Exhibit 99.1

 

Targa Resources Partners LP and Targa Resources Corp. Report

Fourth Quarter and Full Year 2014 Financial Results

HOUSTON – February 13, 2015 - Targa Resources Partners LP (NYSE: NGLS) (“Targa Resources Partners” or the “Partnership”) and Targa Resources Corp. (NYSE: TRGP) (“TRC”, “Targa”, or the “Company”) today reported fourth quarter and full year 2014 results.

Targa Resources Partners – Fourth Quarter and Full Year 2014 Financial Results

Fourth quarter 2014 net income attributable to Targa Resources Partners was $108.2 million compared to $108.6 million for the fourth quarter of 2013. Net income per diluted limited partner unit was $0.58 in the fourth quarter of 2014 compared to $0.70 for the fourth quarter of 2013. The Partnership reported earnings before interest, income taxes, depreciation and amortization and other non-cash items (“Adjusted EBITDA”) of $258.3 million for the fourth quarter of 2014 compared to $216.2 million for the fourth quarter of 2013.

For the full year 2014, net income attributable to Targa Resources Partners was $467.7 million compared to $233.5 million for 2013. Net income per diluted limited partner unit was $2.77 for 2014 compared to $1.19 for 2013. The Partnership reported Adjusted EBITDA of $970.3 million for the full year 2014 compared to $635.2 million for the full year 2013.

The Partnership’s distributable cash flow for the fourth quarter 2014 of $199.3 million corresponds to distribution coverage of approximately 1.5 times the $137.4 million in total distributions to be paid on February 13, 2015 (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”)). For the full year 2014, the Partnership’s distributable cash flow of $763.2 million corresponds to distribution coverage of 1.5 times the $515.3 million in total distributions declared with respect to 2014.

“2014 was another record year for Targa, driven by the successful completion of a number of growth capital projects that contributed to record Adjusted EBITDA and record operating margin from fee-based activities, positioning us well for the future,” said Joe Bob Perkins, Chief Executive Officer of the general partner of the Partnership and of the Company. “Turning to 2015, Targa has the diversity and financial flexibility to continue to execute through a reduced commodity price cycle. Our pending merger with Atlas Pipeline Partners, L.P. will provide additional scale and diversity to support our upstream and downstream customers.”

On January 21, 2015, the Partnership announced a cash distribution for the fourth quarter 2014 of $0.8100 per common unit, or $3.24 per unit on an annualized basis, representing an increase of approximately 2% over the distribution for the third quarter 2014 and 8% over the distribution for the fourth quarter 2013. The cash distribution will be paid on February 13, 2015 on all outstanding common units to holders of record as of the close of business on February 2, 2015. The total distribution paid will be $137.4 million, with $85.8 million to the Partnership’s third-party limited partners and $51.6 million to TRC for its ownership of common units and incentive distribution rights (“IDRs”) and its 2% general partner interest in the Partnership.

Targa Resources Corp. – Fourth Quarter and Full Year 2014 Financial Results

TRC reported net income available to common shareholders of $25.6 million for the fourth quarter 2014 compared to $20.4 million for the fourth quarter 2013. The net income per diluted common share was $0.61 in the fourth quarter of 2014 compared to $0.48 for the fourth quarter of 2013.

For the full year 2014, TRC reported net income available to common shareholders of $102.3 million compared to $65.1 million for 2013. Net income per diluted common share was $2.43 for 2014 compared to $1.55 for 2013.

The Company, which as of December 31, 2014 owned a 2% general partner interest in the Partnership (held through its 100% ownership interest in the general partner of the Partnership), all of the IDRs and 12,945,659 common units of the Partnership, presents its results consolidated with those of the Partnership.

Fourth quarter 2014 distributions to be paid on February 13, 2015 by the Partnership to the Company will be $51.6 million, with $10.5 million, $38.4 million and $2.7 million paid with respect to common units, IDRs and general partner interests, respectively.

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On January 21, 2015, TRC declared a quarterly dividend of $0.7750 per share of its common stock for the three months ended December 31, 2014, or $3.10 per share on an annualized basis, representing increases of approximately 6% over the previous quarter’s dividend and 28% over the dividend for the fourth quarter of 2013. Total cash dividends of approximately $32.6 million will be paid February 17, 2015 on all outstanding common shares to holders of record as of the close of business on February 2, 2015.

The Company’s distributable cash flow for the fourth quarter 2014 was $37.5 million compared to $32.8 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). For the full year 2014, the Company’s distributable cash flow was $124.7 million compared to $120.4 million in total dividends declared with respect to 2014.

Targa Resources Partners Fourth Quarter 2014 - Capitalization, Liquidity and Financing

Total funded debt of the Partnership as of December 31, 2014 was $2,966.2 million including no amounts outstanding under the Partnership’s $1.2 billion senior secured revolving credit facility, $182.8 million outstanding under the Partnership’s accounts receivable securitization facility, and $2,783.4 million of senior unsecured notes, net of unamortized discounts.

As of December 31, 2014, after giving effect to $44.1 million in outstanding letters of credit, the Partnership had available revolver capacity of $1,155.9 million and $72.3 million of cash on hand, resulting in total liquidity of $1,228.2 million.

In October 2014, the Partnership privately placed $800.0 million in aggregate principal amount of 4 ¹⁄₈% Senior Notes due 2019 resulting in net proceeds of $790.8 million. The net proceeds were used to reduce borrowings under the Partnership’s senior secured revolving credit facility and its accounts receivable securitization facility and for general partnership purposes.

In November 2014, the Partnership redeemed its outstanding 7 ⁷⁄₈% Senior Notes due 2018 paying $259.8 million plus accrued interest per the terms of the note agreement to redeem the outstanding balance of the 7 ⁷⁄₈% Notes. The redemption resulted in a $12.4 million loss on debt redemption, including premiums paid and non-cash write-offs of unamortized debt issue costs.

