News: $NGLS $TRGP – Targa Resources Partners LP and Targa Resources Corp. Report Third Quarter 2015 Financial Results

HOUSTON, Nov. 03, 2015 (GLOBE NEWSWIRE) — Targa Resources Partners LP (NYSE:NGLS) (“Targa Resources Partners”, the “Partnership” or “TRP”) and Targa Resources Corp. (NYSE:TRGP) (“TRC” or the “Company”) today reported third quarter results.

Targa Resources Partners – Third Quarter 2015 Financial Results

Third quarter 2015 net income attributable to Targa Resources Partners was $48.5 million compared to $128.3 million for the third quarter of 2014. Net income per diluted limited partner unit was $0.02 in the third quarter of 2015 compared to $0.78 for the third quarter of 2014. The Partnership reported earnings before interest, income taxes, depreciation and amortization and other non-cash items (“Adjusted EBITDA”) of $305.8 million for the third quarter of 2015 compared to $248.8 million for the third quarter of 2014. The Partnership’s distributable cash flow for the third quarter of 2015 of $220.7 million corresponds to distribution coverage of approximately 1.1 times the $200.4 million in total distributions to be paid on November 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”)).

“Targa’s third quarter results highlight the benefits of our diverse asset footprint, fee-based margin and our continued focus on cost savings and execution,” said Joe Bob Perkins, Chief Executive Officer of the Partnership and of the Company. “We continue to develop attractive projects, demonstrate access to capital markets and execute in a cost effective manner, positioning Targa to successfully navigate the challenging environment ahead.”

On October 20, 2015, the Partnership announced a cash distribution for the third quarter 2015 of $0.8250 per common unit, or $3.30 per unit on an annualized basis, representing an unchanged distribution from the previous quarter and approximately 3% growth over the distribution for the third quarter 2014. The cash distribution will be paid on November 13, 2015 on all outstanding common units to holders of record as of the close of business on November 2, 2015. The total distribution paid will be $200.4 million, with $139.0 million to the Partnership’s third-party limited partners and $61.4 million to TRC for its ownership of common units, incentive distribution rights (“IDRs”) and its 2% general partner interest in the Partnership.

Targa Resources Corp. – Third Quarter 2015 Financial Results

TRC reported net income available to common shareholders of $12.7 million for the third quarter 2015 compared to $30.7 million for the third quarter 2014. The net income per diluted common share was $0.23 in the third quarter of 2015 compared to net income per diluted common share of $0.73 for the third quarter of 2014.

The Company, which as of September 30, 2015 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 16,309,594 common units of the Partnership, presents its results consolidated with those of the Partnership.

Third quarter 2015 distributions to be paid on November 13, 2015 by the Partnership to the Company will be $61.4 million, with $13.5 million, $43.9 million and $4.0 million paid with respect to common units, IDRs and general partner interests, respectively.

On October 20, 2015, TRC declared a quarterly dividend of $0.9100 per share of its common stock for the three months ended September 30, 2015, or $3.64 per share on an annualized basis, representing increases of approximately 4% over the previous quarter’s dividend and 24% over the dividend for the third quarter of 2014. Total cash dividends of approximately $50.9 million will be paid November 16, 2015 on all outstanding common shares to holders of record as of the close of business on November 2, 2015.

The Company’s distributable cash flow for the third quarter 2015 was $53.7 million compared to $51.2 million in total declared dividends for the quarter (see the section of this release entitled “Targa Resources Corp. – Non-GAAP Financial Measures” for a discussion of distributable cash flow and reconciliations of this measure to its most directly comparable financial measure calculated and presented in accordance with GAAP).

Targa Resources Partners Third Quarter 2015 – Capitalization, Liquidity and Financing

Total funded debt of the Partnership as of September 30, 2015 was $5,471.9 million including $435.0 million outstanding under the Partnership’s $1.6 billion senior secured revolving credit facility, $135.5 million outstanding under the Partnership’s accounts receivable securitization facility, and $4,901.4 million of senior unsecured notes, net of unamortized discounts.

As of September 30, 2015, after giving effect to $11.2 million in outstanding letters of credit, the Partnership had available revolver capacity of $1,153.8 million.

In September 2015, the Partnership issued $600 million in aggregate principal amount of 6¾% Senior Notes due 2024 (the “6¾% Notes”). The 6¾% Notes resulted in approximately $595.0 million of net proceeds after costs, which were used to reduce borrowings under the Partnership’s senior secured revolving credit facility and for general partnership purposes. The 6¾% Notes are unsecured senior obligations that have substantially the same terms and covenants as its other senior notes.

In October 2015, under its automatic shelf registration statement filed in April 2013 and amended by a post-effective amendment filed in October 2015 (the “April 2013 Shelf”), the Partnership completed an offering of 4,400,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Preferred Units”) at a price of $25.00 per unit. Pursuant to the exercise of the underwriters’ overallotment option, the Partnership sold an additional 600,000 Preferred Units at a price of $25.00 per unit. The Partnership received net proceeds after costs of approximately $121.1 million, which were to reduce borrowings under its senior secured credit facility and for general partnership purposes. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA”.

Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership’s general partner. Distributions on the Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but not including, November 1, 2020, at a rate equal to 9.0% per annum of the stated liquidation preference. On and after November 1, 2020, distributions on the Preferred Units will accumulate at an annual floating rate equal to the one- month LIBOR plus a spread of 7.71%.

On October 20, 2015, the Partnership announced that the board of directors of its general partner declared a prorated monthly cash distribution of $0.10 per Preferred Unit.  This cash distribution is the initial distribution payable on the Preferred Units for the period from October 15, 2015 through October 31, 2015, and will be paid November 16, 2015 on all outstanding Preferred Units to holders of record as of the close of business on October 30, 2015.

Targa Resources Corp. Third Quarter 2015 – Capitalization, Liquidity and Financing

Total funded debt of the Company as of September 30, 2015, excluding debt of the Partnership, was $602.4 million including $445.0 million outstanding under the Company’s $670.0 million senior secured revolving credit facility due 2020 and $157.4 million, net of unamortized discounts, outstanding on the Company’s senior secured term loan due 2022. This resulted in $225.0 million in available revolver capacity as of September 30, 2015.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 11:00 a.m. Eastern time (10:00 a.m. Central time) on November 3, 2015 to discuss third quarter 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 60174409. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following the completion of the Webcast through the Investors section of the Partnership’s website. An updated investor presentation will also be available in the Events and Presentations section of the Partnership’s and the Company’s websites following the completion of the conference call.

