News Column

Targa Resources Partners LP and Targa Resources Corp. Report Fourth Quarter and Full Year 2013 Financial Results

February 13, 2014

HOUSTON, Feb. 13, 2014 (GLOBE NEWSWIRE) -- Targa Resources Partners LP (NYSE:NGLS) ("Targa Resources Partners" or the "Partnership") and Targa Resources Corp. (NYSE:TRGP) ("TRC" or the "Company") today reported fourth quarter and full year 2013 results. Fourth quarter 2013 net income attributable to Targa Resources Partners was $108.6 million compared to $33.5 million for the fourth quarter of 2012. Net income per diluted limited partner unit was $0.70 in the fourth quarter of 2013 compared to $0.14 for the fourth quarter of 2012. The Partnership reported earnings before interest, income taxes, depreciation and amortization and other non-cash items ("Adjusted EBITDA") of $214.6 million for the fourth quarter of 2013 compared to $130.6 million for the fourth quarter of 2012.

For the full year 2013, net income attributable to Targa Resources Partners was $233.5 million compared to $174.6 million for 2012. Net income per diluted limited partner unit was $1.19 for 2013 compared to $1.20 for 2012. The Partnership reported Adjusted EBITDA of $629.2 million for the full year 2013 compared to $514.9 million for the full year 2012.

The Partnership's distributable cash flow for the fourth quarter 2013 of $164.9 million corresponds to distribution coverage of approximately 1.4 times the $115.8 million in total distributions to be paid on February 14, 2014 (see the section of this release entitled "Targa Resources Partners - Non-GAAP Financial Measures" for a discussion of Adjusted EBITDA, gross margin, operating margin and distributable cash flow, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles ("GAAP")). For the full year 2013, the Partnership's distributable cash flow of $440.3 million corresponds to distribution coverage of over 1.0 times the $422.4 million in total distributions declared with respect to 2013.

"2013 was a transformational year for Targa. The portion of the Partnership's operating margin that is fee-based now exceeds 60 percent, and the recent and expected Adjusted EBITDA growth is impressive with $515 million in 2012, $629 million in 2013 and $750+ million expected for 2014. With over $1 billion of growth projects placed in service during 2013 and additional projects in process, Targa is well positioned for the future," said Joe Bob Perkins, Chief Executive Officer of the general partner of the Partnership and of the Company.

On January 14, 2014, the Partnership announced a cash distribution for the fourth quarter 2013 of $0.7475 per common unit, or $2.99 per unit on an annualized basis, representing an increase of approximately 2% over the distribution for the third quarter 2013 and 10% over the distribution for the fourth quarter 2012. The cash distribution will be paid on February 14, 2014 on all outstanding common units to holders of record as of the close of business on January 27, 2014. The total distribution paid will be $115.8 million, with $74.3 million to the Partnership's third-party limited partners and $41.5 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. – Fourth Quarter and Full Year 2013 Financial Results

Targa Resources Corp., the parent of Targa Resources Partners, today reported its fourth quarter and full year 2013 results. The Company, which as of December 31, 2013 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.

TRC reported net income available to common shareholders of $20.4 million for the fourth quarter 2013 compared with a net income available to common shareholders of $11.2 million for the fourth quarter 2012. The net income per diluted common share was $0.48 in the fourth quarter of 2013 compared to $0.27 for the fourth quarter of 2012.

For the full year 2013, TRC reported net income available to common shareholders of $65.1 million compared to $38.1 million for 2012. Net income per diluted common share was $1.55 for 2013 compared to $0.91 for 2012.

Fourth quarter 2013 distributions to be paid on February 14, 2014 by the Partnership to the Company will be $41.5 million, with $9.7 million, $29.5 million and $2.3 million paid with respect to common units, IDRs and general partner interests, respectively.

On January 14, 2014, TRC declared a quarterly dividend of $0.6075 per share of its common stock for the three months ended December 31, 2013, or $2.43 per share on an annualized basis, representing increases of approximately 7% over the previous quarter's dividend and 33% over the dividend for the fourth quarter of 2012. Total cash dividends of approximately $25.5 million will be paid February 18, 2014 on all outstanding common shares to holders of record as of the close of business on January 27, 2014.

The Company's distributable cash flow for the fourth quarter 2013 was $26.6 million compared to $25.6 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 2013, the Company's distributable cash flow was $116.6 million compared to $93.2 million in total dividends declared with respect to 2013.

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

Total funded debt of the Partnership as of December 31, 2013 was $2,905.3 million including $395.0 million outstanding under the Partnership's $1.2 billion senior secured revolving credit facility, $279.7 million outstanding under the Partnership's accounts receivable securitization facility, and $2,230.6 million of senior unsecured notes, net of unamortized discounts.

As of December 31, 2013, after giving effect to $86.8 million in outstanding letters of credit, the Partnership had available revolver capacity of $718.2 million and $57.5 million of cash on hand, resulting in total liquidity of $775.7 million.

