EX-99.1

EX-99.1 2 d620976dex991.htm EX-99.1 EX-99.1

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Targa Resources Partners LP and Targa Resources Corp. Report

Third Quarter 2013 Financial Results and Provide Update on Financial Outlook

HOUSTON – November 4, 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 third quarter 2013 results. Third quarter 2013 net income attributable to Targa Resources Partners was $59.7 million compared to $24.2 million for the third quarter of 2012. Net income per diluted limited partner unit was $0.30 in the third quarter of 2013 compared to $0.08 for the third quarter of 2012. The Partnership reported earnings before interest, income taxes, depreciation and amortization and other non-cash items (“Adjusted EBITDA”) of $155.9 million for the third quarter of 2013 compared to $116.2 million for the third quarter of 2012.

The Partnership’s distributable cash flow for the third quarter 2013 of $110.8 million corresponds to distribution coverage of approximately 1.0 times the $108.5 million in total distributions to be paid on November 14, 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 commissioned two large expansion programs this quarter - 100 MBbl/d of additional fractionation capacity with Train 4 at our Cedar Bayou facility plus the addition of over 2 million barrels per month of export capacity at our Galena Park Marine Terminal. These projects contributed to the Partnership’s record third quarter Adjusted EBITDA of $156 million,” said Joe Bob Perkins, Chief Executive Officer of the general partner of the Partnership and of Targa Resources Corp. “We had higher volumes and margin in our Field Gathering & Processing segment, and increased export volumes and margin in our Downstream Business. Our gathering and processing assets, located in some of the most active oil and gas producing basins in the country, combined with a growing and diverse downstream footprint position us well for continued growth.”

On October 21, 2013, the Partnership announced a cash distribution for the third quarter 2013 of $0.7325 per common unit, or $2.93 per unit on an annualized basis, representing an increase of approximately 2% over the second quarter 2013 and 11% over the distribution for the third quarter 2012. The cash distribution will be paid on November 14, 2013 on all outstanding common units to holders of record as of the close of business on October 31, 2013. The total distribution paid will be $108.5 million, with $69.9 million to the Partnership’s third-party limited partners and $38.6 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 2013 Financial Results

Targa Resources Corp., the parent of Targa Resources Partners, today reported its third quarter 2013 results. The Company, which as of September 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 $16.3 million for the third quarter 2013 compared with a net income available to common shareholders of $8.7 million for the third quarter 2012. The net income per diluted common share was $0.39 in the third quarter of 2013 compared to $0.21 for the third quarter of 2012.

Third quarter 2013 distributions to be paid on November 14, 2013 by the Partnership to the Company will be $38.6 million, with $9.5 million, $26.9 million and $2.2 million paid with respect to common units, IDRs and general partner interests, respectively.

On October 21, 2013, TRC declared a quarterly dividend of $0.57 per share of its common stock for the three months ended September 30, 2013, or $2.28 per share on an annualized basis, representing increases of approximately 7% over the previous quarter’s dividend and 35% over the dividend for the third quarter of 2012. Total cash dividends of approximately $23.7 million will be paid November 15, 2013 on all outstanding common shares to holders of record as of the close of business on October 31, 2013.

The Company’s distributable cash flow for the third quarter 2013 was $35.5 million compared to $24.1 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 – Financial Outlook Update

For the full year 2013, assuming current commodity prices, the Partnership expects Adjusted EBITDA to be near the lower end of the guidance range of $595 million to $655 million.

The Partnership estimates that Adjusted EBITDA for 2014 will be approximately $740 million to $760 million. This estimate assumes commodity prices in 2014 of $3.75 per MMBtu for natural gas, $95.00 per barrel for crude oil and average prices for the Partnership’s NGLs of $0.90 per gallon. Under these assumptions, a $0.05 per gallon change in the price of NGLs would correspondingly change 2014 Adjusted EBITDA by approximately 2%. The Partnership expects distribution coverage to be approximately 1.0x in 2014.

Based on the estimated range of Adjusted EBITDA for 2014 and assuming generally stable broader market conditions, the Partnership expects to be in a position to increase distributions per common unit by 7% to 9% in 2014 compared to 2013, subject to approval of the board of directors of the Partnership’s general partner.

These initial estimates for full year 2013, and for 2014, are preliminary estimates and, accordingly, remain subject to changes that could be significant. See the section of this release entitled “Targa Resources Partners - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA and a reconciliation of this measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Growth Projects Update

The Partnership has announced approximately $1.9 billion in growth capital investments that will be placed in service in 2013 through 2014, with approximately 72% of the total for projects expected to provide primarily fee-based margin. The Partnership estimates that total growth capital expenditures for 2014 will be approximately $590 million.