Targa Resources Partners – Consolidated Financial Results of Operations

    Three Months Ended September 30,       Nine Months Ended September 30,
    2015    2014        2015    2014 
                             
    ($ in millions, except per unit data and operating statistics)
Revenues                             
Sales of commodities   $   1,321.3     $   2,009.2         $   4,119.6     $   5,853.3  
Fees from midstream services       310.8         279.1             891.6         730.4  
Total revenues:       1,632.1         2,288.3             5,011.2         6,583.7  
Product purchases       1,172.4         1,880.5             3,677.7         5,412.2  
Gross margin (1)       459.7         407.8             1,333.5         1,171.5  
Operating expenses       133.6         112.8             381.8         323.6  
Operating margin (2)       326.1         295.0             951.7         847.9  
Depreciation and amortization expenses       165.8         87.5             448.3         252.8  
General and administrative expenses       42.9         40.4             130.1         115.3  
Other operating (income) expenses       0.1         (4.3 )           0.6         (5.3 )
Income from operations       117.3         171.4             372.7         485.1  
Interest expense, net       (64.1 )       (36.0 )           (177.2 )       (104.1 )
Equity earnings       (1.6 )       4.7             (1.1 )       13.8  
Loss from financing activities       (0.5 )                   (0.5 )        
Other income (expense)       1.8         (0.6 )           (9.1 )       (0.6 )
Income tax (expense) benefit       0.4         (1.3 )           (0.4 )       (3.7 )
Net income       53.3         138.2             184.4         390.5  
Less: Net income attributable to noncontrolling interests       4.8         9.9             17.3         30.9  
Net income attributable to Targa Resources Partners LP   $   48.5     $   128.3         $   167.1     $   359.6  
                             
Net income attributable to general partner       44.9         38.6             132.0         108.2  
Net income attributable to limited partners       3.6         89.7             35.1         251.4  
Net income attributable to Targa Resources Partners LP   $   48.5     $   128.3         $   167.1     $   359.6  
                             
Basic net income per limited partner unit   $   0.02     $   0.78         $   0.21     $   2.21  
Diluted net income per limited partner unit       0.02         0.78             0.21         2.20  
                             
Financial data:                            
Adjusted EBITDA (3)   $   305.8     $   248.8         $   866.5     $   712.1  
Distributable cash flow (4)       220.7         194.6             630.8         564.0  
Capital expenditures       186.2         142.9             571.0         533.8  
                             
Operating data:                            
Crude oil gathered, MBbl/d       108.9         99.2             105.4         86.0  
Plant natural gas inlet, MMcf/d (5),(6),(7)       3,452.5         2,170.3             3,163.2         2,111.2  
Gross NGL production, MBbl/d (7)       283.4         157.6             255.7         152.2  
Export volumes, MBbl/d (8)       184.1         205.9             180.0         160.5  
Natural gas sales, BBtu/d (6),(7)       1,932.3         923.7             1,721.4         890.5  
NGL sales, MBbl/d (7)       499.2         441.6             501.2         401.6  
Condensate sales, MBbl/d (7)       10.8         4.8             9.5         4.4  

__________

(1) Gross margin is a non-GAAP financial measure and is discussed under “Targa Resources Partners – Non-GAAP Financial Measures.”

(2) Operating margin is a non-GAAP financial measure and is discussed under “Targa Resources Partners – Non-GAAP Financial Measures.”

(3) Adjusted EBITDA is net income attributable to Targa Resources Partners LP before: interest, income taxes, depreciation and amortization, gains or losses on debt repurchases, redemptions, amendments, exchanges and early debt extinguishments and asset disposals, risk management activities related to derivative instruments including the cash impact of hedges acquired in the Partnership’s merger with Atlas Pipeline Partners, L.P. (the “APL merger”), non-cash compensation on  TRP equity grants, transactions costs related to business acquisitions, earnings/losses from unconsolidated affiliates net of distributions  and the noncontrolling 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 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, including the cash impact of hedges acquired in the APL merger; debt repurchases, redemptions, amendments, exchanges and early debt extinguishments; non-cash compensation on TRP equity grants; transaction costs related to business acquisitions; earnings/losses from unconsolidated affiliates net of distributions and asset disposals and less maintenance capital expenditures (net of any reimbursements of project costs). This measure includes any impact of noncontrolling interests. This is a non-GAAP financial measure and is discussed under “Targa Resources Partners – Non-GAAP Financial Measures.”

(5) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than in Badlands, where it represents total wellhead gathered volume.

(6) Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(7) These volume statistics are presented with the numerator as the total volume sold during the quarter and the denominator as the number of calendar days during the quarter.

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

Targa Resources Partners – Review of Consolidated Third Quarter Results

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

Revenues from commodity sales declined as the effect of significantly lower commodity prices ($1,749.6 million) exceeded the favorable impacts of inclusion of a full quarter of operations of Targa Pipeline Partners LP (“TPL”) ($388.2 million), other volume increases ($648.3 million), and favorable hedge settlements ($21.8 million). Fee-based and other revenues increased due to the inclusion of TPL’s fee revenue ($55.0 million), which were partially offset by lower export fees.

Offsetting lower commodity revenues was a commensurate reduction in product purchases due to significantly lower commodity costs ($1,050.9 million), which were partially offset by the inclusion of product purchases related to TPL’s operations ($342.8 million).

The higher gross margin in 2015 was attributable to inclusion of TPL operations, increased throughput related to other system expansions in TRP’s Field Gathering and Processing segment, recognition of a renegotiated commercial contract and increased terminaling and storage fees, partially offset by lower fractionation and export margin in TRP’s Logistics and Marketing segments. Higher operating expenses are due to the inclusion of TPL’s operations ($29.4 million), which more than offset the cost savings generated throughout TRP’s other operating areas. 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 the impact of TPL, the planned increased amortization of the Badlands intangible assets and growth investments placed in service after June 2014, including the international export expansion project, continuing development at Badlands and other system expansions.