In January 2015, the Partnership launched cash tender offers (the “Tender Offers”) for any and all of the outstanding $500.0 million aggregate principal amount of the 6 ⁵⁄₈% Senior Notes due 2020 (the “2020 APL Notes”), $400.0 million aggregate principal amount of the 4 ³⁄₄% Senior Notes due 2021 (the “2021 APL Notes”) and $650.0 million aggregate principal amount of the 5 ⁷⁄₈% Senior Notes due 2023 (the “2023 APL Notes” and, together with the 2020 APL Notes and the 2021 APL Notes, the “APL Notes”) issued by Atlas Pipeline Partners, L.P. (“APL”) and Atlas Pipeline Finance Corporation, and solicitations of consents to certain proposed amendments to the respective indentures governing the APL Notes. The Tender Offers are in connection with, and conditioned upon, the consummation of the proposed merger with APL. In addition, on February 5, 2015, the Partnership launched a cash tender offer (the “Change of Control Offer”) for any and all of the 2020 APL Notes, as permitted by the indenture governing the 2020 APL Notes. The Change of Control Offer is also being made independently of the Partnership’s previously announced tender offer for the APL Notes.

Also in January 2015, the Partnership privately placed $1.1 billion in aggregate principal amount of 5% Senior Notes due 2018 resulting in net proceeds of $1,090.8 million. The net proceeds will be used, together with borrowings under the Partnership’s senior secured credit facility, to fund the Tender Offers, the change of control offer for the 2020 APL Notes which was launched in February 2015 by the Partnership and to finance the cash portion of the APL Merger.

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

Total funded debt of the Company as of December 31, 2014, excluding debt of the Partnership, was $102.0 million in borrowings outstanding under its $150.0 million senior secured revolving credit facility due 2017. This resulted in $48.0 million in available revolver capacity as of December 31, 2014.

The Company’s cash balance, excluding cash held by the Partnership and its subsidiaries, was $8.7 million as of December 31, 2014, resulting in total liquidity of $56.7 million.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 10:30 a.m. Eastern time (9:30 a.m. Central time) on February 13, 2015 to discuss fourth quarter and full year 2014 financial results. The conference call can be accessed via Webcast through the Events and Presentations section of the Partnership’s website at www.targaresources.com, by going directly to http://ir.targaresources.com/events.cfm?company=LP or by dialing 877-881-2598. The pass code for the dial-in is 69812074. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following the completion of the Webcast through the Investors section of the Partnership’s website. An updated investor presentation will also be available in the Events and Presentations section of the Partnership’s website following the completion of the conference call.

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Targa Resources Partners – Consolidated Financial Results of Operations

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
		($ in millions, except per unit data and operating statistics)
Revenues		$	2,032.9			$	2,104.5			$	8,616.5			$	6,314.9
Product purchases			1,634.7				1,749.4				7,046.9				5,137.2
Gross margin (1)			398.2				355.1				1,569.6				1,177.7
Operating expenses			109.4				96.5				433.0				376.2
Operating margin (2)			288.8				258.6				1,136.6				801.5
Depreciation and amortization expenses			93.7				73.1				346.5				271.6
General and administrative expenses			24.6				37.5				139.8				143.1
Other operating (income) expenses			2.1				1.2				(3.0	)			9.6
Income from operations			168.4				146.8				653.3				377.2
Interest expense, net			(39.7	)			(35.4	)			(143.8	)			(131.0	)
Equity earnings			4.3				4.6				18.0				14.8
Gain (loss) on debt redemptions and amendments			(12.4	)			—				(12.4	)			(14.7	)
Other income (expense)			(4.8	)			—				(5.2	)			15.2
Income tax (expense) benefit			(1.1	)			(0.4	)			(4.8	)			(2.9	)
Net income			114.7				115.6				505.1				258.6
Less: Net income attributable to noncontrolling interests			6.5				7.0				37.4				25.1
Net income attributable to Targa Resources Partners LP		$	108.2			$	108.6			$	467.7			$	233.5
Net income attributable to general partner			40.5				31.5				148.7				107.5
Net income attributable to limited partners			67.7				77.1				319.0				126.0
Net income attributable to Targa Resources Partners LP		$	108.2			$	108.6			$	467.7			$	233.5
Basic net income per limited partner unit		$	0.58			$	0.70			$	2.78			$	1.19
Diluted net income per limited partner unit			0.58				0.70				2.77				1.19
Financial data:
Adjusted EBITDA (3)		$	258.3			$	216.2			$	970.3			$	635.2
Distributable cash flow (4)			199.3				166.3				763.2				446.3
Capital expenditures			214.0				307.4				747.8				1,034.5
Operating data:
Crude oil gathered, MBbl/d			115.9				65.1				93.5				46.9
Plant natural gas inlet, MMcf/d (5),(6)			2,104.5				2,149.5				2,109.5				2,110.2
Gross NGL production, MBbl/d			155.6				140.4				153.0				136.8
Export volumes, MBbl/d (7)			225.5				124.5				176.9				66.6
Natural gas sales, BBtu/d (6)			937.5				920.4				902.3				928.2
NGL sales, MBbl/d			472.4				381.4				419.5				294.8
Condensate sales, MBbl/d			4.3				3.1				4.4				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 attributable to Targa Resources Partners LP before: interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and debt redemptions, early debt extinguishments and asset disposals, non-cash risk management activities related to derivative instruments; changes in the fair value of the Badlands acquisition contingent consideration; non-cash compensation on TRP equity grants and the non-controlling interest portion of depreciation and amortization expenses. This is a non-GAAP financial measure and is discussed under “Targa Resources Partners - Non-GAAP Financial Measures.”

(4)

Distributable cash flow is income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash risk management activities related to derivative instruments, debt repurchases and redemptions, early debt extinguishments, non-cash compensation on TRP equity grants 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.

(7)	Export volumes represent the quantity of NGL products delivered to third party customers destined for international markets at our Galena Park Marine terminal.