For the full year 2013, the Partnership issued a total of 11,154,438 common units representing total net proceeds of $517.9 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 $10.8 million to maintain its 2% general partner interest during this period.

In January, 2014, the Partnership issued an additional 1,118,147 common units and received net proceeds of approximately $56.2 million from equity issuances under an equity distribution agreement, which allows the Partnership to periodically issue equity at prevailing market prices, less a commission. TRC contributed $1.2 million to maintain its 2% general partnership interest during this period.

The Partnership estimates that its total growth capital expenditures for 2014 will be approximately $650.0 million on a gross basis, and that maintenance capital expenditures net to the Partnership's interest will be $90.0 million.

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

Total funded debt of the Company as of December 31, 2013, excluding debt of the Partnership, was $84.0 million in borrowings outstanding under its $150.0 million senior secured revolving credit facility due 2017. This resulted in $66.0 million in available revolver capacity as of December 31, 2013.

The Company's cash balance, excluding cash held by the Partnership and its subsidiaries, was $9.2 million as of December 31, 2013, resulting in total liquidity of $75.2 million.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) on February 13, 2014 to discuss fourth quarter and full year 2013 financial results. The conference call can be accessed via Webcast through the Events and Presentations section of the Partnership's website at www.targaresources.com, by going directly to http://ir.targaresources.com/events.cfm?company=LP or by dialing 877-881-2598. The pass code for the dial-in is 40332376. 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 Investor's section of the Partnership's and the Company'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.

Targa Resources Partners – Consolidated Financial Results of Operations

 Three Months Ended December 31,Year Ended December 31,
 2013201220132012
  (In millions, except per unit data)
Revenues   $ 2,159.9  $ 1,526.8  $ 6,556.2  $ 5,883.6
Product purchases  1,804.8  1,267.2  5,378.5  4,878.9
Gross margin (1)  355.1  259.6  1,177.7  1,004.7
Operating expenses  96.5  85.8  376.2  313.0
Operating margin (2)  258.6  173.8  801.5  691.7
Depreciation and amortization expenses  73.1  55.2  271.6  197.3
General and administrative expenses  37.5  31.6  143.1  131.6
Other operating expense  1.2  1.1  9.6  19.9
Income from operations  146.8  85.9  377.2  342.9
Interest expense, net  (35.4)  (29.0)  (131.0)  (116.8)
Equity earnings   4.6  2.2  14.8  1.9
Loss on debt redemptions and amendments  --   (12.8)  (14.7)  (12.8)
Other   --   (6.2)  15.2  (7.8)
Income tax expense   (0.4)  (1.5)  (2.9)  (4.2)
Net income   115.6  38.6  258.6  203.2
Less: Net income attributable to noncontrolling interests  7.0  5.1  25.1  28.6
Net income attributable to Targa Resources Partners LP  $ 108.6  $ 33.5  $ 233.5  $ 174.6
         
Net income attributable to general partner  31.5  20.5  107.5  66.7
Net income attributable to limited partners   77.1  13.0  126.0  107.9
Net income attributable to Targa Resources Partners LP  $ 108.6  $ 33.5  $ 233.5  $ 174.6
         
Basic net income per limited partner unit  $ 0.70  $ 0.14  $ 1.19  $ 1.20
Diluted net income per limited partner unit  0.70  0.14  1.19  1.20
         
Financial data:        
Adjusted EBITDA (3)  $ 214.6  $ 130.6  $ 629.2  $ 514.9
Distributable cash flow (4)  164.9  86.4  440.3  353.9
Capital expenditures  307.4  1,213.1  1,034.5  1,612.9
         
Operating data:        
Crude oil gathered, MBbl/d  65.1  --   46.9  -- 
Plant natural gas inlet, MMcf/d (5),(6)  2,149.5  2,110.2  2,110.2  2,098.3
Gross NGL production, MBbl/d  140.4  135.2  136.8  128.7
Export volumes, MBbl/d (7)  124.5  45.0  66.6  31.6
Natural gas sales, BBtu/d (6)  920.4  937.1  928.2  927.6
NGL sales, MBbl/d  397.6  306.2  316.6  284.5
Condensate sales, MBbl/d  3.1  3.5  3.5  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 and changes in the fair value of the Badlands acquisition contingent consideration and the non-controlling interest portion of depreciation and amortization expenses. This is a non-GAAP financial measure and is discussed under "Targa Resources Partners - Non-GAAP Financial Measures."
(4)  Distributable cash flow is income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash 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.
(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 Year End Results

Three Months Ended December 31, 2013 Compared to Three Months Ended December 31, 2012

The increase in revenues primarily reflects higher NGL sales volumes ($320.0 million), higher commodity prices ($220.1 million), and higher fee-based and other revenues ($109.5 million).