Higher general and administrative expenses is due to the inclusion of TPL general and administrative costs ($8.4 million), which was partially offset by general and administrative savings ($5.9 million), primarily from lower compensation and related costs.

The increase in interest expense primarily reflects higher borrowings attributable to the APL merger and lower capitalized interest associated with major capital projects compared to 2014.

Net income attributable to noncontrolling interests decreased due to lower earnings in 2015 that impacted TRP’s Cedar Bayou Fractionators, VESCO and Versado joint ventures, and the inclusion of losses from TPL’s joint ventures.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

Revenues declined as the effect of significantly lower commodity prices ($5,049.4 million) exceeded the favorable impacts of the inclusion of seven months of operations of TPL ($928.8 million), other volume increases ($2,321.9 million), and favorable hedge settlements ($60.7 million). Fee-based and other revenues increased due to the inclusion of TPL’s operating results ($115.6 million), which were partially offset by lower export fees.

Offsetting lower commodity revenues was a commensurate reduction in product purchases due to significantly lower commodity costs ($2,550.1 million), which were partially offset by the inclusion of product purchases related to TPL’s operations ($815.6 million).

The higher gross margin in 2015 was primarily attributable to increased Field Gathering and Processing throughput volumes primarily associated with the inclusion of TPL’s operations and the recognition of a renegotiated commercial contract, partially offset by lower export margins and treating and reservation fees in TRP’s Logistics and Marketing segments. Higher operating expenses are due to the inclusion of TPL’s operations ($69.4 million), which more than offset the cost savings generated throughout TRP’s other operating areas. See “Targa Resources Partners – Review of Segment Performance” for additional information regarding changes in gross margin and operating margin on a segment basis.

Higher general and administrative expenses were primarily due to the inclusion of TPL general and administrative costs ($21.4 million), which partially offset other general and administrative savings ($6.6 million), primarily from lower compensation and related costs.

The nine months results were impacted by the same factors for depreciation and amortization expenses, interest expense, net and net income attributable to noncontrolling interests, as discussed above for the three month comparison of 2015 to 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 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 the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; and the Williston Basin in North Dakota.

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

    Three Months Ended September 30,   Nine Months Ended September 30,
    2015    2014    2015    2014 
    ($ in millions, except operating statistics and price amounts)
Gross margin   $ 206.3     $ 145.6   $ 556.4   $ 428.7
Operating expenses     73.7       47.6     206.5     138.9
Operating margin   $ 132.6     $ 98.0   $ 349.9   $ 289.8
Operating statistics (1):                          
Plant natural gas inlet, MMcf/d (2),(3)                          
SAOU (4)     240.2       207.0     231.6     183.4
WestTX (5)     460.2           344.4    
Sand Hills     168.1       166.7     166.1     164.4
Versado     187.8       172.2     182.3     165.9
SouthTX (5)     139.1           112.9    
North Texas (6)     339.1       361.8     351.7     350.3
SouthOK (5)     473.8           378.2    
WestOK (5)     563.4           458.6    
Badlands (7)     50.7       44.9     46.6     39.2
      2,622.4       952.6     2,272.4     903.2
Gross NGL production, MBbl/d (3)                          
SAOU     28.6       25.9     27.2     25.1
WestTX (5)     53.6           40.1    
Sand Hills     17.5       17.6     17.6     18.1
Versado     24.0       22.0     23.5     20.8
SouthTX (5)     13.7           13.2    
North Texas     39.0       39.7     40.2     36.9
SouthOK (5)     30.3           23.4    
WestOK (5)     27.9           22.9    
Badlands     7.4       4.0     6.3     3.5
      242.0       109.2     214.4     104.4
Crude oil gathered, MBbl/d     108.9       99.2     105.4     86.0
Natural gas sales, BBtu/d (3)     1,518.6       478.7     1,308.7     453.4
NGL sales, MBbl/d     191.1       82.4     167.2     79.5
Condensate sales, MBbl/d     9.8       3.9     8.5     3.6
Average realized prices (8):                          
Natural gas, $/MMBtu      2.48         3.80      2.43       4.21 
NGL, $/gal      0.31         0.75      0.35       0.79 
Condensate, $/Bbl      39.96         85.08      43.31       88.17 

_______

(1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter, including the volumes related to plants acquired in the APL merger.

(2) Plant natural gas inlet represents TRP’s undivided interest in 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) Operations acquired as part of the APL merger effective February 27, 2015.

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

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

(8) Average realized prices exclude the impact of hedging activities presented in Other.

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

The increase in gross margin was primarily due to the inclusion of the TPL volumes along with other volume increases partially offset by significantly lower commodity sales prices.  The increases in plant inlet volumes were driven by system expansions and by increased producer activity which increased available supply across most of TRP’s areas of operation partially offset by reduced producer activity in North Texas. Higher natural gas and NGL sales reflect similar factors. Badlands crude oil and natural gas volumes increased significantly due to increased producer activity. The Little Missouri 3 plant which started commercial operations in January 2015 was a benefit to the gas volumes in the third quarter of 2015.

Despite cost reductions in most areas, higher operating expenses were primarily driven by the inclusion of TPL operating expenses and the commencement in operations of the Little Missouri 3 plant.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

The increase in gross margin was primarily due to the inclusion of the TPL volumes along with other volume increases partially offset by significantly lower commodity sales prices.  The other increases in plant inlet volumes were driven by system expansions and by increased producer activity which increased available supply across TRP’s areas of operation partially offset by reduced producer activity and volumes in North Texas.  The start-up of commercial operations in May 2014 at the Longhorn plant in North Texas, in June 2014 at the High Plains plant in SAOU and in January 2015 at the Little Missouri 3 plant in Badlands was a benefit to the nine month period of 2015. Badlands crude oil and natural gas volumes increased significantly due to producer activities and plant and system expansion.

Despite cost reductions in most areas, higher operating expenses were primarily driven by the inclusion of TPL operating expenses and increased expenses associated with the commencement in operations of the Longhorn, High Plains and Little Missouri 3 plants.