Targa Resources Partners – Review of Consolidated Fourth Quarter and Year End 2014 Results

Three Months Ended December 31, 2014 Compared to Three Months Ended December 31, 2013

Lower revenues, including the impact of hedging, were primarily due to lower NGL prices ($529.2 million), offset by higher NGL volumes ($361.6 million) and higher fee-based and other revenues ($78.1 million).

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

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

Lower general and administrative expenses were primarily driven by lower non-cash Long Term Incentive Plan valuation expense.

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

Losses on debt redemptions and amendments reflect premiums paid and the write-off of associated unamortized debt issue costs related to the redemption of our 7 ⁷⁄₈% Notes in 2014.

Other expense in 2014 was primarily attributable to transaction costs related to the pending Atlas Mergers.

Net income attributable to noncontrolling interests decreased as our joint ventures experienced lower earnings in the fourth quarter of 2014.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Higher revenues, including the impact of hedging (a decrease to revenues of $29.4 million), were primarily due to higher NGL volumes ($1,778.6 million), higher fee-based and other revenues ($438.1 million) and higher natural gas commodity sales prices ($201.4 million), partially offset by lower NGL and condensate prices ($65.6 million).

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

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

General and administrative expenses were slightly lower due to the effect of lower non-cash expenses related to periodic valuations of unvested Long Term Incentive Plan awards which offset increases in other overhead costs.

The increase in other operating income primarily relates to an insurance settlement in 2014 compared to losses on asset disposals recorded in 2013.

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

Losses on debt redemptions and amendments reflect premiums paid and the write-off of associated unamortized debt issue costs related to the redemptions of our 7 ⁷⁄₈% Notes in 2014 and the 11 ¹⁄₄% Notes and $100 million of our 6 ³⁄₈% Notes in 2013.

Other expense in 2014 was primarily attributable to transaction costs related to the pending Atlas Mergers. In 2013 we recorded a gain from the elimination of the contingent consideration liability associated with the Badlands acquisition.

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

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

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reporting and is reviewed for consistency and trend analysis. For a discussion of operating margin, see “Targa Resources Partners - Non-GAAP Financial Measures - Operating Margin.” Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation. For all operating statistics presented, the numerator is the total volume or sales during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.

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

Field Gathering and Processing

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

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

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
		($ in millions, except operating statistics and price amounts)
Gross margin		$	134.4			$	120.5			$	563.2			$	435.7
Operating expenses			52.0				41.7				190.9				165.2
Operating margin		$	82.4			$	78.8			$	372.3			$	270.5
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Sand Hills			167.3				155.2				165.1				155.8
SAOU (4)			221.7				157.8				193.1				154.1
North Texas System (5)			366.9				306.5				354.5				292.4
Versado			180.6				135.0				169.6				156.4
Badlands (6)			37.9				30.5				38.9				21.4
			974.4				785.0				921.2				780.1
Gross NGL production, MBbl/d (3)
Sand Hills			17.9				17.1				18.0				17.5
SAOU			25.7				22.8				25.2				22.5
North Texas System			40.4				31.7				37.8				31.1
Versado			23.0				16.0				21.4				18.9
Badlands			3.5				2.6				3.5				1.9
			110.5				90.2				105.9				91.9
Crude oil gathered, MBbl/d			115.9				65.1				93.5				46.9
Natural gas sales, BBtu/d (3)			515.0				381.8				469.0				376.3
NGL sales, MBbl/d			84.2				75.3				80.7				71.4
Condensate sales, MBbl/d			3.3				2.7				3.6				3.2
Average realized prices (7):
Natural gas, $/MMBtu			3.62				3.38				4.05				3.44
NGL, $/gal			0.53				0.82				0.72				0.76
Condensate, $/Bbl			63.46				92.07				82.35				92.89

 

(1)

Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.

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

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

(4)	Includes volumes from the 200 MMcf/d cryogenic High Plains plant which started commercial operations in June 2014.

(5)	Includes volumes from the 200 MMcf/d cryogenic Longhorn plant which started commercial operations in May 2014.

(6)	Badlands natural gas inlet represents the total wellhead gathered volume.

(7)	Average realized prices exclude the impact of hedging settlements presented in Other.

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Three Months Ended December 31, 2014 Compared to Three Months Ended December 31, 2013

Gross margin improvements in our Field Gathering and Processing segment were fueled by throughput increases and higher natural gas sales prices partially offset by lower NGL and condensate sales prices. The increase in plant inlet volumes was driven by system expansions and by increased producer activity which increased available supply across our areas of operation. The fourth quarter of 2014 also benefited from the start-up of commercial operations in May at the Longhorn Plant in North Texas and in June at the High Plains Plant in SAOU. Versado inlet volumes were impacted in the fourth quarter of 2013 by the Saunders fire. Badlands crude oil and natural gas volumes increased significantly due to producer activities and system expansion. Higher NGL sales reflect similar factors.

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

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Gross margin improvements in our Field Gathering and Processing segment were fueled by throughput increases and higher natural gas sales prices partially offset by lower NGL and condensate sales prices and the impact of severe cold weather in the first quarter of 2014. The increase in plant inlet volumes was driven by system expansions and by increased producer activity which increased available supply across our areas of operation. 2014 also benefited from the second quarter start-up of commercial operations at the Longhorn Plant in North Texas and the High Plains Plant in SAOU. Badlands crude oil and natural gas volumes increased significantly due to producer activities and system expansion. Higher NGL sales reflect similar factors.