The increase in consolidated gross margin was driven by higher fractionation fees and increased exports activities in our Logistics and Marketing division, increased volumes and commodity prices in our Field Gathering and Processing segment and the inclusion of gross margin from the Badlands operations in 2013. Higher operating expenses were driven by system expansions related to new operations in our Field Gathering and Processing segment, including Badlands, new growth projects in our Logistics and Marketing division, 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 assets acquired in the Badlands acquisition and the timing of major organic investments placed in service including Cedar Bayou Fractionator ("CBF") Train 4, Phase I of the international export expansion project, and the Badlands expansion.

General and administrative expenses increased, reflecting increased compensation-related costs to support our expanding business operations.

The increase in interest expense primarily reflects higher borrowings ($9.6 million), which was offset by the impact of lower effective interest rates ($2.9 million) and increases in capitalized interest that was attributable to our major expansion projects ($0.2 million).

The increase in equity earnings relates to our investment in Gulf Coast Fractionators ("GCF") which had higher throughput after the plant's capacity expansion project completed in 2012.

Losses on debt redemptions and amendments during the fourth quarter of 2012 were attributable to the redemption of our 8¼% Notes due 2016 and the partial write-off of deferred debt issue costs in connection with an amendment of our Revolver.

In 2012, other expense included fees and expenses related to the Badlands acquisition.

The increase in net income attributable to noncontrolling interest is due to the minority interest allocations of earnings at our consolidated joint ventures. Consolidated fourth quarter earnings at our CBF joint venture increased for 2013, consolidated fourth quarter earnings at our Versado joint venture decreased and consolidated fourth quarter earnings at our VESCO joint venture were flat.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Revenues, including the impact of hedging, increased due to the impact of higher commodity volumes ($446.9 million), higher realized prices on natural gas, condensate, and petroleum products ($261.2 million) and higher fee-based and other revenues ($227.8 million), partially offset by lower realized prices on NGLs ($263.2 million).

Higher consolidated gross margin in 2013 includes the contribution of our Badlands acquisition. Other favorable gross margin factors were increased volumes from system expansions and higher gas prices in our Field Gathering and Processing segment and higher fractionation fees and increased export activities in our Logistics and Marketing segments. This significant growth in our asset base brought a higher level of operating expenses in 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.

The increase in depreciation and amortization expenses was primarily due to tangible and intangible assets acquired in the Badlands acquisition and the timing of major organic investments placed in service including CBF Train 4, Phase I of the international export expansion project, and the Badlands expansion.

General and administrative expenses increased, reflecting increased compensation related costs to support our expanding business operations.

Other operating expense in 2013 includes the Versado joint venture cost of repairs less amounts covered by insurance ($4.0 million) related to a fire at the Saunders plant. Other operating expense in 2012 reflects a $15.4 million loss due to a write-off of our investment in the Yscloskey joint venture processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant. Additionally, other operating expense in 2012 includes $3.6 million in costs associated with the clean-up and repairs necessitated by Hurricane Isaac at our Coastal Straddle plants. 

The increase in interest expense primarily reflects higher borrowings ($36.2 million), partially offset by the impact of lower effective interest rates ($7.7 million) and increases in capitalized interest attributable to our major expansion projects ($14.4 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 related to the expansion of the facility.

Losses on debt redemptions and amendments during 2013 are attributable to premiums paid and write-off of debt issue costs in connection with the redemption of the outstanding balance of the 11¼% Notes and the redemption of $100 million of the Partnership's 6?% Notes.

The increase in other income was attributable to the elimination of the contingent consideration associated with the Badlands acquisition, reflecting management's current assessment that the stipulated volumetric thresholds will not be met.

Net income attributable to noncontrolling interests declined during 2013, as the impact of lower earnings at our Versado and VESCO joint ventures more than offset the impact of higher earnings at CBF.

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 in West Texas and New Mexico and North Dakota.

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

 Three Months Ended December 31, Year Ended December 31,
 2013201220132012
 ($ in millions, except operating statistics and price amounts)
Gross margin  $ 120.5  $ 86.2  $ 435.7  $ 357.4
Operating expenses  41.7  35.6  165.2  126.2
Operating margin  $ 78.8  $ 50.6  $ 270.5  $ 231.2
Operating statistics (1):        
Plant natural gas inlet, MMcf/d (2),(3)        
Sand Hills  155.2  149.6  155.8  145.2
SAOU  157.8  136.0  154.1  124.8
North Texas System  306.5  264.0  292.4  244.5
Versado  135.0  170.8  156.4  167.4
Badlands (4)  30.5  --   21.4  -- 
   785.0  720.4  780.1  681.9
Gross NGL production, MBbl/d (3)        
Sand Hills  17.1  17.4  17.5  16.9
SAOU  22.8  20.2  22.5  19.2
North Texas System  31.7  29.1  31.1  26.8
Versado  16.0  20.5  18.9  19.7
Badlands  2.6  --   1.9  -- 
   90.2  87.2  91.9  82.6
Crude oil gathered, MBbl/d  65.1  --   46.9  -- 
Natural gas sales, BBtu/d (3)  381.8  340.2  376.3  325.0
NGL sales, MBbl/d  75.3  72.7  71.4  68.5
Condensate sales, MBbl/d   2.7  3.0  3.2  3.2
Average realized prices (5):        
Natural gas, $/MMBtu  3.38  3.15  3.44  2.60
NGL, $/gal  0.82  0.77  0.76  0.87
Condensate, $/Bbl  92.07  82.23  92.89  88.49
 