Gross Operating Statistics Compared to Actual Reported

The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field Gathering and Processing segment:

  Three Months Ended September 30, 2015
Operating statistics:                
Plant natural gas inlet, MMcf/d (1),(2)   Gross Volume (3)   Ownership %   Net Volume (3)   Actual Reported
SAOU   240.2     100.0 %   240.2   240.2
WestTX (4)(5)   632.1     72.8 %   460.2   460.2
Sand Hills   168.1     100.0 %   168.1   168.1
Versado (6)   187.8     63.0 %   118.3   187.8
SouthTX (4)   139.1     100.0 %   139.1   139.1
North Texas   339.1     100.0 %   339.1   339.1
SouthOK (4)   473.8   Varies (7)   397.1   473.8
WestOK (4)   563.4     100.0 %   563.4   563.4
Badlands (8)   50.7     100.0 %   50.7   50.7
Total   2,794.3       2,476.2   2,622.4
Gross NGL production, MBbl/d (2)                
SAOU   28.6     100.0 %   28.6   28.6
WestTX (4)(5)   73.6     72.8 %   53.6   53.6
Sand Hills   17.5     100.0 %   17.5   17.5
Versado   24.0     63.0 %   15.1   24.0
SouthTX (4)   13.7     100.0 %   13.7   13.7
North Texas   39.0     100.0 %   39.0   39.0
SouthOK (4)   30.3   Varies (7)   27.0   30.3
WestOK (4)   27.9     100.0 %   27.9   27.9
Badlands   7.4     100.0 %   7.4   7.4
Total   262.0       229.8   242.0

_______

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

(2) 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.

(3) For these 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.

(4) Operations acquired as part of the APL merger effective February 27, 2015.

(5) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in TRP’s reported financials.

(6) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in TRP’s reported financials.

(7) SouthOK includes the Centrahoma joint venture, of which TPL owns 60% and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in TRP’s reported financials.

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

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 September 30,   Nine Months Ended September 30,
    2015    2014    2015    2014 
    ($ in millions, except operating statistics and price amounts)
Gross margin   $ 17.7   $ 32.3   $ 52.6   $ 102.2
Operating expenses     9.8     13.2     30.5     35.2
Operating margin   $ 7.9   $ 19.1   $ 22.1   $ 67.0
Operating statistics (1):                        
Plant natural gas inlet, MMcf/d (2),(3)                        
LOU     177.0     293.1     173.8     308.4
VESCO     459.3     533.9     438.9     514.9
Other Coastal Straddles     193.8     390.9     278.2     384.7
      830.1     1,217.9     890.9     1,208.0
Gross NGL production, MBbl/d (3)                        
LOU     7.1     9.2     6.7     9.6
VESCO     27.8     27.3     25.7     26.3
Other Coastal Straddles     6.5     11.9     8.7     11.9
      41.4     48.4     41.1     47.8
Natural gas sales, BBtu/d (3)     227.6     252.7     231.4     266.5
NGL sales, MBbl/d     31.4     40.8     31.0     41.5
Condensate sales, MBbl/d     0.8     0.7     0.8     0.7
Average realized prices:                        
Natural gas, $/MMBtu     2.82     4.04     2.85     4.58
NGL, $/gal     0.38     0.80     0.40     0.86
Condensate, $/Bbl     49.13     102.88     51.72     100.04

__________

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

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

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

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

The decrease in Coastal Gathering and Processing gross margin was primarily due to lower NGL sales prices, a less favorable frac spread and lower throughput volumes. The decrease in plant inlet volumes was largely attributable to current market conditions and the decline of leaner off-system supply volumes.

Operating expenses decreased primarily due to reduced volumes and lower plant run-time due to current market conditions and reduced system and maintenance expenses at VESCO.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

The decrease in Coastal Gathering and Processing gross margin was primarily due to lower NGL sales prices, less favorable frac spread and lower throughput volumes, partially offset by new volumes at VESCO with higher GPM.  The overall decrease in plant inlet volumes was largely attributable to current market conditions and the decline of leaner off-system supply volumes.

Operating expenses decreased primarily due to reduced volumes and lower plant run-time due to current market conditions.

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 the LPG export market; and storing and terminaling refined petroleum products. These assets are generally connected to and supplied in part by TRP’s Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas and Lake Charles, Louisiana.

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

    Three Months Ended September 30,     Nine Months Ended September 30,
    2015    2014    2015    2014 
    ($ in millions, except operating statistics)
Gross margin (1)   $ 153.1   $ 164.4     $ 474.6   $ 449.1
Operating expenses (1)     49.5     45.8       132.9     125.1
Operating margin   $ 103.6   $ 118.6     $ 341.7   $ 324.0
Operating statistics, MBbl/d (2):                          
Fractionation volumes (3)     344.6     368.6       347.7     342.7
LSNG treating volumes     23.8     24.8       22.8     24.2
Benzene treating volumes     23.8     24.8       22.8     24.2

 _______
(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 sold during the year and the denominator is the number of calendar days during the year.
(3) Fractionation volumes reflect those volumes delivered and settled under fractionation contracts.

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

Logistics Assets gross margin decreased primarily due to lower LPG export and fractionation margin, partially offset by a recognition of a portion of the renegotiated commercial arrangements related to TRP’s condensate splitter project and increased terminaling and storage activities. The lower export margin was partially due to LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, which averaged 184.1 MBbl/d in the third quarter of 2015 compared to 205.9 MBbl/d for the same period last year. Fractionation gross margin was impacted by a decrease in supply volume and by the variable effects of fuel and power, which are largely reflected in lower operating expenses (see footnote (1) above). Terminaling and storage volumes increased due to higher customer throughput.

Higher operating expenses were due to less favorable system product gains and higher maintenance, partially offset by lower fuel and power expense and lower export-related costs.  

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

Logistics Assets gross margin increased primarily due to the recognition of the renegotiated commercial arrangements related to TRP’s condensate splitter project and increased terminaling and storage activities, partially offset by lower fractionation and LPG export gross margin. Terminaling and storage volumes increased due to higher customer throughput. Fractionation gross margin was impacted by the variable effects of fuel and power, which are largely reflected in lower operating expenses (see footnote (1) above) partially offset by an increase in supply volume. LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 180.0 MBbl/d in 2015 compared to 160.5 MBbl/d for 2014. 

Higher operating expenses were due to less favorable system product gains and higher maintenance, partially offset by lower fuel and power expense and lower export-related costs.  