The Partnership expects net maintenance capital expenditures to be approximately $90 million in 2014.

Targa Resources Corp. – Financial Outlook Update

Given the Partnership’s expected distribution growth of 7% to 9% in 2014, TRC expects to be in a position to increase dividends in excess of 25% compared to 2013, subject to the approval of the board of directors of TRC. For 2014, the estimated financial performance of the Partnership is expected to result in cash taxes for TRC equal to approximately 27% of its estimated pre-tax distributable cash flow. TRC’s estimated dividend increases, effective tax rate and the estimated Adjusted EBITDA of the Partnership are based on preliminary estimates and, accordingly, remain subject to changes that could be significant.

Targa Resources Partners Third Quarter 2013 - Capitalization, Liquidity and Financing

Total funded debt at the Partnership as of September 30, 2013 was $2,797.9 million including $400.0 million outstanding under the Partnership’s $1.2 billion senior secured revolving credit facility, $168.0 million outstanding under the Partnership’s accounts receivable securitization facility, and $2,229.9 million of senior unsecured notes, net of unamortized discounts.

As of September 30, 2013, after giving effect to $50.0 million in outstanding letters of credit, the Partnership had available revolver capacity of $750.0 million and $74.1 million of cash on hand, resulting in total liquidity of $824.1 million.

In July 2013, the Partnership paid $76.8 million plus accrued interest to redeem all of its outstanding 11¹⁄₄% Notes.

During the nine months ended September 30, 2013, the Partnership issued a total of 8,349,727 common units representing total net proceeds of $377.4 million from equity issuances under equity distribution agreements, which allow the Partnership to periodically issue equity at prevailing market prices, less a commission. TRC contributed $7.9 million to maintain its 2% general partner interest during this period.

The Partnership estimates that its total growth capital expenditures for 2013 will be approximately $900 million on a gross basis, and that maintenance capital expenditures net to the Partnership’s interest will be $80 million.

Targa Resources Corp. Third Quarter 2013 - Capitalization, Liquidity and Financing

Total funded debt of the Company as of September 30, 2013, excluding debt of the Partnership, was $70.0 million in borrowings outstanding under its $150.0 million senior secured revolving credit facility due 2017. This resulted in $80.0 million in available revolver capacity as of September 30, 2013.

The Company’s cash balance, excluding cash held by the Partnership and its subsidiaries, was $9.6 million as of September 30, 2013, resulting in total liquidity of $89.6 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 November 5, 2013 to discuss third quarter 2013 financial results. The 2013 Investor & Analyst Presentation will begin immediately following the discussion of third quarter results, and will include an update from Management on the Partnership’s business operations and on financial and operational guidance, along with presentation materials that will be posted to the Partnership’s website after the NYSE closes for trading on Monday, November 4, 2013. 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 85694850. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following completion of the Webcast through the Investor’s section of the Partnership’s and the Company’s website.

Targa Resources Partners – Consolidated Financial Results of Operations


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In millions except per unit data)
Revenues	$	1,556.9		$	1,392.9		$	4,396.4		$	4,356.8
Product purchases		1,259.8			1,153.0			3,573.8			3,611.7

Gross margin (1)		297.1			239.9			822.6			745.1
Operating expenses		97.6			78.3			279.7			227.1

Operating margin (2)		199.5			161.6			542.9			518.0
Depreciation and amortization expenses		68.9			47.9			198.5			142.1
General and administrative expenses		35.4			33.5			105.7			100.0
Other operating expense		4.2			18.9			8.3			18.8

Income from operations		91.0			61.3			230.4			257.1
Interest expense, net		(32.6	)		(29.0	)		(95.6	)		(87.8	)
Equity earnings (loss)		5.6			(2.2	)		10.1			(0.3	)
Loss on debt redemption		(7.4	)		—			(14.7	)		—
Other		9.1			(1.1	)		15.3			(1.6	)
Income tax expense		(0.7	)		(0.9	)		(2.5	)		(2.7	)

Net income		65.0			28.1			143.0			164.7
Less: Net income attributable to noncontrolling interests		5.3			3.9			18.1			23.5

Net income attributable to Targa Resources Partners LP	$	59.7		$	24.2		$	124.9		$	141.2

Net income attributable to general partner		28.1			15.4			76.1			46.1
Net income attributable to limited partners		31.6			8.8			48.8			95.1