(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 year and the denominator is the number of calendar days during the year.
(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)  Badlands natural gas inlet represents the total wellhead gathered volume.
(5)  Average realized prices exclude the impact of hedging settlements presented in Other.


Three Months Ended December 31, 2013 Compared to Three Months Ended December 31, 2012

The increase in gross margin was primarily due to the inclusion of Badlands operations in 2013, higher overall throughput volumes and higher commodity 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. However, throughput was somewhat constrained by operational issues and severe cold weather.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

The increase in gross margin was primarily due to the inclusion of Badlands operations in 2013, higher overall throughput volumes and higher natural gas and condensate sales prices, partially offset by lower NGL sales prices. The increase in plant inlet volumes was largely attributable to new well connects which increased available supply across each of our areas of operations, offset by the Saunders fire at Versado and by other operational issues and severe cold weather. 

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

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,
 2013201220132012
 ($ in millions, except operating statistics and price amounts)
Gross margin  $ 36.2  $ 35.0  $ 132.3  $ 162.2
Operating expenses   12.0  12.2  46.9  47.1
Operating margin  $ 24.2  $ 22.8  $ 85.4  $ 115.1
Operating statistics (1):        
Plant natural gas inlet, MMcf/d (2),(3)        
LOU (4)  389.1  307.2  350.9  260.6
VESCO  528.9  583.1  515.5  479.6
Other Coastal Straddles  446.4  499.5  463.7  676.2
   1,364.4  1,389.8  1,330.1  1,416.4
Gross NGL production, MBbl/d (3)        
LOU  12.2  9.2  10.2  8.6
VESCO  24.8  25.2  21.5  22.1
Other Coastal Straddles  13.2  13.5  13.2  15.4
   50.2  47.9  44.9  46.1
Natural gas sales, BBtu/d (3)  328.6  279.7  296.0  298.5
NGL sales, MBbl/d   47.1  43.6  41.8  42.5
Condensate sales, MBbl/d   0.4  0.5  0.4  0.3
Average realized prices:        
Natural gas, $/MMBtu  3.75  3.43  3.73  2.78
NGL, $/gal  0.86  0.86  0.83  0.96
Condensate, $/Bbl   96.14  98.70  104.38  103.57
 
(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 year and the denominator is the number of calendar days during the year.
(2)  Plantnatural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
(3)  Plantnatural 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 Big Lake processing plant acquired in July 2012.


Three Months Ended December 31, 2013 Compared to Three Months Ended December 31, 2012

The increase in gross margin was primarily due to higher NGL production and higher NGL sales resulting from additional throughput volumes at LOU. The decrease in plant inlet volumes was largely attributable to the decline in offshore and off-system supply volumes at VESCO and the Coastal Straddles, partially offset by higher GPM volumes at LOU.

The decrease in operating expenses was primarily due to the fourth quarter 2012 impact of system maintenance and repair costs at VESCO, partially offset by higher system maintenance and repair costs at LOU.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

The decrease in gross margin was primarily due to lower NGL prices, less favorable frac spread and lower throughput volumes at VESCO and the Other Coastal Straddles. 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 2012 volumes also reflect the shutdown of Coastal Straddle plant operations during Hurricane Isaac. 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 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 liquefied petroleum gas ("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,
 2013201220132012
 ($ in millions, except operating statistics)
Gross margin  $ 137.0  $ 78.0  $ 408.2  $ 286.0
Operating expenses  33.6  28.9  125.9  97.7
Operating margin  $ 103.4  $ 49.1  $ 282.3  $ 188.3
Operating statistics, MBbl/d (1):        
Fractionation volumes  318.3  298.7  287.6  299.2
LSNG treating volumes  25.6  18.4  20.1  22.4
Benzene treating volumes  24.3  15.4  17.5  19.0
         
(1)  For all volume statistics presented, the numerator is the total volume during the year and the denominator is the number of calendar days during the year.


Three Months Ended December 31, 2013 Compared to Three Months Ended December 31, 2012

Gross margin increased due to increased fractionation and LPG export activity. Fractionation activity was higher due to increased fractionation fees, higher volumes resulting from the CBF Train 4 project, which came on line in the third quarter 2013, and higher contractual capacity reservation fees. LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 125 MBbl/d for the fourth quarter 2013, compared to 45 MBbl/d for the same period last year. The increased volumes reflect an increase in ongoing LPG export activity due to our international export expansion project, which was placed into service in September 2013. In addition to the export volume increase, per unit export terminaling fees were also higher. Storage revenues were up due to increased rates and new customers, and treating revenues increased due to higher volumes in the fourth quarter 2013 compared to the same period last year.