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

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Coastal Gathering and Processing

The Coastal Gathering and Processing segment assets are located in the onshore and near offshore region of the Louisiana Gulf Coast, accessing natural gas from the Gulf Coast and the Gulf of Mexico. With the strategic location of 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 December 31,								Year Ended December 31,
		2014				2013				2014				2013
		($ in millions, except operating statistics and price amounts)
Gross margin		$	21.9			$	36.2			$	123.8			$	132.3
Operating expenses			11.1				12.0				46.2				46.9
Operating margin		$	10.8			$	24.2			$	77.6			$	85.4
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
LOU			213.9				389.1				284.6				350.9
VESCO			491.4				528.9				509.0				515.5
Other Coastal Straddles			424.8				446.4				394.8				463.7
			1,130.1				1,364.4				1,188.4				1,330.1
Gross NGL production, MBbl/d (3)
LOU			7.1				12.2				9.0				10.2
VESCO			25.1				24.8				26.0				21.5
Other Coastal Straddles			12.8				13.2				12.1				13.2
			45.0				50.2				47.1				44.9
Natural gas sales, BBtu/d (3)			233.0				328.6				258.0				296.0
NGL sales, MBbl/d			36.5				47.1				40.2				41.8
Condensate sales, MBbl/d			0.9				0.4				0.7				0.4
Average realized prices:
Natural gas, $/MMBtu			3.97				3.75				4.44				3.73
NGL, $/gal			0.59				0.86				0.80				0.83
Condensate, $/Bbl			68.43				96.14				89.70				104.38

 

(1)

Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.

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

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

Three Months Ended December 31, 2014 Compared to Three Months Ended December 31, 2013

The decrease in Coastal Gathering and Processing gross margin was primarily due to lower NGL sales prices, less favorable frac spreads and lower throughput volumes partially offset by new volumes at VESCO with higher GPM. The decrease in plant inlet volumes was largely attributable to the idling of the Big Lake plant in November 2014 due to market conditions, operational issues at VESCO, reduced availability of short-term, high GPM off-system volumes at LOU and the decline of leaner off-system supply volumes.

Operating expenses were relatively flat.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

The decrease in Coastal Gathering and Processing gross margin was primarily due to lower NGL sales prices, less favorable frac spreads and lower throughput volumes partially offset by new volumes at VESCO with higher GPM and the availability of short-term higher GPM off-system volumes at LOU. The overall decrease in plant inlet volumes was largely attributable to the decline of leaner off-system supply volumes and the idling of the Big Lake plant in November 2014 due to market conditions. Gross NGL production at VESCO during 2013 was impacted by a third-party NGL takeaway pipeline volume constraint.

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Operating expenses were relatively 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, including services for exporting LPG and storing and terminaling refined petroleum products and crude oil. The Partnership’s logistics assets are generally connected to, and supplied in part by, its Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas and Lake Charles, Louisiana.

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

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
		($ in millions, except operating statistics)
Gross margin (1)		$	164.1			$	137.0			$	613.3			$	408.2
Operating expenses (1)			43.1				33.6				168.2				125.9
Operating margin		$	121.0			$	103.4			$	445.1			$	282.3
Operating statistics, MBbl/d (2):
Fractionation volumes (3)			371.7				318.3				350.0				287.6
LSNG treating volumes			21.2				25.6				23.4				20.1
Benzene treating volumes			21.2				24.3				23.4				17.5

 

(1)	Fractionation and treating contracts include pricing terms composed of base fees and fuel and power components which vary with the cost of energy. As such, the logistics segment results include effects of variable energy costs that impact both gross margin and operating expenses.

(2)

Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.

(3)	Fractionation volumes reflect those volumes delivered and settled under fractionation contracts.

Three Months Ended December 31, 2014 Compared to Three Months Ended December 31, 2013

Logistics Assets gross margin was higher due to increased LPG export activity and increased fractionation activities, despite the increasing impact of ethane rejection. LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 226 MBbl/d in the fourth quarter of 2014 compared to 125 MBbl/d for the same period last year. This increase was driven by Phase II of our international export expansion project which added incremental capacity and operational efficiency in the second quarter of 2014 and became fully operational in the third quarter of 2014. Fractionation supply volumes increased in the fourth quarter of 2014 compared to the same period last year.

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

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Logistics Assets gross margin was significantly higher due to increased LPG export activity and increased fractionation activities, despite the increasing impact of ethane rejection. LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 177 MBbl/d in 2014 compared to 67 MBbl/d for 2013. This increase was driven by Phase I of our international export expansion project coming on-line in September 2013 and Phase II coming on-line during the second quarter and third quarter of 2014. Higher fractionation volumes were primarily due to CBF Train 4 which became operational in the third quarter of 2013. Treating volumes improved in 2014 compared to 2013 due to higher customer throughput. Terminaling and storage activity also increased, and capacity reservation fees were higher.

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

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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 the Partnership’s natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end-users; (4) providing propane, butane and services to LPG exporters; and (5) marketing natural gas available to the Partnership from its Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.

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

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
		($ in millions, except operating statistics and price amounts)
Gross margin		$	80.9			$	59.7			$	298.0			$	185.2
Operating expenses			10.7				11.8				48.4				43.3
Operating margin		$	70.2			$	47.9			$	249.6			$	141.9
Operating statistics (1):
NGL sales, MBbl/d			476.1				383.1				423.3				296.6
Average realized prices:
NGL realized price, $/gal			0.74				1.04				0.93				0.94

 

(1)

Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.

Three Months Ended December 31, 2014 Compared to Three Months Ended December 31, 2013

Marketing and Distribution gross margin increased primarily due to higher LPG export activity (which benefits both Logistics Assets and Marketing and Distribution segments), partially offset by lower Wholesale and NGL marketing activities and a reduced benefit associated with a contract settlement.

Operating Expenses decreased due to lower barge towing costs and decreased barge maintenance.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Marketing and Distribution gross margin increased primarily due to higher LPG export activity (which benefits both Logistics Assets and Marketing and Distribution segments), higher Wholesale and NGL marketing activities, higher terminal activity, higher barge utilization including increased barge fleet, and increased refinery services. Gross margin was partially offset by lower truck utilization and a reduced benefit associated with a contract settlement.

Operating expenses increased primarily due to higher terminal activity, higher barge and railcar utilization partially offset by lower truck utilization.