Net income attributable to Targa Resources Partners LP	$	59.7		$	24.2		$	124.9		$	141.2

Basic net income per limited partner unit	$	0.30		$	0.08		$	0.47		$	1.07

Diluted net income per limited partner unit		0.30			0.08			0.47			1.07

Financial data:
Adjusted EBITDA (3)	$	155.9		$	116.2		$	414.6		$	384.4
Distributable cash flow (4)		110.8			77.2			275.4			267.6
Capital expenditures		284.5			161.5			727.1			399.8

Operating data:
Crude oil gathered, MBbl/d		52.4			—			40.8			—
Plant natural gas inlet, MMcf/d (5)(6)		2,126.5			1,968.6			2,092.0			2,094.3
Gross NGL production, MBbl/d		142.3			123.4			135.6			126.6
Export volumes, MBbl/d		55.2			31.1			47.1			40.8
Natural gas sales, BBtu/d (6)		988.0			981.8			930.8			924.4
NGL sales, MBbl/d		303.9			282.0			289.4			277.1
Condensate sales, MBbl/d		3.7			3.6			3.7			3.5

(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, debt redemptions, early debt extinguishments, 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 Third Quarter Results

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

The increase in revenues primarily reflects higher commodity sales volumes ($77.4 million), higher realized prices on natural gas and condensate ($61.7 million), and higher fee-based and other revenues ($34.4 million).

The increase in consolidated gross margin was driven by increased volumes and higher natural gas prices in our Field Gathering and Processing segment and higher fractionation fees and increased exports activities in our Logistics and Marketing division. These favorable factors were partially offset by lower NGL prices in our Coastal Gathering and Processing segment. Higher operating expenses were driven by system expansions related to new operations in Field Gathering and Processing and of new growth projects in Logistics, costs associated with our Badlands growth and other higher labor and maintenance costs. See “Targa Resources Partners – Review of Segment Performance” for additional information regarding changes in the components of gross and operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses was primarily due to the Badlands acquisition, CBF Train 4, Phase I of the international export expansion project, other system expansions and other assets placed in service during the last twelve months.

General and administrative expenses increased, reflecting increased support for our expanding business operations.

Other operating expense in 2013 includes the Versado joint venture cost of repairs less amounts covered by insurance ($3.7 million) related to a fire at the Saunders plant. Other operating expense in 2012 reflects losses due to Hurricane Isaac, which include the write-off upon closure of the Yscloskey joint interest processing plant and costs associated with the clean-up and repairs necessitated at our other Coastal Straddle plants.

The increase in interest expense primarily reflects higher borrowing levels to fund our business expansion ($9.4 million), offset by lower effective interest rates ($1.9 million) and higher interest capitalized on major capital projects ($4.0 million).

The increase in equity earning relates to our investment in Gulf Coast Fractionators (“GCF”), which turned a profit in 2013 compared to a loss in 2012 due to a planned shutdown of operations associated with its capacity expansion during 2012.

In July 2013, we paid $76.8 million plus accrued interest, which included a premium of $4.1 million, per the terms of the note agreement to redeem the outstanding balance of the 11¹⁄₄% Senior Notes due 2017 (the “11¹⁄₄% Notes”). The redemption resulted in a $7.4 million loss on debt redemption in the third quarter 2013, including the write-off of $1.0 million of unamortized debt issue costs.

The increase in other income was attributable to the elimination of the contingent consideration associated with the Badlands acquisition. The elimination of the contingent liability reflects management’s updated assessment, with only nine months remaining in the contingency period, that we will not meet the stipulated volumetric thresholds.

The increase in net income attributable to noncontrolling interests reflects higher earnings at our CBF and VESCO joint ventures. Our Versado joint venture, which had lower earnings in 2013, was affected by operational issues, including a fire at the Saunders plant in September, which is still under repair.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

The increase in revenues reflects the impact of higher realized prices on natural gas and condensate ($259.3 million), higher commodity volumes ($136.3 million) and higher fee-based and other revenues ($79.2 million), offset by lower realized prices on NGLs ($435.2 million), especially during the first quarter of 2013.

The increase in consolidated gross margin for the nine months was driven by the same factors as discussed above for the three months, partially offset by the planned maintenance and inspection turnaround at CBF for the period from May through July 2013. See “Targa Resources Partners – Review of Segment Performance” for additional information regarding changes in the components of gross and operating margin on a disaggregated basis.

General and administrative expenses increased reflecting increased support for our expanding business operations.

Other operating expense in 2012 relates to the Yscloskey plant closure and Hurricane Isaac repair cost as discussed above.

