debt of the Partnership, was $78 million in borrowings outstanding under its $150.0 million senior secured revolving credit facility due 2017. This resulted in $72.0 million in available revolver capacity as of June 30, 2013.

The Company’s cash balance, excluding cash held by the Partnership and its subsidiaries, was $10.2 million as of June 30, 2013, resulting in total liquidity of $82.2 million.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) on August 1, 2013 to discuss second quarter 2013 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 17364562. 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. An updated investor presentation will be available in the Events and Presentations section of the Partnership’s website following the completion of the conference call.

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Targa Resources Partners – Consolidated Financial Results of Operations

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		(In millions except per unit data)
Revenues		$	1,441.6			$	1,318.4			$	2,839.5			$	2,963.9
Product purchases			1,176.4				1,074.6				2,313.9				2,458.7
Gross margin (1)			265.2				243.8				525.6				505.2
Operating expenses			96.1				77.2				182.1				148.8
Operating margin (2)			169.1				166.6				343.5				356.4
Depreciation and amortization expenses			65.7				47.6				129.6				94.3
General and administrative expenses			36.1				33.5				70.3				66.4
Other operating expense			4.1				—				4.2				(0.1	)
Income from operations			63.2				85.5				139.4				195.8
Interest expense, net			(31.6	)			(29.4	)			(63.0	)			(58.8	)
Equity earnings			2.9				(0.2	)			4.5				1.9
Loss on debt redemption and early debt extinguishment			(7.4	)			—				(7.4	)			—
Other			6.5				(0.4	)			6.3				(0.5	)
Income tax expense			(0.9	)			(0.8	)			(1.8	)			(1.8	)
Net income			32.7				54.7				78.0				136.6
Less: Net income attributable to noncontrolling interests			6.4				7.9				12.8				19.6
Net income attributable to Targa Resources Partners LP		$	26.3			$	46.8			$	65.2			$	117.0
Net income attributable to general partner			25.1				15.4				47.9				29.5
Net income attributable to limited partners			1.2				31.4				17.3				87.5
Net income attributable to Targa Resources Partners LP		$	26.3			$	46.8			$	65.2			$	117.0
Basic net income per limited partner unit		$	0.01			$	0.35			$	0.17			$	0.99
Diluted net income per limited partner unit			0.01				0.35				0.17				0.99
Financial data:
Adjusted EBITDA (3)		$	126.5			$	122.9			$	258.8			$	268.3
Distributable cash flow (4)			79.0				84.5				164.7				190.2
Capital expenditures			235.7				140.4				442.6				238.4
Operating data:
Crude oil gathered, MBbl/d			38.3				—				34.9				—
Plant natural gas inlet, MMcf/d (5)(6)			2,072.2				2,083.0				2,075.6				2,157.8
Gross NGL production, MBbl/d			131.2				124.0				132.3				128.1
Export volumes, MBbl/d			41.2				28.0				43.0				25.1
Natural gas sales, BBtu/d (6)			953.1				930.3				901.7				895.4
NGL sales, MBbl/d			282.7				270.3				282.0				274.7
Condensate sales, MBbl/d			4.0				3.7				3.7				3.4

 

(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 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. 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 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.

(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 Second Quarter Results

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

The increase in revenues reflected higher realized prices on natural gas and condensate ($148.8 million), higher commodity sales volumes ($50.7 million) and higher fee-based and other revenues ($19.8 million). Partially offsetting these favorable factors was lower realized prices on NGLs ($96.1 million).

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The increase in consolidated gross margin was driven by volume expansions and higher natural gas price in our Field Gathering and Processing segment and higher fractionation fees and increased exports activities in our Logistics and Marketing division. Offsetting these favorable factors were the effects of lower NGL prices and lower system volumes in our Coastal Gathering and Processing segment. Logistics margins were partially constrained by the planned maintenance and inspection turnaround at Cedar Bayou Fractionators (CBF). Higher operating expenses were driven by system expansions in Field Gathering and Processing, growth projects in Logistics, the Badlands acquisition and higher labor and maintenance costs. 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 Badlands acquisition, system expansions and other assets placed in service during the last twelve months.

