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Targa Resources Partners LP and Targa Resources Corp. Report Fourth Quarter and Full Year 2015 Financial Results

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HOUSTON, Feb. 25, 2016 (GLOBE NEWSWIRE) -- Targa Resources Partners LP (NYSE:NGLS PRA) ("Targa Resources Partners", the "Partnership" or "TRP") and Targa Resources Corp. (NYSE: TRGP) ("TRC", the "Company" or "Targa") today reported fourth quarter and full year 2015 results.

Targa Resources Partners – Fourth Quarter and Full Year 2015 Financial Results

Fourth quarter 2015 net income attributable to Targa Resources Partners before impairment of goodwill was $50.7 million compared to $108.2 million for the fourth quarter of 2014. The net income results for the fourth quarter and full year 2015 excludes a non-cash provisional loss of $290 million associated with impairment of goodwill in the Field Gathering and Processing segment. The Partnership reported earnings before interest, income taxes, depreciation and amortization, impairment of goodwill and other non-cash items ("Adjusted EBITDA") of $324.7 million for the fourth quarter of 2015 compared to $258.3 million for the fourth quarter of 2014. The Partnership paid $200.4 million in common equity, general partner, and incentive distribution right distributions and $2.4 million of preferred distributions with respect to the fourth quarter of 2015, which resulted in approximately 1.2 times equity distribution coverage. Distributable cash flow was $237.0 million (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 2015, net income attributable to Targa Resources Partners before impairment of goodwill was $217.8 million compared to $467.7 million for 2014.  The Partnership reported Adjusted EBITDA of $1,191.2 million for the full year 2015 compared to $970.3 million for the full year 2014.

"Targa's solid 2015 performance in the current industry environment highlights the strengths of our diverse businesses and of our exceptional work force," said Joe Bob Perkins, Chief Executive Officer of the Company. "With the buy-in now closed and with our recently announced preferred equity transaction, we are well positioned to be patient and potentially opportunistic as we move through the energy cycle in 2016."

On January 19, 2016, the Partnership announced a cash distribution on common units for the fourth 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 2% growth over the distribution for the fourth quarter 2014. The cash distribution was paid on February 9, 2016 on all outstanding common units to holders of record as of the close of business on February 2, 2016. The total distribution paid was $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.

The Partnership pays monthly preferred distributions of $0.1875 per Series A Preferred Unit. The initial distribution rate for the partial month of October 2015 that the series was outstanding was $0.10 per unit. The Partnership paid $2.4 million of preferred distributions with respect to the fourth quarter of 2015.

Targa Resources Corp. – Fourth Quarter and Full Year 2015 Financial Results

TRC reported net income available to common shareholders before impairment of goodwill of $52.5 million for the fourth quarter 2015 compared to $25.6 million for the fourth quarter 2014.  For the full year 2015, net income attributable to common shareholders before impairment of goodwill was $83.9 million compared to $102.3 million for 2014.

The Company, which as of December 31, 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.

Fourth quarter 2015 distributions paid on February 9, 2016 by the Partnership to the Company were $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 January 19, 2016, TRC declared a quarterly dividend of $0.9100 per share of its common stock for the three months ended December 31, 2015, or $3.64 per share on an annualized basis, flat over the previous quarter's dividend and an increase of 24% over the dividend for the fourth quarter of 2014. Total cash dividends of approximately $51.0 million were paid February 9, 2016 on all outstanding common shares to holders of record as of the close of business on February 2, 2016.

The Company's distributable cash flow for the fourth quarter 2015 was $54.9 million compared to $51.7 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 Fourth Quarter 2015 - Capitalization, Liquidity and Financing

Total funded debt of the Partnership as of December 31, 2015 was $5,383.3 million including $280.0 million outstanding under the Partnership's $1.6 billion senior secured revolving credit facility, $219.3 million outstanding under the Partnership's accounts receivable securitization facility, and $4,884.0 million of senior unsecured notes, net of unamortized discounts.