The increase in interest expense primarily reflects higher borrowing levels to fund our business expansion ($23.0 million) offset by lower effective interest rates ($1.1 million) and higher interest capitalized on major capital projects ($14.2 million).

The increase in equity earnings relates to our investment in GCF, which was profitable in 2013 compared to a loss in 2012 due to a planned shutdown of operations in 2012 related to an expansion of the facility.

The July 2013 11¹⁄₄% Notes redemption noted above combined with the June 2013 6³⁄₈% Notes redemption resulted in $14.7 million in losses on debt redemption for the nine months ended September 30, 2013.

The increase in other income was primarily attributable to the elimination of the contingent consideration liability associated with the Badlands acquisition as described above.

The decrease in net income attributable to noncontrolling interests reflects lower earnings at our Vesco and Versado joint ventures, which were affected by operational issues. This was partially offset by higher earnings at our CBF joint venture.

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.

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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in millions)
Gross margin	$	113.5	$	84.0	$	315.3	$	271.2
Operating expenses		42.9		30.2		123.5		90.6

Operating margin	$	70.6	$	53.8	$	191.8	$	180.6

Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Sand Hills		153.4		154.6		156.0		143.7
SAOU		163.9		126.0		152.8		121.1
North Texas System		310.9		246.5		287.7		237.9
Versado		159.3		159.2		163.6		166.3
Badlands		12.5		—		13.4		—

		799.9		686.3		773.5		669.0

Gross NGL production, MBbl/d
Sand Hills		17.9		17.8		17.6		16.8
SAOU		23.7		19.5		22.4		18.8
North Texas System		31.8		26.6		30.9		26.1
Versado		19.6		19.0		19.9		19.3
Badlands		1.8		—		1.7		—

		94.8		82.9		92.5		81.0

Crude oil gathered, MBbl/d		52.4		—		40.8		—

Natural gas sales, BBtu/d (3)		404.4		333.5		374.5		319.9
NGL sales, MBbl/d		72.4		68.7		70.1		67.1
Condensate sales, MBbl/d		3.5		3.4		3.4		3.3
Average realized prices (4):
Natural gas, $/MMBtu		3.32		2.59		3.46		2.40
NGL, $/gal		0.78		0.79		0.73		0.90
Condensate, $/Bbl		101.93		86.82		93.11		90.40

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

The increase in gross margin was primarily due to higher overall throughput volumes with plant inlets up or flat in every business unit, despite operational issues. Gross margin also increased due to higher natural gas and condensate sales prices, which were partially offset by lower NGL sales prices. The increase in plant inlet volumes was largely attributable to new plant expansions that came on line at the end of 2012 and the first part of 2013 at Sand Hills and SAOU and new well connects, which increased available supply across each of our areas of operations, though throughput was somewhat constrained by operational issues. In the third quarter 2013, we commenced the fractionation of the temporary build of y-grade inventory that resulted from the CBF planned curtailment in the second quarter 2013. We expect to complete the fractionation of this additional y-grade inventory during the fourth quarter.

The increase in operating expenses was primarily due to the inclusion of Badlands operations in 2013 and additional compression related expenses due to increased volumes across our business and system expansions.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

The nine month results were impacted by the same factors as discussed above for the three months, with a larger negative impact from lower NGL prices.

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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in millions)
Gross margin	$	33.6	$	31.7	$	96.1	$	127.2
Operating expenses		12.5		13.7		34.9		34.9

Operating margin	$	21.1	$	18.0	$	61.2	$	92.3

Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
LOU (4)		354.8		324.5		338.0		245.0
Coastal Straddles		466.1		607.7		469.5		735.5
VESCO		505.6		350.0		510.9		444.8

		1,326.5		1,282.2		1,318.5		1,425.3

Gross NGL production, MBbl/d
LOU		11.3		8.9		9.6		8.4
Coastal Straddles		13.2		14.8		13.2		16.0
VESCO		23.0		16.9		20.3		21.1

		47.4		40.6		43.1		45.5

Natural gas sales, BBtu/d (3)		294.3		317.2		285.0		304.8
NGL sales, MBbl/d		43.2		38.4		40.0		42.1
Condensate sales, MBbl/d		0.3		0.2		0.4		0.2
Average realized prices:
Natural gas, $/MMBtu		3.61		2.87		3.72		2.59
NGL, $/gal		0.80		0.85		0.82		0.99
Condensate, $/Bbl		107.21		96.07		107.19		107.17