General and administrative expenses increased primarily due to higher compensation and benefits.

The increase in interest expense reflects higher borrowing levels to fund our business expansion ($8.0 million), offset by higher interest capitalized on major capital projects ($5.9 million).

The June 2013 redemption of $100 million of the outstanding 6 ³/₈% Notes at a redemption price of 106.375% plus accrued interest resulted in a $7.4 million loss, consisting of a premium paid of $6.4 million and the write-off of $1.0 million of unamortized debt issue costs.

The decrease in net income attributable to noncontrolling interests reflects the impact of lower earnings at the non-wholly owned upstream consolidated subsidiaries, primarily at our Versado and VESCO joint ventures, which were affected by operational issues.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

The decrease in revenues reflects lower realized prices, especially during the first quarter of 2013, on NGLs ($418.2 million), which were partially offset by the impact of higher realized prices on natural gas and condensate ($197.5 million), the impact of higher commodity volumes ($51.6 million) and higher fee-based and other revenues ($44.7 million).

The increase in consolidated gross margin for the six months was driven by the same factors as discussed above for the three months.

The increase in depreciation and amortization expenses was primarily due to the Badlands acquisition, system expansions and other assets placed in service during the last twelve months.

General and administrative expenses increased primarily due to compensation and benefits.

The increase in interest expense reflects higher borrowing levels to fund our business expansion ($11.8 million) and higher effective interest rates ($2.6 million), offset by higher interest capitalized on major capital projects ($10.2 million).

The June 2013 6 ³/₈% Notes redemption noted above resulted in a $7.4 million loss on debt redemption.

The decrease in net income attributable to noncontrolling interests reflects the impact of lower earnings at our non-wholly owned upstream consolidated subsidiaries, primarily at our Versado and VESCO joint ventures, which were affected by operational issues.

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) 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.

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Field Gathering and Processing

The Field Gathering and Processing segment’s assets are located in North Texas and the Permian Basin on West Texas and New Mexico. With the Badlands acquisition on December 31, 2012, this segment’s assets now include the Badlands crude oil and natural gas gathering, terminaling and processing assets in North Dakota.

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

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		($ in millions)
Gross margin		$	110.2			$	85.0			$	201.7			$	187.3
Operating expenses			42.9				31.1				80.6				60.4
Operating margin		$	67.3			$	53.9			$	121.1			$	126.9
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Sand Hills			162.4				130.6				157.4				138.2
SAOU			155.1				121.9				147.2				118.6
North Texas System			290.8				242.7				275.9				233.5
Versado			170.8				169.9				165.8				169.9
Badlands			14.1				—				15.0				—
			793.2				665.1				761.3				660.2
Gross NGL production, MBbl/d
Sand Hills			17.5				15.4				17.5				16.2
SAOU			22.7				18.9				21.7				18.5
North Texas System			32.0				26.8				30.5				25.8
Versado			20.6				20.0				20.0				19.6
Badlands			1.8				—				1.7				—
			94.6				81.1				91.4				80.1
Crude oil gathered, MBbl/d			38.2				—				34.9				—
Natural gas sales, BBtu/d (3)			379.1				312.6				359.3				313.0
NGL sales, MBbl/d			67.3				67.5				69.0				66.2
Condensate sales, MBbl/d			3.6				3.5				3.3				3.2
Average realized prices (4):
Natural gas, $/MMBtu			3.89				2.02				3.53				2.29
NGL, $/gal			0.69				0.86				0.71				0.96
Condensate, $/Bbl			90.58				86.51				88.40				92.34

 

(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 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 June 30, 2013 Compared to Three Months Ended June 30, 2012

The increase in gross margin was primarily due to higher throughput volumes and higher natural gas prices partially offset by lower NGL sales prices. The increase in plant inlet volumes was largely attributable to new well connects across each of our areas of operations. At the same time, volumes at Sand Hills and Versado were constrained by operational issues. NGL sales were flat, impacted by the planned partial curtailment of CBF in May and June 2013 (see Logistics Assets discussion). The planned partial curtailment of CBF also resulted in a temporary build of y-grade inventory, primarily for our third party producer customers, that is expected to be fractionated during the third and fourth quarters.