Other

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
		(In millions)
Gross margin		$	4.4			$	4.3			$	(8.0	)		$	21.4
Operating margin		$	4.4			$	4.3			$	(8.0	)		$	21.4

Other contains the financial effects of the Partnership’s hedging program on operating margin as it represents the cash settlements on derivative hedge contracts and mark-to-market gains and losses on its derivative contracts not designated as hedges. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow. We have hedged the commodity price associated with a portion of our expected (i) natural gas equity volumes in Field Gathering and Processing Operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing as well as in the LOU portion of the Coastal Gathering and Processing Operations that result from percent of proceeds or liquid processing arrangements by entering into derivative instruments. Because we are essentially forward-selling a portion of our plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

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

 

		Three Months Ended December 31, 2014												Three Months Ended December 31, 2013
		(In millions, except volumetric data and price amounts)
		Volume Settled				Price Spread (1)(2)				Gain (Loss)				Volume Settled				Price Spread (1)(2)				Gain (Loss)				2014 vs 2013
Natural Gas (BBtu)			6.1			$	0.17			$	1.1				3.8			$	0.91			$	3.6			$	(2.5	)
NGL (MMBbl)			0.2				11.86				2.9				0.5				2.79				1.5				1.4
Crude Oil (MMBbl)			0.2				18.74				4.2				0.2				(4.27	)			(0.8	)			5.0
Non-Hedge Accounting (3)											(3.8	)											(0.4	)			(3.4	)
Ineffectiveness (4)											—												0.4				(0.4	)
										$	4.4											$	4.3			$	0.1
		Year Ended December 31, 2014												Year Ended December 31, 2013
		(In millions, except volumetric data and price amounts)
		Volume Settled				Price Spread (1)(2)				Gain (Loss)				Volume Settled				Price Spread (1)(2)				Gain (Loss)				2014 vs 2013
Natural Gas (BBtu)			21.9			$	(0.27	)		$	(5.9	)			12.3			$	0.95			$	11.7			$	(17.6	)
NGL (MMBbl)			0.6				5.79				3.6				2.1				6.19				12.8				(9.2	)
Crude Oil (MMBbl)			0.9				(1.07	)			(1.0	)			0.7				(4.01	)			(2.9	)			1.9
Non-Hedge Accounting (3)											(4.8	)											(0.3	)			(4.5	)
Ineffectiveness (4)											0.1												0.1				—
										$	(8.0	)										$	21.4			$	(29.4	)

 

(1)	The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

(2)	Price spread on Natural Gas volumes is $/MMBtu, NGL volumes is $/Bbl and Crude volume is $/Bbl.

(3)	Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes.

(4)	Ineffectiveness primarily relates to certain crude hedging contracts.

About Targa Resources Corp. and Targa Resources Partners

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

Targa Resources Partners is a publicly traded Delaware limited partnership formed in October 2006 by its parent, Targa Resources Corp., to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. The Partnership is a leading provider of midstream natural gas and natural gas liquid services in the United States. In addition, the Partnership provides crude oil gathering and crude oil and petroleum product terminaling services. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting, terminaling and selling NGLs and NGL products; gathering, storing, and terminaling crude oil; and storing and terminaling petroleum products. The Partnership reports its operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments - (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing, consisting of two reportable segments - (a) Logistics Assets and (b) Marketing and Distribution. The financial results of the Partnership’s commodity hedging activities are reported in Other.

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

Targa Resources Partners - Non-GAAP Financial Measures

This press release includes the Partnership’s non-GAAP financial measures distributable cash flow, Adjusted EBITDA, gross margin and operating margin. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. The Partnership’s non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities or any other GAAP measure of liquidity or financial performance.

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Distributable Cash Flow - The Partnership defines distributable cash flow as net income attributable to Targa Resources Partners LP plus: depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash risk management activities related to derivative instruments, debt repurchases and redemptions, early debt extinguishments, non-cash compensation on Partnership equity grants and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs) and changes in the fair value of the Badlands acquisition contingent consideration. This measure includes any impact of noncontrolling interests.

Distributable cash flow is a significant performance metric used by the Partnership and by external users of its financial statements, such as investors, commercial banks and research analysts to compare basic cash flows generated by the Partnership (prior to the establishment of any retained cash reserves by the board of directors of the Partnership’s general partner) to the cash distributions it expects to pay its unitholders. Using this metric, management and external users of the Partnership’s financial statements can quickly compute the coverage ratio of estimated cash flows to cash distributions. Distributable cash flow is also an important financial measure for the Partnership’s unitholders since it serves as an indicator of the Partnership’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Partnership is generating cash flow at a level that can sustain or support an increase in its quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).

Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Partners LP. It has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income attributable to Targa Resources Partners LP and is defined differently by different companies in the Partnership’s industry, the Partnership’s definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making processes.

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

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
		(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow:
Net income attributable to Targa Resources Partners LP		$	108.2			$	108.6			$	467.7			$	233.5
Depreciation and amortization expenses			93.7				73.1				346.5				271.6
Deferred income tax expense (benefit)			0.5				0.1				1.6				0.9
Non-cash interest expense, net (1)			2.5				3.7				11.2				15.5
Loss on debt redemptions and amendments			12.4				—				12.4				14.7
Change in contingent consideration			—				—				—				(15.3	)
(Gain) loss on sale or disposition of assets			0.8				0.8				(4.8	)			3.9
Compensation on TRP equity grants			2.2				1.6				9.2				6.0
Risk management activities			3.8				(0.3	)			4.7				(0.5	)
Maintenance capital expenditures			(23.6	)			(19.5	)			(79.1	)			(79.9	)
Other (2)			(1.2	)			(1.6	)			(6.2	)			(4.1	)
Targa Resources Partners LP distributable cash flow		$	199.3			$	166.5			$	763.2			$	446.3

 

(1)	Includes amortization of debt issuance costs, discount and premium.

(2)	Includes the noncontrolling interest portion of maintenance capital expenditures, and depreciation and amortization expenses.

Adjusted EBITDA - The Partnership defines Adjusted EBITDA as net income attributable to Targa Resources Partners LP before: interest; income taxes; depreciation and amortization; gains or losses on debt repurchases and redemptions, early debt extinguishments and asset disposals; non-cash risk management activities related to derivative instruments; changes in the fair value of the Badlands acquisition contingent consideration; non-cash compensation on Partnership equity grants and the non-controlling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by the Partnership and by external users of its financial statements such as investors, commercial banks and others.