Marketing and Distribution

The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes: (1) marketing the Partnership’s natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end-users; (4) providing propane, butane and services to LPG exporters; and (5) marketing natural gas available to the Partnership from its Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.

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

    Three Months Ended September 30,     Nine Months Ended September 30,
    2015    2014      2015    2014 
    ($ in millions, except operating statistics and price amounts)
Gross margin   $ 70.2   $ 73.8   $ 209.4   $ 217.2
Operating expenses     10.0     12.2     32.1     37.7
Operating margin   $ 60.2   $ 61.6   $ 177.3   $ 179.5
Operating statistics (1):                        
NGL sales, MBbl/d     401.1     444.3     426.1     405.5
Average realized prices:                        
NGL realized price, $/gal     0.41     0.95     0.47     1.00

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

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

Marketing and Distribution gross margin decreased primarily due to the lower LPG export volumes (which benefit both Logistics Assets and Marketing and Distribution segments), lower barge revenue and lower refinery LPG supply partially offset by higher marketing gains.

Operating expenses decreased primarily due to lower barge expense and truck expense. 

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

Marketing and Distribution gross margin decreased primarily due to a lower price environment and the expiration and recognition of a contract settlement in 2014, lower barge revenue and lower refinery LPG supply. LPG export volumes (which benefit both Logistics Assets and Marketing and Distribution segments) were higher. 

Operating expenses decreased primarily due to lower barge maintenance and lower railcar expense and truck expense.

Other

    Three Months Ended September 30,   Nine Months Ended September 30,
    2015    2014    2015    2014 
                         
    (In millions)
Gross margin   $ 21.8   $   (2.3 )   $ 60.7   $   (12.4 )
Operating margin   $ 21.8   $   (2.3 )   $ 60.7   $   (12.4 )

Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash-flow hedges. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column. The primary purpose of the Partnership’s commodity risk management activities is to mitigate a portion of the impact of commodity prices on its operating cash flow. 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 percent of proceeds or liquid processing arrangements by entering into derivative instruments. Because the Partnership is essentially forward-selling a portion of its plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

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

  Three Months Ended September 30, 2015   Three Months Ended September 30, 2014    
  (In millions, except volumetric data and price amounts)    
   Volume
Settled
  Price
Spread
(1)(2)
  Gain
(Loss)
   Volume
Settled
  Price
Spread
(1)(2)
  Gain (Loss)   2015 vs.
2014
Natural Gas (BBtu) 16.2 $ 0.48 $   7.7     6.1 $   (0.02 ) $   (0.1 ) $   7.8  
NGL (MMBbl) 0.6   14.72     8.5     7.3     0.07       0.5       8.0  
Crude Oil (MMBbl) 0.2   33.50     6.7     0.2     (5.36 )     (1.1 )     7.8  
Non-Hedge Accounting (3)           (1.7 )             (1.6 )     (0.1 )
Ineffectiveness (4)           0.6                     0.6  
        $   21.8           $   (2.3 ) $   24.1  
                           
  Nine Months Ended September 30, 2015   Nine Months Ended September 30, 2014    
  (In millions, except volumetric data and price amounts)    
   Volume
Settled
  Price
Spread
(1)(2)
  Gain
(Loss)
   Volume
Settled
  Price
Spread
(1)(2)
  Gain (Loss)   2015 vs.
2014
Natural Gas (BBtu) 35.0 $ 0.65 $   22.6     15.9 $   (0.44 ) $   (6.9 ) $   29.5  
NGL (MMBbl) 62.4   0.29     18.1     15.9     0.04       0.7       17.4  
Crude Oil (MMBbl) 0.7   19.71     13.8     0.7     (7.74 )     (5.3 )     19.1  
Non-Hedge Accounting (3)           4.9               (1.0 )     5.9  
Ineffectiveness (4)           1.3               0.1       1.2  
        $   60.7           $   (12.4 ) $   73.1  

______________

(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 Oil volumes is $/Bbl.

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

(4) Ineffectiveness primarily relates to certain crude hedging contracts and certain acquired hedges of APL that do not qualify for hedge accounting.

As part of the Atlas mergers, outstanding APL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to the Partnership and included in the acquisition date fair value of assets acquired. Derivative settlements of $20.7 million and $52.2 million related to these novated contracts were received during the three and nine months ended September 30, 2015 and were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired, with no effect on results of operations.

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 IDRs and a portion of the outstanding limited partner interests in Targa Resources Partners LP.

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

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

Targa Resources Partners – Non-GAAP Financial Measures

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

Distributable Cash Flow – The Partnership defines distributable cash flow  as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash risk management activities related to derivative instruments, including the cash impact of hedges acquired in the APL merger; debt repurchases, redemptions, amendments, exchanges and early debt extinguishments; non-cash compensation on TRP equity grants; transaction costs related to business acquisitions; earnings/losses from unconsolidated affiliates net of distributions and asset disposals and less maintenance capital expenditures (net of any reimbursements of project costs). 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 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 September 30,   Nine Months Ended September 30,
      2015    2014    2015    2014 
        (In millions)   (In millions)
Reconciliation of net income to Distributable Cash flow:                        
Net income attributable to Targa Resources Partners LP   $   48.5     $   128.3     $   167.1     $   359.6  
Depreciation and amortization expenses       165.8         87.5         448.3         252.8  
Deferred income tax expense (benefit)       (0.6 )       0.4         (0.3 )       1.1  
Non-cash interest expense, net (1)       3.3         2.2         9.3         8.8  
Loss from financing activities       0.5                 0.5          
(Earnings) loss from unconsolidated affiliates (2)       1.6         (4.7 )       1.1         (13.8 )
Distributions from unconsolidated affiliates (2)       4.2         4.7         11.2         13.8  
Compensation on TRP equity grants (2)       3.9         2.1         12.8         7.0  
Gain on sale or disposition of assets               (4.4 )       (0.2 )       (5.6 )
Risk management activities       21.8         1.5         46.0         0.9  
Maintenance capital expenditures       (26.7 )       (21.9 )       (73.0 )       (55.6 )
Transactions costs related to business acquisitions (2)       0.6                 14.9          
Other (3)       (2.2 )       (1.1 )       (6.9 )       (5.0 )
Targa Resources Partners LP distributable cash flow   $   220.7     $   194.6     $   630.8     $   564.0  

 _______

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

(2) The definition of Adjusted EBITDA was changed in 2014 to exclude non-cash compensation on equity grants and in 2015 to exclude earnings from unconsolidated investments net of distributions and transaction costs related to business acquisitions.