As of December 31, 2015, after giving effect to $12.9 million in outstanding letters of credit, the Partnership had available revolver capacity of $1,307.1 million.

Targa Resources Corp. Fourth Quarter 2015 - Capitalization, Liquidity and Financing

Total funded debt of the Company as of December 31, 2015, excluding debt of the Partnership, was $597.5 million including $440.0 million outstanding under the Company's $670.0 million senior secured revolving credit facility due 2020 and $157.5 million, net of unamortized discounts, outstanding on the Company's senior secured term loan due 2022. This resulted in $230.0 million in available revolver capacity as of December 31, 2015.

TRC/TRP Merger

On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the "TRC/TRP Merger Agreement"), by and among TRP, Targa Resources GP LLC (its "general partner"), TRC and Spartan Merger Sub LLC, a subsidiary of TRC ("Merger Sub") pursuant to which TRC acquired indirectly all of TRP's outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP (the "TRC/TRP Merger"), with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of TRP's outstanding common units.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share ("TRC shares"). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders instead received cash in lieu of fractional TRC shares.

Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause TRP's common units to be delisted from the New York Stock Exchange ("NYSE") and deregistered under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). As a result of the completion of the TRC/TRP Merger, TRP's common units are no longer publicly traded. The Series A Preferred Units of TRP remain outstanding as limited partner interests in TRP and continue to trade on the NYSE under the symbol "NGLS PRA."

TRC Private Placement of 9.5% Series A Preferred Stock

On February 18, 2016, TRC announced that it had entered into an agreement with an affiliate of Stonepeak Infrastructure Partners ("Stonepeak") for the issuance and sale of $500 million of 9.5% Series A Preferred Stock (the "Preferred Stock"). The Preferred Stock can be redeemed in whole or in part at the Company's option after five years, and is also convertible into TRC common stock beginning in 2028 by Stonepeak or under certain conditions by TRC. In connection with the issuance of the Preferred Stock, TRC also agreed to issue to Stonepeak 7,020,000 warrants with a strike price of $18.88 per common share and 3,385,000 warrants with a strike price of $25.11 per common share. The warrants have a seven year term. The Company expects to use the net proceeds from the sale of the Preferred Stock, which is expected to close in March 2016, to repay indebtedness and for general corporate purposes.

Conference Call

Targa will host a conference call for investors and analysts at 10:30 a.m. Eastern time (9:30 a.m. Central time) on February 25, 2016 to discuss fourth quarter and full year 2015 financial results. The conference call can be accessed via webcast through the Events and Presentations section of Targa's website at www.targaresources.com, by going directly to http://ir.targaresources.com/trc/events.cfm or by dialing 877-881-2598.  The pass code for the dial-in is 48931557. 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 Company's website. An updated investor presentation will also be available in the Events and Presentations section of the Company's websites following the completion of the conference call.

 
Targa Resources Partners – Consolidated Financial Results of Operations
 
   Three Months Ended December 31,   Year Ended December 31,
    2015     2014      2015     2014  
              