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

The increase in gross margin was primarily due to higher throughput volumes partially offset by lower NGL prices and less favorable frac spread. The increase in plant inlet volumes was largely attributable to the impact of Hurricane Isaac on production at the Coastal Straddle plants in the third quarter of 2012 and additional Big Lake volumes in 2013. This volume increase was partially offset by the 2013 decline in offshore and off-system supply volumes and the cessation of operations at Yscloskey and other third-party plant shutdowns.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 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, and the impact of the Yscloskey, Calumet and other third-party plant shutdowns. In addition, volumes were constrained by operational issues at VESCO and LOU. This volume decrease was partially offset by the addition of the Big Lake plant in the third quarter 2012 and the resumption of operations after Hurricane Isaac in 2012 at the Coastal Straddle plants. Operational issues at VESCO included the impact of damage to one of the two third-party pipelines that provide NGL takeaway capacity for VESCO which constrained NGL production until repairs were completed in June 2013.

Operating expenses were flat.

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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in millions)
Gross margin	$	100.1	$	74.5	$	271.2	$	208.0
Operating expenses		29.6		24.1		92.3		68.8

Operating margin	$	70.5	$	50.4	$	178.9	$	139.2

Operating statistics (1):
Fractionation volumes, MBbl/d		316.4		293.3		277.2		299.4
LSNG treating volumes, MBbl/d		9.6		24.8		18.2		23.7
Benzene treating volumes, MBbl/d		8.1		19.8		15.2		20.2

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

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

Gross margin increased due to higher fractionation and export volumes. Fractionation volumes increased with the start up of Train 4 at CBF. Higher fractionation gross margin also includes the impact of higher fuel prices, which pass through to operating expenses. LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 55 MBbl/d for the third quarter 2013, compared to 31 MBbl/d for the same period last year. The increased volumes reflect an increase in ongoing LPG export

activity, as well as low ethane propane cargoes loaded in connection with testing and commissioning of Phase I of our international export expansion project, which was placed in service in September. Export rates were also higher. Storage revenues were higher due to increased rates and new customers.

The increase in operating expenses primarily reflects increased fuel and power usage due to higher fractionation volumes and higher fuel and power prices (which have a corresponding impact on fractionating and treating revenues), expenses related to the commissioning and start-up of Train 4 at CBF, and increased maintenance costs, partially offset by higher system product gains.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

The nine month results were impacted by the same factors as discussed above for the three months. In addition, lower year-to-date fractionation volumes are due to the impact of turnaround related curtailments at CBF earlier in the year.

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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in millions)
Gross margin	$	43.4	$	35.4	$	125.5	$	106.2
Operating expenses		10.9		10.0		31.5		28.4

Operating margin	$	32.5	$	25.4	$	94.0	$	77.8

Operating statistics (1):
NGL sales, MBbl/d		306.7		289.4		291.2		282.2
Average realized prices:
NGL realized price, $/gal		0.88		0.88		0.88		1.00

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

Gross margin increased primarily due to higher LPG export activity, which benefited both the Logistics Assets and Marketing and Distribution segments (see Logistics Assets) and higher truck and barge utilization.

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

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

The nine month results were impacted by the same factors as discussed above for the three months, plus the negative impact of lower NGL prices.

Other


	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(In millions)
Gross margin	$	4.8	$	14.0	$	17.0	$	28.1

Operating margin	$	4.8	$	14.0	$	17.0	$	28.1

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 on liquids processing arrangements by entering into derivative instruments.

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013			2012
	(In millions)
Natural gas	$	3.8		$	8.0	$	8.1		$	(18.8	)
NGL		3.3			6.0		11.3			7.8
Crude oil		(2.3	)		—		(2.4	)		(0.1	)

	$	4.8		$	14.0	$	17.0		$	(11.1	)

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).

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,
	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	$	59.7		$	24.2		$	124.9		$	141.2
Depreciation and amortization expenses		68.9			47.9			198.5			142.1
Deferred income tax expense		—			0.4			0.8			1.2
Amortization in interest expense		3.8			4.5			11.8			13.6
Loss on debt redemption and early debt extinguishment		7.4			15.6			14.7			15.5
Change in contingent consideration		(9.1	)		—			(15.3	)		—
(Gain) loss on sale or disposition of assets		(0.7	)		—			3.1			—
Risk management activities		(0.3	)		1.6			(0.2	)		3.8
Maintenance capital expenditures		(17.0	)		(16.2	)		(60.4	)		(48.0	)
Other (1)		(1.9	)		(0.8	)		(2.5	)		(1.8	)