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

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Gross margin increased primarily due to fractionation operations and LPG export activity. The lower year-to-date 2013 fractionation volumes were due to the planned maintenance turnaround at the Cedar Bayou Facility, ethane rejection at certain gas processing plants and pipeline operating issues at non-Partnership facilities. Improvements in 2013 resulted from higher fractionation fees, CBF Train 4 which commenced commercial operations during the third quarter of 2013 and higher contractual capacity reservation fees. Gross margin results also include 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 67 MBbl/d in 2013, compared to 32 MBbl/d for the previous year. The higher volumes reflect a significant increase in ongoing LPG export activity primarily due to our international export expansion project, which was placed into service in September 2013. Terminaling rates per unit volume were also higher and storage revenues increased due to increased rates and new customers. Gross margin for 2013 also benefitted from the renewable fuels project in our Petroleum Logistics business.

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

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,
 2013201220132012
 ($ in millions, except operating statistics and price amounts)
Gross margin  $ 59.7  $ 47.9  $ 185.2  $ 154.1
Operating expenses  11.8  9.7  43.3  38.1
Operating margin  $ 47.9  $ 38.2  $ 141.9  $ 116.0
Operating statistics (1):        
NGL sales, MBbl/d  399.2  312.4  318.4  289.8
Average realized prices:        
NGL realized price, $/gal  1.04  0.91  0.93  0.98
         
(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 year and the denominator is the number of calendar days during the year.


Three Months Ended December 31, 2013 Compared to Three Months Ended December 31, 2012

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

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

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Gross margin increased primarily due to significantly higher terminaling fees from LPG export activity (which benefit both the Logistics Assets and Marketing and Distribution segments). The favorable impacts of higher barge and wholesale terminal utilization and of higher wholesale margins were offset by lower natural gas marketing processing opportunities during 2013.

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

Other

  Three Months Ended December 31,  Year Ended December 31, 
 2013201220132012
 (In millions)
Gross margin  $ 4.4  $ 13.0  $ 21.4  $ 41.1
Operating margin  $ 4.4  $ 13.0  $ 21.4  $ 41.1


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

The primary purpose of the Partnership's commodity risk management activities is to manage its exposure to commodity price risk and reduce volatility in its operating cash flow due to fluctuations in commodity prices. The Partnership has hedged the commodity price associated with a portion of its expected (i) natural gas equity volumes in Field Gathering and Processing Operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing as well as in the LOU portion of the Coastal Gathering and Processing Operations that result from its percent of proceeds on liquids processing arrangements by entering into derivative instruments.

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

 Three Months Ended December 31,Year Ended December 31,
 2013201220132012
 (In millions)
Natural gas  $ 3.1  $ 6.8  $ 11.2  $ 33.8
NGL  1.5  5.7  12.8  9.1
Crude oil  (0.2)  0.5  (2.6)  (1.8)
   $ 4.4  $ 13.0  $ 21.4  $ 41.1


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 complementary midstream energy assets. The Partnership is a leading provider of midstream natural gas and natural gas liquid services in the United States. In addition, the Partnership provides crude oil gathering and crude oil and petroleum product terminaling services. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting, terminaling and selling NGLs and NGL products; gathering, storing, and terminaling crude oil; and storing and terminaling petroleum products. The Partnership reports its operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments - (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing, consisting of two reportable segments - (a) Logistics Assets and (b) Marketing and Distribution. The financial results of the Partnership's commodity hedging activities are reported in Other.

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

Targa Resources Partners - Non-GAAP Financial Measures

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

Distributable Cash Flow - The Partnership defines distributable cash flow as net income attributable to Targa Resources Partners LP plus: depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash losses (gains) on mark-to-market derivative contracts, debt repurchases and redemptions, early debt extinguishments and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs), and changes in the fair value of the Badlands acquisition contingent consideration. This measure includes any impact of non-controlling 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 December 31,Year Ended December 31,
 2013201220132012
  (In millions) 
Reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow:        
Net income attributable to Targa Resources Partners LP  $ 108.6  $ 33.5  $ 233.5  $ 174.6
Depreciation and amortization expenses  73.1  55.2  271.6  197.3
Deferred income tax expense  0.1  0.5  0.9  1.7
Amortization in interest expense  3.7  4.0  15.5  17.6
Loss on debt redemptions and amendments  --   12.8  14.7  12.8
Change in contingent consideration  --   --   (15.3)  -- 
Loss on sale or disposition of assets  0.8  0.1  3.9  15.6
Risk management activities  (0.3)  1.6  (0.5)  5.4
Maintenance capital expenditures  (19.5)  (19.6)  (79.9)  (67.6)
Other (1)  (1.6)  (1.7)  (4.1)  (3.5)
Targa Resources Partners LP distributable cash flow  $ 164.9  $ 86.4  $ 440.3  $ 353.9
 
(1)  Includes the noncontrolling interest portion of maintenance capital expenditures, and depreciation and amortization expenses. 