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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.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income attributable to Targa Resources Partners LP. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income attributable to Targa Resources Partners LP. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income attributable to Targa Resources Partners LP and net cash provided by operating activities and is defined differently by different companies in the Partnership’s industry, the Partnership’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

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

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
		(In millions)
Reconciliation of net cash provided by Targa Resources Partners LP operating activities to Adjusted EBITDA:
Net cash provided by operating activities		$	266.8			$	135.1			$	838.5			$	411.4
Net income attributable to noncontrolling interests			(6.5	)			(7.0	)			(37.4	)			(25.1	)
Interest expense			39.7				35.4				143.8				131.0
Non-cash interest expense, net (1)			(2.4	)			(3.7	)			(11.2	)			(15.5	)
Current income tax expense (benefit)			0.6				0.3				3.2				2.0
Other (2)			(4.7	)			(1.5	)			(18.4	)			(13.7	)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivables, inventories and other assets			(214.5	)			136.9				(58.6	)			230.3
Accounts payable and other liabilities			179.3				(79.3	)			110.4				(85.2	)
Targa Resources Partners LP Adjusted EBITDA		$	258.3			$	216.2			$	970.3			$	635.2

 

(1)	Includes amortization of debt issuance costs, discount and premium.

(2)	Includes equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations and noncontrolling interest portion of depreciation and amortization expenses.

The following table presents a reconciliation of net income of the Partnership to Adjusted EBITDA for the periods indicated:

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
		(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP		$	108.2			$	108.6			$	467.7			$	233.5
Interest expense, net			39.7				35.4				143.8				131.0
Income tax expense			1.1				0.4				4.8				2.9
Depreciation and amortization expenses			93.7				73.1				346.5				271.6
(Gain) loss on sale or disposition of assets			0.8				0.8				(4.8	)			3.9
(Gain) loss on debt redemptions and amendments			12.4				—				12.4				14.7
Change in contingent consideration			—				—				—				(15.3	)
Compensation on TRP equity grants (1)			2.2				1.6				9.2				6.0
Non-cash risk management activities			3.8				(0.3	)			4.7				(0.5	)
Noncontrolling interests adjustment (2)			(3.6	)			(3.4	)			(14.0	)			(12.6	)
Adjusted EBITDA		$	258.3			$	216.2			$	970.3			$	635.2

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(1)	The definition of Adjusted EBITDA was changed in 2014 to exclude non-cash compensation on equity grants.

(2)	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 commodity hedging program. The Partnership defines Gathering and Processing gross margin as total operating revenues from (1) the sale of natural gas, condensate, crude oil and NGLs and (2) natural gas and crude oil gathering and service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas and crude oil purchases. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees, NGL and natural gas sales, less cost of sales, which consists primarily of NGL and natural gas purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash flow hedge settlements are reported in Other.

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

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.

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

Management 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 December 31,								Year Ended December 31,
		2014				2013				2014				2013
		(In millions)
Reconciliation of Targa Resources Partners LP gross margin and operating margin to net income:
Gross margin		$	398.2			$	355.1			$	1,569.6			$	1,177.7
Operating expenses			(109.4	)			(96.5	)			(433.0	)			(376.2	)
Operating margin			288.8				258.6				1,136.6				801.5
Depreciation and amortization expenses			(93.7	)			(73.1	)			(346.5	)			(271.6	)
General and administrative expenses			(24.6	)			(37.4	)			(139.8	)			(143.1	)
Interest expense, net			(39.7	)			(35.4	)			(143.8	)			(131.0	)
Income tax (expense) benefit			(1.1	)			(0.4	)			(4.8	)			(2.9	)
Gain (loss) on sale or disposition of assets			(0.8	)			(0.8	)			4.8				(3.9	)
Gain (loss) on debt redemptions and amendments			(12.4	)			—				(12.4	)			(14.7	)
Change in contingent consideration			—				—				—				15.3
Other, net			(1.8	)			4.1				11.0				9.0
Net income		$	114.7			$	115.6			$	505.1			$	258.6

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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 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 process.

The following tables present a reconciliation of net income of Targa Resources Corp. to distributable cash flow, and an alternative reconciliation of cash distributions declared by Targa Resources Partners LP to distributable cash flow of Targa Resources Corp. for the periods indicated:

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
		(In millions)
Reconciliation of Net Income attributable to Targa Resources Corp. to Distributable Cash Flow
Net income of Targa Resources Corp.		$	92.3			$	95.7			$	423.0			$	201.3
Less: Net income of Targa Resources Partners LP			(114.7	)			(115.6	)			(505.1	)			(258.6	)
Net loss for TRC Non-Partnership			(22.4	)			(19.9	)			(82.1	)			(57.3	)
TRC Non-Partnership income tax expense			13.3				17.5				63.2				45.3
Distributions from the Partnership			51.6				41.5				190.8				149.0
Non-cash loss (gain) on hedges			—				0.1				—				0.3
Depreciation - Non-Partnership assets			4.2				0.1				4.5				0.3
Current cash tax expense (1)			(12.1	)			(15.8	)			(63.5	)			(31.0	)
Taxes funded with cash on hand (2)			2.9				3.1				11.8				10.0
Distributable cash flow		$	37.5			$	26.6			$	124.7			$	116.6

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(1)	Excludes $1.2 million and $4.7 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 twelve months ended December 31, 2014 and 2013.