The increase in operating expenses was primarily due to the addition of Badlands, additional compression related expenses due to increased volumes, system expansions and higher system maintenance and repair costs.

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Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

The six month results were impacted by the same factors as discussed above for the three month comparison of 2013 to 2012.

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 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 June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		($ in millions)
Gross margin		$	28.6			$	38.8			$	62.6			$	95.5
Operating expenses			11.9				10.8				22.5				21.2
Operating margin		$	16.7			$	28.0			$	40.1			$	74.3
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
LOU (4)			317.7				214.7				329.5				204.8
Coastal Straddles			468.0				760.9				471.3				800.2
VESCO			493.3				442.3				513.6				492.6
			1,279.0				1,417.9				1,314.4				1,497.6
Gross NGL production, MBbl/d
LOU			8.4				8.2				8.7				8.2
Coastal Straddles			13.1				15.8				13.3				16.7
VESCO			15.2				18.9				19.0				23.1
			36.7				42.9				41.0				48.0
Natural gas sales, BBtu/d (3)			285.3				315.1				280.2				298.5
NGL sales, MBbl/d			35.3				40.7				38.3				44.0
Condensate sales, MBbl/d			0.3				0.2				0.4				0.2
Average realized prices:
Natural gas, $/MMBtu			4.09				2.27				3.78				2.43
NGL, $/gal			0.81				0.95				0.83				1.06
Condensate, $/Bbl			102.63				91.40				107.19				111.64

 

(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 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)	Includes volumes from the Big Lake processing plant acquired in July 2012.

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

The decrease in gross margin was primarily due to lower NGL 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, the impact of the Yscloskey, Calumet and other third-party plant shutdowns and operational issues at VESCO and LOU. This volume decrease was partially offset by the addition of the Big Lake plant. The operational issues at VESCO included the impact of damage to one of the two third-party pipelines that provide NGL takeaway capacity for VESCO that constrained NGL production until repairs were completed in June. Lower natural gas sales volumes reflected decreased sales to other reportable segments for resale partially offset by an increase in demand from industrial customers.

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

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

The six month results were impacted by the same factors as discussed above for the three month comparison of 2013 to 2012.

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 Gathering and Processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana.

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

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		($ in millions)
Gross margin		$	84.7			$	69.1			$	171.3			$	133.5
Operating expenses			32.6				23.4				62.7				44.8
Operating margin		$	52.1			$	45.7			$	108.6			$	88.7
Operating statistics (1):
Fractionation volumes, MBbl/d			256.6				311.3				257.3				302.5
LSNG treating volumes, MBbl/d			19.4				27.1				22.6				23.1
Benzene treating volumes, MBbl/d			16.9				23.7				18.8				20.4

 

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

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

The increase in gross margin reflects higher revenues from all logistics activities except for treating. Higher fractionation fees more than offset the impact of partially curtailed fractionation volumes associated with the planned maintenance turnaround at CBF. Included in the increase in fractionation gross margin is the impact of higher fuel prices, which pass through to operating expenses. The CBF planned maintenance, which started in May 2013 and was completed in July 2013, primarily addresses Occupational Safety and Health Administration (“OSHA”) Process Safety Management Standards and CBF’s mechanical integrity programs. Export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 41 MBbl/d for the three months ended June 30, 2013, compared to 28 MBbl/d for the same period last year. Export rates were also higher. Storage revenues were higher due to increased rates and new customers. Treating revenues decreased due to reduced market demand. Petroleum Logistics terminaling gross margin improved as a result of increased crude oil throughput, the 2013 start-up of a renewable fuels project, and improved margins.

The increase in operating expenses primarily reflects higher fuel and power prices (which have a corresponding impact on fractionating and treating revenues), expenses related to the commissioning of Train Four at CBF, and increased maintenance costs, partially offset by higher system product gains.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

The six month results were impacted by the same factors as discussed above for the three month comparison of 2013 to 2012.