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

The economic substance behind 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 December 31,Year Ended December 31,
 2013201220132012
 (In millions)
 
Reconciliation of net cash provided by Targa Resources Partners LP operating activities to Adjusted EBITDA:        
Net cash provided by operating activities  $ 135.1  $ 150.0  $ 411.4  $ 465.4
Net income attributable to noncontrolling interests  (7.0)  (5.1)  (25.1)  (28.6)
Interest expense, net (1)  31.7  25.0  115.5  99.2
Loss on debt redemptions and amendments  (0.1)  (12.8)  (14.7)  (12.8)
Change in contingent consideration   (0.1)  --   (15.3)  -- 
Current income tax expense  0.3  1.0  2.0  2.5
Other (2)  (3.0)  8.1  (5.0)  (6.4)
Changes in operating assets and liabilities which used (provided) cash:      
Accounts receivable and other assets  136.9  70.0  230.3  (96.1)
Accounts payable and other liabilities  (79.2)  (105.6)  (69.9)  91.7
Targa Resources Partners LP Adjusted EBITDA  $ 214.6  $ 130.6  $ 629.2  $ 514.9
 
(1)  Net of amortization of debt issuance costs, discount and premium included in interest expense of $3.7 million and $4.0 million for the three months ended December 31, 2013 and 2012, and $15.5 million and $17.6 million for years ended December 31, 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 and 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 December 31, Year Ended December 31, 
 2013201220132012
  (In millions) 
Reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA:        
Net income attributable to Targa Resources Partners LP  $ 108.6  $ 33.5  $ 233.5  $ 174.6
Interest expense, net   35.4  29.0  131.0  116.8
Income tax expense  0.4  1.5  2.9  4.2
Depreciation and amortization expenses  73.1  55.2  271.6  197.3
Loss on sale or disposition of assets  0.8  0.1  3.9  15.6
Loss on debt redemptions and amendments  --   12.8  14.7  12.8
Change in contingent consideration  --   --   (15.3)  -- 
Risk management activities  (0.3)  1.6  (0.5)  5.4
Noncontrolling interests adjustment (1)  (3.4)  (3.1)  (12.6)  (11.8)
Targa Resources Partners LP Adjusted EBITDA  $ 214.6  $ 130.6  $ 629.2  $ 514.9
 
(1)  Noncontrolling interest portion of depreciation and amortization expenses.


Gross MarginThe Partnership defines gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as the Partnership's contract mix and 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. The gross margin impacts of cash flow settlements are reported in Other.

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

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

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

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

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

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

 Three Months Ended December 31,Year Ended December 31,
 2013201220132012
 (In millions)
Reconciliation of Targa Resources Partners LP gross margin and operating margin to net income:        
Gross margin  $ 355.1  $ 259.6  $ 1,177.7  $ 1,004.7
Operating expenses  (96.5)  (85.8)  (376.2)  (313.0)
Operating margin  258.6  173.8  801.5  691.7
Depreciation and amortization expenses  (73.1)  (55.2)  (271.6)  (197.3)
General and administrative expenses  (37.4)  (31.6)  (143.1)  (131.6)
Other Operating income (loss)  --   --   --   -- 
Interest expense, net  (35.4)  (29.0)  (131.0)  (116.8)
Income tax expense  (0.4)  (1.5)  (2.9)  (4.2)
Gain (loss) on sale or disposition of assets  (0.8)  3.2  (3.9)  (15.6)
Loss on debt redemption and early debt extinguishments  --   (12.8)  (14.7)  (12.8)
Change in contingent consideration   --   --   15.3  -- 
Other, net  4.1  (8.3)  9.0  (10.2)
Targa Resources Partners LP net income  $ 115.6  $ 38.6  $ 258.6  $ 203.2


Targa Resources Corp. - Non-GAAP Financial Measures

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

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

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

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

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

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

 Three Months Ended December 31,Year Ended December 31,
 2013201220132012
 (In millions)
Reconciliation of Net Income attributable to Targa Resources Corp. to Distributable Cash Flow        
Net income of Targa Resources Corp.  $ 95.7  $ 27.6  $ 201.3  $ 159.3
Less: Net income of Targa Resources Partners LP  (115.6)  (38.6)  (258.6)  (203.2)
Net loss for TRC Non-Partnership  (19.9)  (11.0)  (57.3)  (43.9)
TRC Non-Partnership income tax expense  17.5  10.7  45.3  32.7
Distributions from the Partnership   41.5  30.7  149.0  103.3
Non-cash loss (gain) on hedges  0.1  (0.6)  0.3  (2.2)
Loss on debt redemptions and amendments  --   0.2  --   0.2
Depreciation - Non-Partnership assets  0.1  (1.9)  0.3  0.3
Current cash tax expense (1)  (15.8)  (5.6)  (31.0)  (20.8)
Taxes funded with cash on hand (2)  3.1  2.1  10.0  8.7
Distributable cash flow  $ 26.6  $ 24.6  $ 116.6  $ 78.3
 