Targa Resources Partners LP distributable cash flow	$	110.8		$	77.2		$	275.4		$	267.6

(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 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.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	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	$	99.5		$	90.5		$	276.3		$	315.5
Net income attributable to noncontrolling interests		(5.3	)		(3.9	)		(18.1	)		(23.5	)
Interest expense, net (1)		28.8			24.5			83.8			74.2
Loss on debt redemption and early debt extinguishments		(7.4	)		—			(14.7	)		—
Change in contingent consideration		(9.1	)		—			(15.3	)		—
Current income tax expense		0.7			0.5			1.7			1.5
Other (2)		(3.0	)		(5.3	)		(1.9	)		(14.5	)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets		124.9			42.6			93.4			(166.1	)
Accounts payable and other liabilities		(73.2	)		(32.7	)		9.4			197.3

Targa Resources Partners LP Adjusted EBITDA	$	155.9		$	116.2		$	414.6		$	384.4

(1)	Net of amortization of debt issuance costs, discount and premium included in interest expense of $3.8 million and $4.5 million for the three months ended September 30, 2013 and 2012, and $11.8 million and $13.6 million for the nine months ended September 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 tables present reconciliations 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,
	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	$	59.7		$	24.2		$	124.9		$	141.2
Interest expense, net		32.6			29.0			95.6			87.8
Income tax expense		0.7			0.9			2.5			2.7
Depreciation and amortization expenses		68.9			47.9			198.5			142.1
Loss on sale or disposition of assets		(0.7	)		15.6			3.1			15.5
Loss on debt redemption and early debt extinguishments		7.4			—			14.7			—
Change in contingent consideration		(9.1	)		—			(15.3	)		—
Risk management activities		(0.3	)		1.6			(0.2	)		3.8
Noncontrolling interests adjustment (1)		(3.3	)		(3.0	)		(9.2	)		(8.7	)

Targa Resources Partners LP Adjusted EBITDA	$	155.9		$	116.2		$	414.6		$	384.4

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


	Twelve Months Ended 12/31/2013
	Low Range			High Range
	($ in millions)
Reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net Income attributable to Targa Resources Partners LP	$	224.5		$	284.5
Add:
Interest expense, net		126.0			126.0
Income tax expense		4.0			4.0
Depreciation and amortization expense		253.0			253.0
Noncontrolling interest adjustment		(12.5	)		(12.5	)

Adjusted EBITDA	$	595.0		$	655.0


	Twelve Months Ended 12/31/2014
	Low Range			High Range
	($ in millions)
Reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net Income attributable to Targa Resources Partners LP	$	264.5		$	284.5
Add:
Interest expense, net		150.0			150.0
Income tax expense		4.0			4.0
Depreciation and amortization expense		335.0			335.0
Noncontrolling interest adjustment		(13.5	)		(13.5	)

Adjusted EBITDA	$	740.0		$	760.0

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.

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income, and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as substitutes for analysis of the Partnership’s results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in the Partnership’s industry, the Partnership’s definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. The Partnership believes that investors benefit from having access to the same financial measures that its management uses in evaluating its operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by the Partnership and by external users of the Partnership’s financial statements, including investors and commercial banks to assess:

•

the financial performance of the Partnership’s assets without regard to financing methods, capital structure or historical cost basis;

•

the Partnership’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

•

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In millions)
Reconciliation of Targa Resources Partners LP gross margin and operating margin to net income:
Gross margin	$	297.1		$	239.9		$	822.6		$	745.1
Operating expenses		(97.6	)		(78.3	)		(279.7	)		(227.1	)

Operating margin		199.5			161.6			542.9			518.0
Depreciation and amortization expenses		(68.9	)		(47.9	)		(198.5	)		(142.1	)
General and administrative expenses		(35.4	)		(33.5	)		(105.7	)		(100.0	)
Interest expense, net		(32.6	)		(29.0	)		(95.6	)		(87.8	)
Income tax expense		(0.7	)		(0.9	)		(2.5	)		(2.7	)
Gain (loss) on sale or disposition of assets		0.7			(15.6	)		(3.1	)		(15.5	)
Loss on debt redemption and early debt extinguishments		(7.4	)		—			(14.7	)		—
Change in contingent consideration		9.1			—			15.3			—
Other, net		0.7			(6.6	)		4.9			(5.2	)

Targa Resources Partners LP net income	$	65.0		$	28.1		$	143.0		$	164.7

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.