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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 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 June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		($ in millions)
Gross margin		$	37.2			$	35.4			$	82.0			$	70.8
Operating expenses			9.8				9.2				20.6				18.4
Operating margin		$	27.4			$	26.2			$	61.4			$	52.4
Operating statistics (1):
NGL sales, MBbl/d			282.9				274.4				283.3				278.5
Average realized prices:
NGL realized price, $/gal			0.84				0.92				0.88				1.07

 

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

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Gross margin increased primarily due to higher LPG export activity (which benefited both the Logistics Assets and Marketing and Distribution segments), higher truck and barge utilization and higher wholesale terminal margins, partially offset by lower marketing fees.

Operating expenses increased primarily due to higher truck utilization and increased storage operating costs.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

The six month results were impacted by the same factors as discussed above for the three month comparison of 2013 to 2012.

Other

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		(In millions)
Gross margin		$	5.6			$	12.8			$	12.3			$	14.1
Operating margin		$	5.6			$	12.8			$	12.3			$	14.1

Other contains the financial effects of our hedging program on operating margin. It typically represents the cash settlements on our 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 our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. 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 their percent of proceeds or liquids processing arrangements by entering into derivative instruments.

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The following table provides a breakdown of our hedge revenue by product:

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		(In millions)
Natural gas		$	1.0			$	10.4			$	4.3			$	19.0
NGL			4.5				3.0				8.1				(2.6	)
Crude oil			0.1				(0.6	)			(0.1	)			(2.3	)
		$	5.6			$	12.8			$	12.3			$	14.1

Because the Partnership is essentially forward selling a portion of the plant equity volumes, these hedge positions will move favorably in periods of falling prices and unfavorably in periods of rising 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 formed in October 2006 by its parent, Targa Resources Corp. to own, operate, acquire and develop a diversified portfolio of 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 operates in two primary divisions: Gathering and Processing, consisting of two reportable segments—Field Gathering and Processing and Coastal Gathering and Processing; and Logistics and Marketing, consisting of two reportable segments—Logistics Assets and Marketing and Distribution.

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 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, to the extent unrealized. 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 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).

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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 June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow:
Net income attributable to Targa Resources Partners LP		$	26.3			$	46.8			$	65.2			$	117.0
Depreciation and amortization expenses			65.7				47.6				129.6				94.3
Deferred income tax expense			0.4				0.4				0.8				0.8
Amortization in interest expense			4.0				4.4				8.0				8.9
Loss on debt redemption and early debt extinguishment			7.4				—				7.4				—
Change in contingent consideration			(6.5	)							(6.2	)
Loss on sale or disposition of assets			3.9				—				3.8				—
Risk management activities			0.2				1.2				0.1				2.2
Maintenance capital expenditures			(21.8	)			(15.5	)			(43.4	)			(31.9	)
Other (1)			(0.6	)			(0.4	)			(0.6	)			(1.1	)
Targa Resources Partners LP distributable cash flow		$	79.0			$	84.5			$	164.7			$	190.2

 

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

Adjusted EBITDA - The Partnership defines Adjusted EBITDA as net income 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; and changes in the fair value of the Badlands acquisition contingent consideration. 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 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.

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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 June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		(In millions)
Reconciliation of net cash provided by Targa Resources Partners LP operating activities to Adjusted EBITDA:
Net cash provided by operating activities		$	5.1			$	78.3			$	176.8			$	225.0
Net income attributable to noncontrolling interests			(6.4	)			(7.9	)			(12.8	)			(19.6	)
Interest expense, net (1)			27.6				24.9				55.0				49.7
Loss on debt redemption and early debt extinguishments			(7.4	)			—				(7.4	)			—
Change in contingent consideration			(6.5	)			—				(6.2	)			—
Current income tax expense			0.5				0.4				1.0				1.0
Other (2)			5.2				(4.2	)			1.2				(9.1	)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets			90.0				(50.5	)			(31.5	)			(208.7	)
Accounts payable and other liabilities			18.4				81.9				82.7				230.0
Targa Resources Partners LP Adjusted EBITDA		$	126.5			$	122.9			$	258.8			$	268.3

 

(1)	Net of amortization of debt issuance costs, discount and premium included in interest expense of $4.0 million and $4.4 million for the three months ended June 30, 2013 and 2012, and $8.0 million and $8.9 million for the six months ended June 30, 2013 and 2012.