(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, 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 December 31,Year Ended December 31,
 2013201220132012
 (In millions)
Targa Resources Corp. Distributable Cash Flow  
Distributions declared by Targa Resources Partners LP associated with:
General Partner Interests  $ 2.3  $ 1.8  $ 8.4  $ 6.2
Incentive Distribution Rights 29.5  20.1  103.1  63.3
Common Units 9.7  8.8  37.5  33.8
Total distributions declared by Targa Resources Partners LP 41.5  30.7  149.0  103.3
Income (expenses) of TRC Non-Partnership        
General and administrative expenses  (1.6)  (1.6)  (8.4)  (8.2)
Interest expense, net  (0.8)  (0.8)  (3.1)  (4.0)
Current cash tax expense (1)  (15.8)  (5.6)  (31.0)  (20.8)
Taxes funded with cash on hand (2) 3.1  2.1  10.0  8.7
Other income (expense) 0.2  (0.2)  0.1  (0.7)
Distributable cash flow  $ 26.6  $ 24.6  $ 116.6  $ 78.3
 
(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, 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.


Forward-Looking Statements

Certain statements in this release are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Partnership and the Company expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Partnership's and the Company's control, which could cause results to differ materially from those expected by management of the Partnership and the Company. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas and natural gas liquids; the timing and success of business development efforts; and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Partnership's and the Company's filings with the Securities and Exchange Commission, including their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. Neither the Partnership nor the Company undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
 
CONSOLIDATED BALANCE SHEETS
(In millions)
 December 31,
 20132012
ASSETS   
Current assets:    
Cash and cash equivalents  $ 57.5  $ 68.0
Trade receivables  658.6  514.9
Inventories  150.7  99.4
Assets from risk management activities  2.0  29.3
Other current assets  7.1  3.3
Total current assets  875.9  714.9
Property, plant and equipment, net  4,345.4  3,533.2
Intangible assets, net  653.4  680.8
Long-term assets from risk management activities  3.1  5.1
Goodwill  --   -- 
Other long-term assets  93.6  91.7
Total assets   $ 5,971.4  $ 5,025.7
LIABILITIES AND PARTNERS' CAPITAL   
Current liabilities:    
Accounts payable and accrued liabilities  $ 773.6  $ 701.2
Liabilities from risk management activities  8.0  7.4
Total current liabilities  781.6  708.6
Long-term debt   2,905.3  2,393.3
Long-term liabilities from risk management activities  1.4  4.8
Other long-term liabilities  64.7  58.9
Owners' equity:    
Targa Resources Partners LP owner's equity  2,057.8 1,709.6
Noncontrolling interests in subsidiaries  160.6 150.5
Total owners' equity  2,218.4  1,860.1
Total liabilities and owners' equity  $ 5,971.4  $ 5,025.7
 
 
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
 
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit amounts)
 Three Months EndedYear Ended
 December 31,December 31,
 2013201220132012
REVENUES  $ 2,159.9  $ 1,526.8  $ 6,556.2  $ 5,883.6
Product purchases  1,804.8  1,267.2  5,378.5  4,878.9
Operating expenses  96.5  85.8  376.2  313.0
Depreciation and amortization expenses  73.1  55.2  271.6  197.3
General and administrative expenses  37.5  31.6  143.1  131.6
Other operating expense  1.2  1.1  9.6  19.9
Total costs and expenses  2,013.1  1,440.9  6,179.0  5,540.7
INCOME FROM OPERATIONS  146.8  85.9  377.2  342.9
Other income (expense):        
Interest expense, net  (35.4)  (29.0)  (131.0)  (116.8)
Equity earnings   4.6  2.2  14.8  1.9
Loss on debt redemptions and amendments  --   (12.8)  (14.7)  (12.8)
Other expense  --   (6.2)  15.2  (7.8)
Income before income taxes  116.0  40.1  261.5  207.4
Income tax expense  (0.4)  (1.5)  (2.9)  (4.2)
NET INCOME  115.6  38.6  258.6  203.2
Less: Net income attributable to noncontrolling interests  7.0  5.1  25.1  28.6
NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP  $ 108.6  $ 33.5  $ 233.5  $ 174.6
         