(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 December 31,								Year Ended December 31,
		2014				2013				2014				2013
		(In millions)
Targa Resources Corp. Distributable Cash Flow
Distributions declared by Targa Resources Partners LP associated with:
General Partner Interests		$	2.7			$	2.3			$	10.2			$	8.4
Incentive Distribution Rights			38.4				29.5				139.8				103.1
Common Units			10.5				9.7				40.8				37.5
Total distributions declared by Targa Resources Partners LP			51.6				41.5				190.8				149.0
Income (expenses) of TRC Non-Partnership
General and administrative expenses			(1.2	)			(1.6	)			(8.2	)			(8.4	)
Interest expense, net			(0.9	)			(0.8	)			(3.3	)			(3.1	)
Current cash tax expense (1)			(12.1	)			(15.8	)			(63.5	)			(31.0	)
Taxes funded with cash on hand (2)			2.9				3.1				11.8				10.0
Other income (expense)			(2.8	)			0.2				(2.9	)			0.1
Distributable cash flow		$	37.5			$	26.6			$	124.7			$	116.6

 

(1)	Excludes $1.2 million and $4.7 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 twelve months ended December 31, 2014 and 2013.

(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.

Additional Information and Where to Find It

In connection with the proposed transaction, the Company has filed with the U.S. Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4 that includes a joint proxy statement of Atlas Energy, L.P. (“ATLS”) and the Company and a prospectus of the Company (the “Company joint proxy statement/prospectus”). In connection with the proposed transaction, the Company mailed the definitive Company joint proxy statement/prospectus to its shareholders on or about January 22, 2015, and ATLS mailed the definitive Company joint proxy statement/prospectus to its unitholders on or about January 22, 2015.

Also in connection with the proposed transaction, the Partnership has filed with the SEC a registration statement on Form S-4 that includes a proxy statement of APL and a prospectus of the Partnership (the “Partnership proxy statement/prospectus”). In connection with the proposed transaction, APL mailed the definitive Partnership proxy statement/prospectus to its unitholders on or about January 22, 2015.

INVESTORS, SHAREHOLDERS AND UNITHOLDERS ARE URGED TO READ THE COMPANY JOINT PROXY STATEMENT/PROSPECTUS, THE PARTNERSHIP PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY CONTAIN IMPORTANT INFORMATION ABOUT THE COMPANY, THE PARTNERSHIP, ATLS AND APL, AS WELL AS THE PROPOSED TRANSACTION AND RELATED MATTERS.

This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval.

A free copy of the Company Joint Proxy Statement/Prospectus, the Partnership Proxy Statement/Prospectus and other filings containing information about the Company, the Partnership, ATLS and APL may be obtained at the SEC’s Internet site at www.sec.gov. In addition, the documents filed with the SEC by the Company and the Partnership may be obtained free of charge by directing such request to: Targa Resources, Attention: Investor Relations, 1000 Louisiana, Suite 4300, Houston, Texas 77002 or emailing jkneale@targaresources.com or calling (713) 584-1133. These documents may also be obtained for free from the Company’s and the Partnership’s investor relations website at www.targaresources.com. The documents filed with the SEC by ATLS may be obtained free of charge by directing such request to: Atlas Energy, L.P., Attn: Investor Relations, 1845 Walnut Street, Philadelphia,

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Pennsylvania 19103 or emailing InvestorRelations@atlasenergy.com. These documents may also be obtained for free from ATLS’s investor relations website at www.atlasenergy.com. The documents filed with the SEC by APL may be obtained free of charge by directing such request to: Atlas Pipeline Partners, L.P., Attn: Investor Relations, 1845 Walnut Street, Philadelphia, Pennsylvania 19103 or emailing IR@atlaspipeline.com. These documents may also be obtained for free from APL’s investor relations website at www.atlaspipeline.com.

Participants in Solicitation Relating to the Atlas Mergers

The Company, the Partnership, ATLS and APL and their respective directors, executive officers and other persons may be deemed to be participants in the solicitation of proxies from the Company, ATLS or APL shareholders or unitholders, as applicable, in respect of the proposed transaction that is described in the Company joint proxy statement/prospectus and the Partnership proxy statement/prospectus. Information regarding the Company’s directors and executive officers is contained in the Company’s definitive proxy statement dated April 7, 2014, which has been filed with the SEC. Information regarding directors and executive officers of the Partnership’s general partner is contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013, which has been filed with the SEC. Information regarding directors and executive officers of ATLS’s general partner is contained in ATLS’s definitive proxy statement dated March 21, 2014, which has been filed with the SEC. Information regarding directors and executive officers of APL’s general partner is contained in APL’s Annual Report on Form 10-K for the year ended December 31, 2013, which has been filed with the SEC.

A more complete description is available in the Company joint proxy statement/prospectus and the Partnership proxy statement/prospectus.

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)

 

		December 31, 2014				December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents		$	72.3			$	57.5
Trade receivables			566.8				658.6
Inventories			168.9				150.7
Assets from risk management activities			44.4				2.0
Other current assets			3.8				7.1
Total current assets			856.2				875.9
Property, plant and equipment, net			4,824.6				4,345.4
Intangible assets, net			591.9				653.4
Long-term assets from risk management activities			15.8				3.1
Other long-term assets			88.7				93.6
Total assets		$	6,377.2			$	5,971.4
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities		$	645.9			$	773.6
Account receivable securitization facility			182.8				—
Liabilities from risk management activities			5.2				8.0
Total current liabilities			833.9				781.6
Long-term debt			2,783.4				2,905.3
Long-term liabilities from risk management activities			—				1.4
Other long-term liabilities			71.5				64.7
Owners’ equity:
Targa Resources Partners LP owner’s equity			2,517.2				2,057.8
Noncontrolling interests in subsidiaries			171.2				160.6
Total owners’ equity			2,688.4				2,218.4
Total liabilities and owners’ equity		$	6,377.2			$	5,971.4

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TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit amounts)

 