(2)	Includes equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock-based compensation, gain 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 June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP		$	26.3			$	46.8			$	65.2			$	117.0
Add:
Interest expense, net			31.6				29.4				63.0				58.8
Income tax expense			0.9				0.8				1.8				1.8
Depreciation and amortization expenses			65.7				47.6				129.6				94.3
Loss on sale or disposition of assets			3.9				—				3.8				—
Loss on debt redemption and early debt extinguishments			7.4				—				7.4				—
Change in contingent consideration			(6.5	)			—				(6.2	)			—
Risk management activities			0.2				1.2				0.1				2.2
Noncontrolling interests adjustment (1)			(3.0	)			(2.9	)			(5.9	)			(5.8	)
Targa Resources Partners LP Adjusted EBITDA		$	126.5			$	122.9			$	258.8			$	268.3

 

(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 the Partnership’s contract mix and hedging program. The Partnership defines Gathering and Processing gross margin as total operating revenues from (1) the sale of natural gas, condensate 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 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.

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.

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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 June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		(In millions)
Reconciliation of Targa Resources Partners LP gross margin and operating margin to net income:
Gross margin		$	265.2			$	243.8			$	525.6			$	505.2
Operating expenses			(96.1	)			(77.2	)			(182.1	)			(148.8	)
Operating margin			169.1				166.6				343.5				356.4
Depreciation and amortization expenses			(65.7	)			(47.6	)			(129.6	)			(94.3	)
General and administrative expenses			(36.1	)			(33.5	)			(70.3	)			(66.4	)
Interest expense, net			(31.6	)			(29.4	)			(63.0	)			(58.8	)
Income tax expense			(0.9	)			(0.8	)			(1.8	)			(1.8	)
Gain (loss) on sale or disposition of assets			(3.9	)			—				(3.8	)			0.1
Loss on debt redemption and early debt extinguishments			(7.4	)			—				(7.4	)			—
Change in contingent consideration			6.5				—				6.2				—
Other, net			2.7				(0.6	)			4.2				1.4
Targa Resources Partners LP net income		$	32.7			$	54.7			$	78.0			$	136.6

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

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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 June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		(in millions)
Reconciliation of net income attributable to Targa Resources Corp. to distributable Cash Flow
Net income of Targa Resources Corp.		$	22.5			$	43.5			$	56.2			$	112.6
Less: Net income of Targa Resources Partners LP			(32.7	)			(54.7	)			(78.0	)			(136.6	)
Net loss for TRC Non-Partnership			(10.2	)			(11.2	)			(21.8	)			(24.0	)
TRC Non-Partnership income tax expense			7.1				7.8				15.8				17.0
Distributions from the Partnership			35.9				24.2				68.9				46.4
Non-cash loss (gain) on hedges			0.1				(0.6	)			0.1				(1.0	)
Depreciation - Non-Partnership			—				0.7				0.1				1.4
Current cash tax expense (1)			(5.9	)			(5.8	)			(13.4	)			(12.7	)
Taxes funded with cash on hand (2)			2.5				2.2				5.0				4.4
Targa Resources Corp. distributable cash flow		$	29.5			$	17.3			$	54.7			$	31.5

 

(1)	Excludes $1.2 million and $2.4 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 six months ended June 30, 2013 and 2012.

(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.