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,
	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.	$	49.4		$	19.0		$	105.6		$	131.7
Less: Net income of Targa Resources Partners LP		(65.0	)		(28.1	)		(143.0	)		(164.7	)

Net loss for TRC Non-Partnership		(15.6	)		(9.1	)		(37.4	)		(33.0	)
TRC Non-Partnership income tax expense		12.3			5.1			27.8			22.0
Distributions from the Partnership		38.6			26.2			107.5			72.6
Non-cash loss (gain) on hedges		0.1			(0.6	)		0.2			(1.6	)
Depreciation - Non-Partnership		0.1			0.7			0.2			2.2
Current cash tax expense, net (1)		(1.9	)		(2.6	)		(15.2	)		(15.2	)
Taxes funded with cash on hand (2)		1.9			2.2			6.9			6.6

Targa Resources Corp. distributable cash flow	$	35.5		$	21.9		$	90.0		$	53.6

(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, 2013 and 2012, and includes 2012 cash tax overpayment applied to 2013 cash tax liability.

(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.


	Three Months Ended September 30,						Nine Months Ended September 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	$	2.2		$	1.5		$	6.1		$	4.4
Incentive Distribution Rights		26.9			16.1			73.6			43.2
Common Units		9.5			8.6			27.8			25.0

Total distributions declared by Targa Resources Partners LP		38.6			26.2			107.5			72.6
Income (expenses) of TRC Non-Partnership
General and administrative expenses		(2.3	)		(2.2	)		(6.8	)		(6.5	)
Interest expense, net		(0.8	)		(1.0	)		(2.3	)		(3.2	)
Current cash tax expense, net (1)		(1.9	)		(2.6	)		(15.2	)		(15.2	)
Taxes funded with cash on hand (2)		1.9			2.2			6.9			6.6
Other income (expense)		—			(0.7	)		(0.1	)		(0.7	)

Targa Resources Corp. distributable cash flow	$	35.5		$	21.9		$	90.0		$	53.6

(1)

(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

TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

CONSOLIDATED BALANCE SHEETS

(In millions)


	September 30, 2013		December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	74.1	$	68.0
Trade receivables		498.5		514.9
Inventories		201.7		99.4
Assets from risk management activities		10.9		29.3
Other current assets		3.5		3.3

Total current assets		788.7		714.9

Property, plant and equipment, net		4,104.8		3,533.2
Other intangible assets, net		660.3		680.8
Long-term assets from risk management activities		3.9		5.1
Other long-term assets		90.3		91.7

Total assets	$	5,648.0	$	5,025.7

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	697.2	$	701.2
Liabilities from risk management activities		5.5		7.4

Total current liabilities		702.7		708.6

Long-term debt		2,797.9		2,393.3
Long-term liabilities from risk management activities		1.6		4.8
Other long-term liabilities		63.8		58.9
Owners’ equity:
Targa Resources Partners LP owner’s equity		1,919.1		1,709.6
Noncontrolling interests in subsidiaries		162.9		150.5

Total owners’ equity		2,082.0		1,860.1

Total liabilities and owners’ equity	$	5,648.0	$	5,025.7

TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit amounts)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUES	$	1,556.9		$	1,392.9		$	4,396.4		$	4,356.8
Product purchases		1,259.8			1,153.0			3,573.8			3,611.7
Operating expenses		97.6			78.3			279.7			227.1
Depreciation and amortization expenses		68.9			47.9			198.5			142.1
General and administrative expenses		35.4			33.5			105.7			100.0
Other operating expense		4.2			18.9			8.3			18.8

Total costs and expenses		1,465.9			1,331.6			4,166.0			4,099.7

INCOME FROM OPERATIONS		91.0			61.3			230.4			257.1
Other income (expense):
Interest expense, net		(32.6	)		(29.0	)		(95.6	)		(87.8	)
Equity earnings (loss)		5.6			(2.2	)		10.1			(0.3	)
Loss on debt redemption		(7.4	)		—			(14.7	)		—
Other expense		9.1			(1.1	)		15.3			(1.6	)

Income before income taxes		65.7			29.0			145.5			167.4
Income tax expense (benefit)		(0.7	)		(0.9	)		(2.5	)		(2.7	)

NET INCOME		65.0			28.1			143.0			164.7
Less: Net income attributable to noncontrolling interests		5.3			3.9			18.1			23.5

NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP	$	59.7		$	24.2		$	124.9		$	141.2

Net income attributable to general partner	$	28.1		$	16.7		$	76.1			46.2
Net income attributable to limited partners		31.6			7.5			48.8			95.0

Net income attributable to Targa Resources Partners LP	$	59.7		$	24.2		$	124.9		$	141.2