(3) Includes the noncontrolling interests portion of maintenance capital expenditures, 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, redemptions, amendments, exchanges and early debt extinguishments and asset disposals; risk management activities related to derivative instruments, including the cash impact of hedges acquired in the APL merger; non-cash compensation on TRP equity grants; transaction costs related to business acquisitions; earnings/losses from unconsolidated affiliates net of distributions and the noncontrolling 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. 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 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. 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 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 income of the Partnership to Adjusted EBITDA for the periods indicated:

      Three Months Ended September 30,   Nine Months Ended September 30,
      2015    2014    2015    2014 
                           
      (In millions)            
Reconciliation of Net Income to Adjusted EBITDA:                        
Net income attributable to Targa Resources Partners LP   $   48.5     $   128.3     $   167.1     $   359.6  
  Interest expense, net       64.1         36.0         177.2         104.1  
  Income tax expense (benefit)       (0.4 )       1.3         0.4         3.7  
  Depreciation and amortization expenses       165.8         87.5         448.3         252.8  
  Gain on sale or disposition of assets               (4.4 )       (0.2 )       (5.6 )
  Loss from financing activities       0.5                 0.5          
  (Earnings) loss from unconsolidated affiliates (1)       1.6         (4.7 )       1.1         (13.8 )
  Distributions from unconsolidated affiliates (1)       4.2         4.7         11.2         13.8  
  Compensation on TRP equity grants (1)       3.9         2.1         12.8         7.0  
  Transaction costs related to business acquisitions (1)     0.6                 14.9          
  Risk management activities       21.8         1.5         46.0         0.9  
  Other                       0.6          
  Noncontrolling interests adjustment (2)       (4.8 )       (3.5 )       (13.4 )       (10.4 )
Targa Resources Partners LP Adjusted EBITDA   $   305.8     $   248.8     $   866.5     $   712.1  

_________
(1) The definition of Adjusted EBITDA was changed in 2014 to exclude non-cash compensation on equity grants and in 2015 to exclude earnings from unconsolidated investments net of distributions and transaction costs related to business acquisitions.
(2) Noncontrolling interest portion of depreciation and amortization expenses.

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

      Three Months Ended September 30,   Nine Months Ended September 30,
      2015    2014    2015    2014 
                           
      (In millions)            
Reconciliation of net cash provided by Targa Resources                      
  Partners LP operating activities to Adjusted EBITDA:                        
Net cash provided by operating activities   $   215.5     $   114.9     $   737.8     $   571.8  
Net income attributable to noncontrolling interests       (4.8 )       (9.9 )       (17.3 )       (30.9 )
Interest expense       64.1         36.0         177.2         104.1  
Non-cash interest expense, net (1)       (3.3 )       (2.2 )       (9.3 )       (8.8 )
(Earnings) loss from unconsolidated affiliates (2)       1.6         (4.7 )       1.1         (13.8 )
Distributions from unconsolidated affiliates (2)       4.2         4.7         11.2         13.8  
Transaction costs related to business acquisitions (2)       0.6                 14.9          
Current income tax expense       0.2         0.9         0.7         2.6  
Other (3)       (10.8 )       (4.6 )       (35.1 )       (13.7 )
Changes in operating assets and liabilities which used (provided) cash:                        
  Accounts receivable and other assets       46.7         114.8         (157.9 )       155.9  
  Accounts payable and other liabilities       (8.2 )       (1.1 )       143.2         (68.9 )
Targa Resources Partners LP Adjusted EBITDA   $   305.8     $   248.8     $   866.5     $   712.1  

________
(1) Includes amortization of debt issuance costs, discount and premium.
(2) The definition of Adjusted EBITDA was changed in 2014 to exclude non-cash compensation on equity grants and in 2015 to exclude earnings from unconsolidated investments net of distributions and transaction costs related to business acquisitions.
(3) Includes accretion expense associated with asset retirement obligations, noncontrolling interest portion of depreciation and amortization expenses and loss on financing activities.

Gross MarginThe Partnership defines gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as by 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 – The Partnership defines operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of the Partnership’s operations.

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 a substitute 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 measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

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

      Three Months Ended September 30,   Nine Months Ended September 30,
      2015    2014      2015    2014 
      (In millions)
Reconciliation of Targa Resources Partners LP gross          
  margin and operating margin to net income:                        
Gross margin   $   459.7     $   407.8       $   1,333.5     $   1,171.5  
  Operating expenses       (133.6 )       (112.8 )         (381.8 )       (323.6 )
Operating margin       326.1         295.0           951.7         847.9  
  Depreciation and amortization expenses       (165.8 )       (87.5 )         (448.3 )       (252.8 )
  General and administrative expenses       (42.9 )       (40.4 )         (130.1 )       (115.3 )
  Interest expense, net       (64.1 )       (36.0 )         (177.2 )       (104.1 )
  Income tax (expense) benefit       0.4         (1.3 )         (0.4 )       (3.7 )
  Gain on sale or disposition of assets               4.4           0.2         5.6  
  (Loss) from financing activities       (0.5 )                 (0.5 )        
  Other, net       0.1         4.0           (11.0 )       12.9  
Net income   $   53.3     $   138.2       $   184.4     $   390.5  