Revenues:($ in millions, except operating statistics and price amounts)
Sales of commodities $ 1,345.7  $ 1,742.0   $ 5,465.4  $ 7,595.2 
Fees from midstream services   300.2    290.9     1,193.2    1,021.3 
Total revenues   1,647.3    2,032.9     6,658.6    8,616.5 
Product purchases   1,195.3    1,634.7     4,873.0    7,046.9 
Gross margin (1)   452.0    398.2     1,785.6    1,569.6 
Operating expenses   122.8    109.4     504.6    433.0 
Operating margin (2)   329.2    288.8     1,281.0    1,136.6 
Depreciation and amortization expenses   228.8    93.7     677.1    346.5 
General and administrative expenses   23.5    24.6     153.6    139.8 
Goodwill impairment   290.0    -     290.0    - 
Other operating (income) expenses   (7.8)   2.1     (7.1)   (3.0)
Income from operations   (205.3)   168.4     167.4    653.3 
Interest expense, net   (30.6)   (39.7)    (207.8)   (143.8)
Equity earnings   (1.4)   4.3     (2.5)   18.0 
Gain (loss) from financing activities   3.4    (12.4)    2.8    (12.4)
Other income (expense)   (5.2)   (4.8)    (14.2)   (5.2)
Income tax (expense) benefit   (0.2)   (1.1)    (0.6)   (4.8)
Net income   (239.3)   114.7     (54.9)   505.1 
Less: Net income attributable to noncontrolling interests   (49.2)   6.5     (31.9)   37.4 
Net income attributable to limited partners and the general partners $ (190.1) $ 108.2   $ (23.0) $ 467.7 
Financial and operating data:             
Financial data:             
Adjusted EBITDA (3) $ 324.7  $ 258.3   $ 1,191.2  $ 970.3 
Distributable cash flow (4)   237.0    199.3     867.8    763.2 
Capital expenditures   206.1    214.0     777.2    747.8 
Operating statistics:             
Crude oil gathered, MBbl/d   108.8    115.9     106.3    93.5 
Plant natural gas inlet, MMcf/d (5)(6)(7)   3,472.1    2,104.5     3,241.3    2,109.5 
Gross NGL production, MBbl/d (7)   294.7    155.6     265.5    153.0 
Export volumes, MBbl/d (8)   192.0    225.5     183.0    176.9 
Natural gas sales, BBtu/d (6)(7)   1,917.2    937.5     1,770.7    902.3 
NGL sales, MBbl/d (7)   563.0    472.4     517.0    419.5 
Condensate sales, MBbl/d (7)   9.0    4.3     9.3    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, impairment of goodwill, 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, distributions from preferred interests  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, impairment of goodwill, deferred taxes and amortization of debt issuance 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, financing activities, non-cash compensation on Partnership equity grants, transaction costs related to acquisitions, earnings/losses from unconsolidated affiliates net of distributions and asset disposals, change in redemptive value of mandatorily redeemable preferred interests 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 Results

Three Months Ended December 31, 2015 Compared to Three Months Ended December 31, 2014

Revenues from commodity sales declined as the effect of significantly lower commodity prices ($1,346.5 million) exceeded the favorable impacts of inclusion of a full quarter of operations of TPL ($332.8 million), other volume increases ($624.1 million), and favorable hedge settlements ($23.5 million). Fee-based and other revenues increased due to the inclusion of TPL's fee revenue ($53.0 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 ($729.9 million), which were partially offset by the inclusion of product purchases related to TPL's operations ($290.5 million).

The higher gross margin in 2015 was attributable to inclusion of TPL operations and increased throughput related to other system expansions in our Field Gathering and Processing segment, partially offset by lower LPG export and fractionation margin and the expiration and recognition of a contract settlement in 2014 in our Logistics and Marketing segments. Higher operating expenses are due to the inclusion of TPL's operations ($32.2 million), which more than offset the cost savings generated throughout our 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 2014, including the international export expansion project, continuing development at Badlands and other system expansions. During 2015, we recorded an additional $32.6 million charge to depreciation to reflect an impairment of certain gas processing facilities and associated gathering systems in the Coastal Gathering and Processing segment as a result of reduced forecasted processing volumes due to current market conditions and processing spreads in Louisiana.

Lower general and administrative expenses are primarily due to lower compensation and related costs ($11.8 million), which was partially offset by the inclusion of TPL general and administrative costs ($10.9 million).

The increase in other operating gains during 2015 was primarily related to higher gains on sales of assets.

During 2015, we recognized a provisional loss of $290.0 million associated with the impairment of goodwill in our Field and Gathering segment.

The increase in net interest expense primarily reflects higher borrowings attributable to the APL mergers and lower capitalized interest associated with major capital projects compared to 2014. These factors were partially offset by the change in the redemption value ($30.6 million) of the mandatorily redeemable preferred interests in the Partnership's WestTX and WestOK joint ventures acquired in the Atlas mergers.