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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 June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
		(in millions)
Targa Resources Corp. distributable Cash Flow
Distributions declared by Targa Resources Partners LP associated with:
General Partner Interests		$	2.0			$	1.5			$	3.9			$	2.9
Incentive Distribution Rights			24.6				14.4				46.7				27.1
Common Units			9.3				8.3				18.3				16.4
Total distributions declared by Targa Resources Partners LP			35.9				24.2				68.9				46.4
Income (expenses) of TRC Non-Partnership
General and administrative expenses			(2.3	)			(2.2	)			(4.3	)			(4.4	)
Interest expense, net			(0.8	)			(1.1	)			(1.5	)			(2.2	)
Current cash tax expense (1)			(5.9	)			(5.8	)			(13.4	)			(12.7	)
Taxes funded with cash on hand (2)			2.5				2.2				5.0				4.4
Other income (expense)			0.1				—				—				—
Targa Resources Corp. distributable cash flow		$	29.5			$	17.3			$	54.7			$	31.5

 

(1)	Excludes $1.2 million and $2.4 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 six months ended June 30, 2013 and 2012.

(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.

Contact investor relations by phone at (713) 584-1133.

 

Jennifer Kneale

Director – Finance

Matthew Meloy

Senior Vice President, Chief Financial Officer and Treasurer

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TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

 

CONSOLIDATED BALANCE SHEETS

(In millions)

 

		June 30,				December 31,
		2013				2012
ASSETS
Current assets:
Cash and cash equivalents		$	72.7			$	68.0
Trade receivables			435.9				514.9
Inventories			138.3				99.4
Assets from risk management activities			23.2				29.3
Other current assets			1.8				3.3
Total current assets			671.9				714.9
Property, plant and equipment, net			3,878.6				3,533.2
Other intangible assets, net			667.1				680.8
Long-term assets from risk management activities			5.6				5.1
Other long-term assets			99.4				91.7
Total assets		$	5,322.6			$	5,025.7
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities		$	616.9			$	701.2
Liabilities from risk management activities			3.8				7.4
Total current liabilities			620.7				708.6
Long-term debt			2,650.0				2,393.3
Long-term liabilities from risk management activities			1.8				4.8
Other long-term liabilities			63.4				58.9
Owners’ equity:
Targa Resources Partners LP owner’s equity			1,826.5				1,709.6
Noncontrolling interests in subsidiaries			160.2				150.5
Total owners’ equity			1,986.7				1,860.1
Total liabilities and owners’ equity		$	5,322.6			$	5,025.7

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TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit amounts)

 

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2013				2012				2013				2012
REVENUES		$	1,441.6			$	1,318.4			$	2,839.5			$	2,963.9
Product purchases			1,176.4				1,074.6				2,313.9				2,458.7
Operating expenses			96.1				77.2				182.1				148.8
Depreciation and amortization expenses			65.7				47.6				129.6				94.3
General and administrative expenses			36.1				33.5				70.3				66.4
Other operating (income) expense			4.1				—				4.2				(0.1	)
Total costs and expenses			1,378.4				1,232.9				2,700.1				2,768.1
INCOME FROM OPERATIONS			63.2				85.5				139.4				195.8
Other income (expense):
Interest expense, net			(31.6	)			(29.4	)			(63.0	)			(58.8	)
Equity earnings (loss)			2.9				(0.2	)			4.5				1.9
Loss on debt redemption and early debt extinguishments			(7.4	)			—				(7.4	)			—
Other expense			6.5				(0.4	)			6.3				(0.5	)
Income before income taxes			33.6				55.5				79.8				138.4
Income tax expense (benefit)			(0.9	)			(0.8	)			(1.8	)			(1.8	)
NET INCOME			32.7				54.7				78.0				136.6
Less: Net income attributable to noncontrolling interests			6.4				7.9				12.8				19.6
NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP		$	26.3			$	46.8			$	65.2			$	117.0
Net income attributable to general partner		$	25.1			$	15.4			$	47.9				29.5
Net income attributable to limited partners			1.2				31.4				17.3				87.5
Net income attributable to Targa Resources Partners LP		$	26.3			$	46.8			$	65.2			$	117.0
Net income per limited partner unit - basic		$	0.01			$	0.35			$	0.17			$	0.99
Net income per limited partner unit - diluted			0.01				0.35				0.17				0.99
Weighted average limited partner units outstanding - basic			103.9				89.2				102.9				88.6
Weighted average limited partner units outstanding - diluted			104.2				89.3				103.1				88.7

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TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

 

CONSOLIDATED CASH FLOW INFORMATION

(In millions)