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 carrying costs associated with its debt and taxes attributable to the Company’s earnings. It excludes transaction costs related to acquisitions, losses on debt redemptions and amendments and non-cash interest expense. 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. Distributable cash flow should not be considered as an alternative to GAAP net income. 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 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 September 30,     Nine Months Ended September 30,
        2015    2014        2015          2014   
        (In millions)
Reconciliation of Net Income attributable to              
    Targa Resources Corp. to Distributable Cash Flow                        
Net income of Targa Resources Corp.   $   20.8     $   120.4     $   80.6     $   330.7  
    Less: Net income of Targa Resources Partners LP       (53.3 )       (138.2 )       (184.4 )       (390.5 )
Net loss for TRC Non-Partnership       (32.5 )       (17.8 )       (103.8 )       (59.8 )
    TRC Non-Partnership income tax expense       24.4         14.2         53.7         49.9  
    Distributions from the Partnership       61.4         48.9         181.8         139.2  
    Loss on financing activities                       12.9          
    Non-cash interest expense (1)       0.8                 1.9          
    Depreciation – Non-Partnership assets               0.1                 0.3  
    Transaction costs related to business acquisitions (1)       (0.1 )               12.4          
    Current cash tax expense (2)       (2.8 )       (17.3 )       (6.5 )       (51.4 )
    Taxes funded with cash on hand (3)       2.5         2.9         6.5         8.8  
Distributable cash flow   $   53.7     $   31.0     $   158.9     $   87.0  
________
  (1 )   The definition of Distributable cash flow was revised in 2015 to adjust for transaction costs related to business acquisitions and non-cash interest expense.
  (2 )   Excludes $1.2 million and $3.6 million of non-cash current tax expense arising from amortization of deferred long-term tax assets from drop down gains realized for tax purposes and paid in 2010 for the three and nine months ended September 30, 2015 and 2014, and includes $(3.4) million and $1.4 million adjustments to account for differences between taxes used to derive cash available for distribution and book taxes for the three and nine months ended September 30, 2015.
  (3 )   Current period portion of amount established at TRC’s IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes.
                             
        Three Months Ended September 30,     Nine Months Ended September 30,
        2015    2014      2015      2014   
          (In millions)
Targa Resources Corp. Distributable Cash Flow              
Distributions declared by Targa Resources Partners LP associated with:            
    General Partner Interests   $   4.0     $   2.6     $   11.9     $   7.5  
    Incentive Distribution Rights       43.9         36.0         129.5         101.4  
    Common Units held by TRC       13.5         10.3         40.4         30.3  
Total distributions declared by Targa Resources Partners LP       61.4         48.9         181.8         139.2  
  Income (expenses) of TRC Non-Partnership                        
    General and administrative expenses       (2.0 )       (2.6 )       (6.4 )       (7.1 )
    Interest expense, net (1)       (5.5 )       (0.9 )       (16.5 )       (2.4 )
    Current cash tax expense (2)       (2.8 )       (17.3 )       (6.5 )       (51.4 )
    Taxes funded with cash on hand (3)       2.5         2.9         6.5         8.8  
    Other income (expense)       0.1                         (0.1 )
Distributable cash flow   $   53.7     $   31.0     $   158.9     $   87.0  

(1) Excludes non-cash interest expense.

(2) Excludes $1.2 million and $3.6 million of non-cash current tax expense arising from amortization of deferred long-term tax assets from drop down gains realized for tax purposes and paid in 2010 for the three and nine months ended September 30, 2015 and 2014, and includes $(3.4) million and $1.4 million adjustments to account for differences between taxes used to derive cash available for distributions and book taxes for the three and nine months ended September 30, 2015.

(3) Current period portion of amount established at TRC’s IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes.

Forward-Looking Statements

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

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED BALANCE SHEETS
(In millions)
               
      September 30, 2015     December 31, 2014
ASSETS          
Current assets:          
  Cash and cash equivalents $ 92.8   $ 72.3
  Trade receivables   620.5     566.8
  Inventories   151.1     168.9
  Assets from risk management activities   92.3     44.4
  Other current assets   8.7     3.8
    Total current assets   965.4     856.2
Property, plant and equipment, net   9,750.2     4,824.6
Intangible assets, net   1,695.7     591.9
Long-term assets from risk management activities   45.4     15.8
Goodwill   551.4    
Other long-term assets   315.1     88.7
    Total assets $ 13,323.2   $ 6,377.2
LIABILITIES AND PARTNERS’ CAPITAL          
Current liabilities:          
  Accounts payable and accrued liabilities $ 690.0   $ 645.9
  Liabilities from risk management activities   4.3     5.2
  Account receivable securitization facility   135.5     182.8
    Total current liabilities   829.8     833.9
Long-term debt   5,336.4     2,783.4
Long-term liabilities from risk management activities   4.0    
Other long-term liabilities   95.8     71.5
Owners’ equity:          
  Targa Resources Partners LP owner’s equity   6,747.6     2,517.2
  Noncontrolling interests in subsidiaries   309.6     171.2
    Total owners’ equity   7,057.2     2,688.4
    Total liabilities and owners’ equity $ 13,323.2   $ 6,377.2

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit amounts)
    Three Months Ended     Nine Months Ended
    September 30,     September 30,
    2015    2014    2015    2014 
REVENUES                      
  Sale of commodities $   1,321.3     $   2,009.2     $   4,119.6     $   5,853.3  
  Fees from midstream services     310.8         279.1         891.6         730.4  
  Total Revenues     1,632.1         2,288.3         5,011.2         6,583.7  
COSTS AND EXPENSES                      
  Product purchases     1,172.4         1,880.5         3,677.7         5,412.2  
  Operating expenses     133.6         112.8         381.8         323.6  
  Depreciation and amortization expenses     165.8         87.5         448.3         252.8  
  General and administrative expenses     42.9         40.4         130.1         115.3  
  Other operating (income) expenses     0.1         (4.3 )       0.6         (5.3 )
    Total costs and expenses     1,514.8         2,116.9         4,638.5         6,098.6  
INCOME FROM OPERATIONS     117.3         171.4         372.7         485.1  
Other income (expense):                      
  Interest expense, net     (64.1 )       (36.0 )       (177.2 )       (104.1 )
  Equity earnings (loss)     (1.6 )       4.7         (1.1 )       13.8  
  Loss from financing activities     (0.5 )               (0.5 )        
  Other     1.8         (0.6 )       (9.1 )       (0.6 )
Income before income taxes     52.9         139.5         184.8         394.2  
Income tax (expense) benefit     0.4         (1.3 )       (0.4 )       (3.7 )
NET INCOME     53.3         138.2         184.4         390.5  
Less: Net income attributable to noncontrolling interests     4.8         9.9         17.3         30.9  
NET INCOME ATTRIBUTABLE TO TARGA
  RESOURCES PARTNERS LP
$   48.5     $   128.3     $   167.1     $   359.6  
                         