Net income attributable to general partner  $ 31.5  $ 20.5  $ 107.5  $ 66.7
Net income attributable to limited partners   77.1  13.0  126.0  107.9
Net income attributable to Targa Resources Partners LP  $ 108.6  $ 33.5  $ 233.5  $ 174.6
         
Net income per limited partner unit - basic   $ 0.70  $ 0.14  $ 1.19  $ 1.20
Net income per limited partner unit - diluted  0.70  0.14  1.19  1.20
         
Weighted average limited partner units outstanding - basic  109.4  94.0  105.5  90.1
Weighted average limited partner units outstanding - diluted  109.9  94.1  105.7  90.2
 
 
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
 
CONSOLIDATED CASH FLOW INFORMATION
(In millions)
 Year Ended December 31,
 20132012
CASH FLOWS FROM OPERATING ACTIVITIES    
Net income  $ 258.6  $ 203.2
Adjustments to reconcile net income to net cash provided by operating activities:    
Amortization in interest expense  15.5  17.6
Compensation on equity grants  6.0  3.6
Depreciation and amortization expense  271.6  197.3
Accretion of asset retirement obligations  3.9  3.9
Deferred income tax expense  0.9  1.7
Equity earnings, net of distributions  (2.8)  -- 
Risk management activities  (0.5)  5.3
Loss on debt redemptions and amendments  14.7  12.8
Loss on sale or disposal of assets  3.9  15.6
Changes in operating assets and liabilities  (160.4)  4.4
Net cash provided by operating activities  411.4  465.4
CASH FLOWS FROM INVESTING ACTIVITIES    
Outlays for property, plant and equipment  (1,013.6)  (582.3)
Business acquisition, net of cash acquired  --   (996.2)
Purchase of materials and supplies  (17.7)  -- 
Investment in unconsolidated affiliate  --   (16.8)
Return of capital from unconsolidated affiliate  --   0.5
Other, net  5.0  1.0
Net cash used in investing activities  (1,026.3)  (1,593.8)
CASH FLOWS FROM FINANCING ACTIVITIES    
Borrowings under credit facility  1,613.0  1,595.0
Repayments of credit facility  (1,838.0)  (1,473.0)
Proceeds from issuance of senior notes  625.0  1,000.0
Redemption of senior notes  (183.2)  (217.7)
Borrowings from accounts receivable securitization facility  373.3  -- 
Repayments of accounts receivable securitization facility  (93.6)  -- 
Costs incurred in connection with financing arrangements  (15.3)  (35.7)
Equity offerings  535.5  575.0
Distributions   (397.3)  (285.7)
Contributions from parent  --   1.0
Contributions from noncontrolling interests  4.3  3.2
Distributions to noncontrolling interests  (19.3)  (21.3)
Net cash provided by financing activities  604.4  1,140.8
Net change in cash and cash equivalents  (10.5)  12.4
Cash and cash equivalents, beginning of period  68.0  55.6
Cash and cash equivalents, end of period  $ 57.5  $ 68.0
 
 
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,
 2013201220132012
REVENUES  $ 2,159.8  $ 1,527.3  $ 6,556.0  $ 5,885.7
Product purchases  1,804.8  1,267.2  5,378.5  4,879.0
Operating expenses  96.5  85.8  376.3  313.1
Depreciation and amortization expenses  73.2  53.3  271.9  197.6
General and administrative expenses  39.0  33.5  151.5  139.8
Other operating expense  1.3  1.1  9.6  19.9
Total costs and expenses  2,014.8  1,440.9  6,187.8  5,549.4
INCOME FROM OPERATIONS  145.0  86.4  368.2  336.3
Other income (expense):        
Interest expense, net  (36.2)  (29.8)  (134.1)  (120.8)
Equity earnings  4.7  2.2  14.8  1.9
Loss on debt redemption and early debt extinguishments  --   (12.8)  (14.7)  (12.8)
Other expenses  --   (6.2)  15.3  (8.4)
Income before income taxes  113.5  39.8  249.5  196.2
Income tax expense  (17.9)  (12.2)  (48.2)  (36.9)
NET INCOME  95.6  27.6  201.3  159.3
Less: Net income attributable to noncontrolling interests  75.2  16.4  136.2  121.2
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS  $ 20.4  $ 11.2  $ 65.1  $ 38.1
         
Net income available per common share - basic   $ 0.49  $ 0.27  $ 1.56  $ 0.93
Net income available per common share - diluted  $ 0.48  $ 0.27  $ 1.55  $ 0.91
         
Weighted average shares outstanding - basic   41.7  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)  
   
 December 31, 2013
Cash and cash equivalents: 
TRC Non-Partnership  $ 9.2
Targa Resources Partners   57.5
Total cash and cash equivalents  $ 66.7
Long-term debt:  
TRC Non-Partnership  $ 84.0
Targa Resources Partners   2,905.3
Total long-term debt  $ 2,989.3

CONTACT: 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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Source: Targa Resources Partners LP; Targa Resources Corp.


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