Net income per limited partner unit - basic	$	0.30		$	0.08		$	0.47		$	1.07

Net income per limited partner unit - diluted		0.30			0.08			0.47			1.07

Weighted average limited partner units outstanding - basic		106.7			89.2			104.2			88.8

Weighted average limited partner units outstanding - diluted		107.0			89.3			104.4			88.9

TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

CONSOLIDATED CASH FLOW INFORMATION

(In millions)


	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	143.0		$	164.7
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense		11.8			13.6
Compensation on equity grants		4.4			2.6
Depreciation and amortization expense		198.5			142.1
Accretion of asset retirement obligations		3.0			2.9
Deferred income tax expense		0.8			1.2
Equity earnings, net of distributions		—			0.3
Risk management activities		(0.2	)		3.8
Loss on debt redemption		14.7			—
Loss (gain) on sale or disposal of assets		3.1			15.5
Changes in operating assets and liabilities		(102.8	)		(31.2	)

Net cash provided by operating activities		276.3			315.5

CASH FLOWS FROM INVESTING ACTIVITIES
Outlays for property, plant and equipment		(708.2	)		(364.8	)
Business acquisition, net of cash acquired		—			(25.8	)
Purchase of materials and supplies		(35.3	)		—
Investment in unconsolidated affiliate		—			(16.8	)
Return of capital from unconsolidated affiliate		1.9			2.3
Other, net		4.0			1.6

Net cash used in investing activities		(737.6	)		(403.5	)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit facility		1,118.0			1,120.0
Repayments of credit facility		(1,338.0	)		(938.0	)
Proceeds from issuance of senior notes		625.0			—
Redemption of senior notes		(183.2	)		—
Borrowings from accounts receivable securitization facility		261.6			—
Repayments of accounts receivable securitization facility		(93.6	)		—
Costs incurred in connection with financing arrangements		(13.6	)		(4.5	)
Equity offerings		385.7			168.3
Distributions to unitholders		(288.8	)		(208.9	)
Contributions from parent		—			0.9
Contributions from noncontrolling interests		4.2			3.2
Distributions to noncontrolling interests		(9.9	)		(19.7	)

Net cash provided by (used in) financing activities		467.4			121.3

Net change in cash and cash equivalents		6.1			33.3
Cash and cash equivalents, beginning of period		68.0			55.6

Cash and cash equivalents, end of period	$	74.1		$	88.9

TARGA RESOURCES CORP.

FINANCIAL SUMMARY (unaudited)

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUES	$	1,556.8		$	1,393.5		$	4,396.2		$	4,358.4
Product purchases		1,259.8			1,153.0			3,573.8			3,611.8
Operating expenses		97.6			78.3			279.8			227.2
Depreciation and amortization expenses		69.0			48.6			198.7			144.3
General and administrative expenses		37.7			35.7			112.5			106.5
Other operating (income) expense		4.2			18.9			8.3			18.8

Total costs and expenses		1,468.3			1,334.5			4,173.1			4,108.6

INCOME FROM OPERATIONS		88.5			59.0			223.1			249.8
Other income (expense):
Interest expense, net		(33.4	)		(30.0	)		(97.9	)		(91.0	)
Equity earnings (loss)		5.6			(2.2	)		10.1			(0.3	)
Loss on debt redemption and early debt extinguishments		(7.4	)		—			(14.7	)		—
Other expenses		9.1			(1.8	)		15.3			(2.1	)

Income before income taxes		62.4			25.0			135.9			156.4
Income tax expense		(13.0	)		(6.0	)		(30.3	)		(24.7	)

NET INCOME		49.4			19.0			105.6			131.7
Less: Net income attributable to noncontrolling interests		33.1			10.3			61.0			104.8

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	16.3		$	8.7		$	44.6		$	26.9

Net income available per common share - basic	$	0.39		$	0.21		$	1.07		$	0.66

Net income available per common share - diluted	$	0.39		$	0.21		$	1.06		$	0.64

Weighted average shares outstanding - basic		41.6			41.0			41.6			41.0

Weighted average shares outstanding - diluted		42.1			41.9			42.1			41.8

TARGA RESOURCES CORP.

FINANCIAL SUMMARY (unaudited)

KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS

(In millions)


	September 30, 2013
Cash and cash equivalents:
TRC Non-Partnership	$	9.6
Targa Resources Partners		74.1

Total cash and cash equivalents	$	83.7

Long-term debt:
TRC Non-Partnership	$	70.0
Targa Resources Partners		2,797.9

Total long-term debt	$	2,867.9