 

		Six Months Ended June 30,
		2013				2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	78.0			$	136.6
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense			8.0				9.1
Compensation on equity grants			3.0				1.6
Depreciation and amortization expense			129.6				94.3
Accretion of asset retirement obligations			2.0				2.0
Deferred income tax expense			0.8				0.8
Equity earnings, net of distributions			(4.5	)			—
Risk management activities			(0.1	)			2.0
Loss on debt redemption and early debt extinguishments			7.4				—
Gain (loss) on sale or disposal of assets			3.8				(0.1	)
Changes in operating assets and liabilities			(51.2	)			(21.3	)
Net cash provided by operating activities			176.8				225.0
CASH FLOWS FROM INVESTING ACTIVITIES
Outlays for property, plant and equipment			(444.5	)			(238.4	)
Investment in unconsolidated affiliate			—				(13.7	)
Other, net			(10.5	)			1.3
Net cash used in investing activities			(455.0	)			(250.8	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility			680.0				325.0
Repayments of credit facility			(1,075.0	)			(683.0	)
Proceeds from issuance of senior notes			625.0				400.0
Redemption of senior notes			(106.4	)			—
Proceeds from accounts receivable securitization facility			207.7				—
Repayments of accounts receivable securitization facility			(82.4	)			—
Costs incurred in connection with financing arrangements			(11.7	)			(4.5	)
Proceeds from equity offerings			235.2				168.4
Distributions to unitholders			(186.4	)			(135.6	)
Contributions from parent			—				0.8
Contributions from noncontrolling interests			4.3				4.8
Distributions to noncontrolling interests			(7.4	)			(16.2	)
Net cash provided by (used in) financing activities			282.9				59.7
Net change in cash and cash equivalents			4.7				33.9
Cash and cash equivalents, beginning of period			68.0				55.6
Cash and cash equivalents, end of period		$	72.7			$	89.5

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TARGA RESOURCES CORP.

FINANCIAL SUMMARY (unaudited)

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
REVENUES		$	1,441.6			$	1,319.1			$	2,839.4			$	2,964.9
Product purchases			1,176.4				1,074.6				2,313.9				2,458.8
Operating expenses			96.1				77.3				182.2				148.9
Depreciation and amortization expenses			65.7				48.3				129.7				95.7
General and administrative expenses			38.4				35.7				74.6				70.8
Other operating (income) expense			4.1				—				4.2				(0.1	)
Total costs and expenses			1,380.7				1,235.9				2,704.6				2,774.1
INCOME FROM OPERATIONS			60.9				83.2				134.8				190.8
Other income (expense):
Interest expense, net			(32.4	)			(30.5	)			(64.5	)			(61.0	)
Equity earnings (loss)			2.9				(0.2	)			4.5				1.9
Loss on debt redemption and early debt extinguishments			(7.4	)			—				(7.4	)			—
Other expenses			6.5				(0.4	)			6.3				(0.3	)
Income before income taxes			30.5				52.1				73.7				131.4
Income tax expense			(8.0	)			(8.6	)			(17.5	)			(18.8	)
NET INCOME			22.5				43.5				56.2				112.6
Less: Net income attributable to noncontrolling interests			7.5				34.9				27.9				94.4
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS		$	15.0			$	8.6			$	28.3			$	18.2
Net income available per common share - basic		$	0.36			$	0.21			$	0.68			$	0.44
Net income available per common share - diluted		$	0.36			$	0.21			$	0.67			$	0.44
Weighted average shares outstanding - basic			41.6				41.0				41.6				41.0
Weighted average shares outstanding - diluted			42.1				41.9				42.0				41.8

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TARGA RESOURCES CORP.

FINANCIAL SUMMARY (unaudited)

 

KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS

(In millions)

 

		June 30, 2013
Cash and cash equivalents:
TRC Non-Partnership		$	10.2
Targa Resources Partners			72.7
Total cash and cash equivalents		$	82.9
Long-term debt:
TRC Non-Partnership		$	78.0
Targa Resources Partners			2,650.0
Total long-term debt		$	2,728.0