Net income attributable to general partner $   44.9     $   38.6     $   132.0         108.2  
Net income attributable to limited partners     3.6         89.7         35.1         251.4  
Net income attributable to Targa Resources Partners LP $   48.5     $   128.3     $   167.1     $   359.6  
                         
Net income per limited partner unit – basic $   0.02     $   0.78     $   0.21     $   2.21  
Net income per limited partner unit – diluted $   0.02     $   0.78     $   0.21     $   2.20  
                         
Weighted average limited partner units outstanding – basic     184.8         115.1         168.1         113.9  
Weighted average limited partner units outstanding – diluted     185.1         115.7         168.5         114.5  

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED CASH FLOW INFORMATION
(In millions)
        Nine Months Ended September 30,
        2015    2014 
CASH FLOWS FROM OPERATING ACTIVITIES          
Net income $   184.4     $   390.5  
Adjustments to reconcile net income to net cash          
  provided by operating activities:          
    Amortization in interest expense     9.3         8.8  
    Compensation on equity grants     12.8         7.0  
    Depreciation and amortization expense     448.3         252.8  
    Accretion of asset retirement obligations     3.9         3.3  
    Deferred income tax expense (benefit)     (0.3 )       1.1  
    Equity earnings of unconsolidated affiliates     1.1         (13.8 )
    Distributions received from unconsolidated affiliates     10.1         13.8  
    Risk management activities     53.2         0.9  
    (Gain) loss on sale or disposal of assets     (0.2 )       (5.6 )
    Loss from financing activities     0.5          
    Changes in operating assets and liabilities     14.7         (87.0 )
    Net cash provided by operating activities     737.8         571.8  
CASH FLOWS FROM INVESTING ACTIVITIES          
  Outlays for property, plant and equipment     (625.3 )       (571.7 )
  Business acquisition, net of cash acquired     (828.7 )        
  Investment in unconsolidated affiliates     (6.6 )        
  Return of capital from unconsolidated affiliates     1.1         4.2  
  Other, net     (3.0 )       6.3  
    Net cash used in investing activities     (1,462.5 )       (561.2 )
CASH FLOWS FROM FINANCING ACTIVITIES          
  Proceeds from borrowings under credit facility     1,646.0         1,295.0  
  Repayments of credit facility     (1,211.0 )       (1,115.0 )
  Borrowings from accounts receivable securitization facility     275.5         88.9  
  Repayments of accounts receivable securitization facility     (322.8 )       (131.0 )
  Proceeds from issuance of senior notes     1,700.0          
  Redemption of APL senior notes     (1,168.8 )        
  Costs in connection with financing arrangements     (20.7 )       (2.7 )
  Proceeds from sale of common units     318.6         259.9  
  Repurchase of common units under compensation plans     (5.2 )       (4.8 )
  Contributions received from General Partner     60.1         5.2  
  Contributions received from noncontrolling interests     16.4          
  Distributions paid to unitholders     (531.7 )       (362.8 )
  Payment of distribution equivalent rights     (2.5 )       (1.6 )
  Distributions to noncontrolling interests     (8.7 )       (26.8 )
    Net cash provided by (used in) financing activities     745.2         4.3  
Net change in cash and cash equivalents     20.5         14.9  
Cash and cash equivalents, beginning of period     72.3         57.5  
Cash and cash equivalents, end of period $   92.8     $   72.4  

  TARGA RESOURCES CORP.
  FINANCIAL SUMMARY (unaudited)
  CONSOLIDATED STATEMENTS OF OPERATIONS            
  (In millions, except per share amounts)                  
      Three Months Ended September 30,   Nine Months Ended September 30,
      2015    2014    2015    2014 
  REVENUES                      
    Sales of commodities $   1,321.3     $   2,009.2     $   4,119.6     $   5,853.3  
    Fees from midstream services     310.8         279.1         891.6         730.4  
    Total revenues     1,632.1         2,288.3         5,011.2         6,583.7  
  COSTS AND EXPENSES                      
    Product purchases     1,172.4         1,880.5         3,677.7         5,412.2  
    Operating expenses     133.6         112.8         381.9         323.7  
    Depreciation and amortization expenses     165.8         87.6         448.3         253.1  
    General and administrative expenses     44.9         43.0         136.5         122.4  
    Other operating income     0.1         (4.3 )       0.6         (5.3 )
    Total costs and expenses     1,516.8         2,119.6         4,645.0         6,106.1  
  INCOME FROM OPERATIONS     115.3         168.7         366.2         477.6  
  Other income (expense):                      
    Interest expense, net     (70.4 )       (36.9 )       (195.6 )       (106.5 )
    Equity earnings     (1.6 )       4.7         (1.1 )       13.8  
    Loss on financing activities     (0.5 )               (13.4 )        
    Other     2.0         (0.6 )       (21.4 )       (0.6 )
  Income before income taxes     44.8         135.9         134.7         384.3  
  Income tax (expense) benefit     (24.0 )       (15.5 )       (54.1 )       (53.6 )
  NET INCOME     20.8         120.4         80.6         330.7  
  Less: Net income attributable to noncontrolling interests     8.1         89.7         49.2         253.9  
  NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $   12.7     $   30.7     $   31.4     $   76.8  
                           
  Net income available per common share – basic $   0.23     $   0.73     $   0.60     $   1.83  
  Net income available per common share – diluted $   0.23     $   0.73     $   0.60     $   1.82  
                           
  Weighted average shares outstanding – basic     56.0         42.0         52.6         42.0  
  Weighted average shares outstanding – diluted     56.1         42.1         52.7         42.1  

TARGA RESOURCES CORP.  
FINANCIAL SUMMARY (unaudited)    
KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS
(In millions)          
             
          September 30, 2015
Cash and cash equivalents:    
  TRC Non-Partnership $ 10.1
  Targa Resources Partners   92.8
    Total cash and cash equivalents $ 102.9
Total funded debt:    
Current    
  Targa Resources Partners $ 135.5
Long term    
  TRC Non-Partnership   602.4
  Targa Resources Partners   5,336.4
    Total long-term debt   5,938.8
      Total funded debt: $ 6,074.3

 

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

Jennifer Kneale
Senior Director – Finance

Matthew Meloy 
Executive Vice President, Chief Financial Officer and Treasurer