		Three Months Ended								Year Ended
		December 31,								December 31,
		2014				2013				2014				2013
REVENUES		$	2,032.9			$	2,104.4			$	8,616.5			$	6,314.9
Product purchases			1,634.7				1,749.3				7,046.9				5,137.2
Operating expenses			109.4				96.5				433.0				376.2
Depreciation and amortization expenses			93.7				73.1				346.5				271.6
General and administrative expenses			24.6				37.5				139.8				143.1
Other operating (income) expenses			2.1				1.2				(3.0	)			9.6
Total costs and expenses			1,864.5				1,957.6				7,963.2				5,937.7
INCOME FROM OPERATIONS			168.4				146.8				653.3				377.2
Other income (expense):
Interest expense, net			(39.7	)			(35.4	)			(143.8	)			(131.0	)
Equity earnings			4.3				4.6				18.0				14.8
Gain (loss) on debt redemptions and amendments			(12.4	)			—				(12.4	)			(14.7	)
Other expense			(4.8	)			—				(5.2	)			15.2
Income before income taxes			115.8				116.0				509.9				261.5
Income tax (expense) benefit			(1.1	)			(0.4	)			(4.8	)			(2.9	)
NET INCOME			114.7				115.6				505.1				258.6
Less: Net income attributable to noncontrolling interests			6.5				7.0				37.4				25.1
NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP		$	108.2			$	108.6			$	467.7			$	233.5
Net income attributable to general partner		$	40.5			$	31.5			$	148.7				107.5
Net income attributable to limited partners			67.7				77.1				319.0				126.0
Net income attributable to Targa Resources Partners LP		$	108.2			$	108.6			$	467.7			$	233.5
Net income per limited partner unit - basic		$	0.58			$	0.70			$	2.78			$	1.19
Net income per limited partner unit - diluted			0.58				0.70				2.77				1.19
Weighted average limited partner units outstanding - basic			116.8				109.4				114.7				105.5
Weighted average limited partner units outstanding - diluted			117.1				109.9				115.1				105.7

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TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

 

CONSOLIDATED CASH FLOW INFORMATION

(In millions)

 

		Year Ended December 31,
		2014				2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	505.1			$	258.6
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense			11.2				15.5
Compensation on equity grants			9.2				6.0
Depreciation and amortization expense			346.5				271.6
Accretion of asset retirement obligations			4.4				3.9
Deferred income tax expense (benefit)			1.6				0.9
Equity earnings of unconsolidated subsidiary			(18.0	)			(14.8	)
Distributions of unconsolidated subsidiary			18.0				12.0
Risk management activities			4.7				(0.5	)
(Gain) loss on sale or disposal of assets			(4.8	)			3.9
(Gain) loss on debt redemptions and amendments			12.4				14.7
Changes in operating assets and liabilities			(51.8	)			(160.4	)
Net cash provided by operating activities			838.5				411.4
CASH FLOWS FROM INVESTING ACTIVITIES
Outlays for property, plant and equipment			(762.2	)			(1,013.6	)
Return of capital from unconsolidated affiliate			5.7				—
Other, net			5.1				(12.7	)
Net cash used in investing activities			(751.4	)			(1,026.3	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility			1,600.0				1,613.0
Repayments of credit facility			(1,995.0	)			(1,838.0	)
Proceeds from issuance of senior notes			800.0				625.0
Borrowings from accounts receivable securitization facility			381.9				373.3
Repayments of accounts receivable securitization facility			(478.8	)			(93.6	)
Redemption of senior notes			(259.8	)			(183.2	)
Costs incurred in connection with financing arrangements			(14.0	)			(15.3	)
Repurchase of common units under compensation plans			(4.8	)			—
Proceeds from equity offerings and general partner contributions			420.4				535.5
Distributions			(495.4	)			(397.3	)
Contributions from noncontrolling interests			—				4.3
Distributions to noncontrolling interests			(26.8	)			(19.3	)
Net cash provided by (used in) financing activities			(72.3	)			604.4
Net change in cash and cash equivalents			14.8				(10.5	)
Cash and cash equivalents, beginning of period			57.5				68.0
Cash and cash equivalents, end of period		$	72.3			$	57.5

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TARGA RESOURCES CORP.

FINANCIAL SUMMARY (unaudited)

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts)

 

		Three Months Ended December 31,								Year Ended December 31,
		2014				2013				2014				2013
REVENUES		$	2,032.9			$	2,104.4			$	8,616.5			$	6,314.7
Product purchases			1,634.7				1,749.4				7,046.9				5,137.2
Operating expenses			109.4				96.5				433.1				376.3
Depreciation and amortization expenses			97.9				73.2				351.0				271.9
General and administrative expenses			25.8				39.0				148.0				151.5
Other operating income			2.0				1.3				(3.0	)			9.6
Total costs and expenses			1,869.8				1,959.4				7,976.0				5,946.5
INCOME FROM OPERATIONS			163.1				145.0				640.5				368.2
Other income (expense):
Interest expense, net			(40.6	)			(36.2	)			(147.1	)			(134.1	)
Equity earnings			4.3				4.7				18.0				14.8
Gain (loss) on debt redemption and amendments			(12.4	)			—				(12.4	)			(14.7	)
Other			(7.5	)			—				(8.0	)			15.3
Income before income taxes			106.9				113.5				491.0				249.5
Income tax (expense) benefit			(14.4	)			(17.9	)			(68.0	)			(48.2	)
NET INCOME			92.5				95.6				423.0				201.3
Less: Net income attributable to noncontrolling interests			66.9				75.2				320.7				136.2
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS		$	25.6			$	20.4			$	102.3			$	65.1
Net income available per common share - basic		$	0.61			$	0.49			$	2.44			$	1.56
Net income available per common share - diluted		$	0.61			$	0.48			$	2.43			$	1.55
Weighted average shares outstanding - basic			42.0				41.7				42.0				41.6
Weighted average shares outstanding - diluted			42.1				42.1				42.1				42.1

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TARGA RESOURCES CORP.

FINANCIAL SUMMARY (unaudited)

 

KEY TARGA RESOURCES CORP. CONSOLIDATED BALANCE SHEET ITEMS

(In millions)

 

		December 31, 2014
Cash and cash equivalents:
TRC Non-Partnership		$	8.7
Targa Resources Partners			72.3
Total cash and cash equivalents		$	81.0
Total funded debt:
Current
Targa Resources Partners		$	182.8
Long term
TRC Non-Partnership			102.0
Targa Resources Partners			2,783.4
Total long-term debt			2,885.4
Total funded debt:		$	3,068.2