During 2015, the gain on financing activities was due primarily to the Partnership's $3.6 million gain on repurchase of debt. In 2014, the loss on financing activities was due to the Partnership's redemption of its 7⅞% senior notes.

Net income attributable to noncontrolling interests decreased due to lower earnings in 2015 that impacted the Partnership and its joint ventures at Cedar Bayou Fractionators, VESCO and Versado. The inclusion of non-controlling interest from TPL's Centrahoma joint venture increased the net income attributable to non-controlling interests.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Revenues from commodity sales declined as the effect of significantly lower commodity prices ($6,318.1 million) exceeded the favorable impacts of inclusion of ten months of operations of TPL ($1,260.5 million), other volume increases ($2,934.0 million), and favorable hedge settlements ($84.2 million). Fee-based and other revenues increased due to the inclusion of TPL's fee revenue ($179.7 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 ($3,280.0 million). 2015 also included product purchases related to TPL's operations ($1,106.1 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 ($101.6 million), which more than offset the cost savings generated throughout TRP's other operating areas ($31.0 million). 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 2014, including the international export expansion project, continuing development at Badlands and other system expansions. During 2015, we recorded an additional $32.6 million charge to depreciation to reflect an impairment of certain gas processing facilities and associated gathering systems in the Coastal Gathering and Processing segment as a result of reduced forecasted processing volumes due to current market conditions and processing spreads in Louisiana.

Higher general and administrative expenses is due to the inclusion of TPL general and administrative costs ($32.1 million), which was partially offset by other general and administrative reductions ($18.1 million), primarily from lower compensation and related costs.

The increase in other operating gains during 2015 was primarily related to higher gains on sales of assets.

During 2015, we recognized a provisional loss of $290.0 million associated with the impairment of goodwill in our Field and Gathering segment.

The increase in net interest expense primarily reflects higher borrowings attributable to the APL merger and lower capitalized interest associated with major capital projects compared to 2014. These factors were partially offset by the change in the estimated redemption value ($30.6 million) of the mandatorily redeemable preferred interests in the WestTX and WestOK joint ventures acquired in the Atlas mergers.

During 2015, the gain on financing activities was due primarily to $3.6 million in gains on repurchase of debt offset by a $0.7 million loss the APL notes exchange offer. In 2014, the loss on financing activities was due to the redemption of the Partnership's 7⅞% senior notes.

Net income attributable to noncontrolling interests decreased due to lower earnings in 2015 at the Partnership's joint ventures: Cedar Bayou Fractionators, VESCO and Versado. The inclusion of non-controlling interest from TPL's joint ventures increased the net income attributable to noncontrolling interests.

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 December 31, Year Ended December 31,
  2015  2014  2015  2014 
  ($ in millions, except operating statistics and price amounts)
Gross margin $203.8  $134.4 $760.3 $563.2
Operating expenses  69.0   52.0  275.5  190.9
Operating margin $134.8  $82.4 $484.8 $372.3
Operating statistics (1):             
Plant natural gas inlet, MMcf/d (2),(3)             
SAOU (4)(5)  241.3   221.7  234.0  193.1
WestTX (6)  462.0   -  374.0  -
Sand Hills (5)  154.0   167.3  163.0  165.1
Versado  185.9   180.6  183.2  169.6
SouthTX (6)  140.3   -  120.0  -
North Texas (7)  335.7   366.9  347.6  354.5
SouthOK (6)  470.7   -  401.5  -
WestOK (6)  510.3   -  471.7  -
Badlands (8)  56.9   37.9  49.2  38.9
   2,557.1   974.4  2,344.2  921.2
Gross NGL production, MBbl/d (3)             
SAOU  27.6   25.7  27.3  25.2
WestTX (6)  53.2   -  43.4  -
Sand Hills  16.6   17.9  17.4  18.0
Versado  23.1   23.0  23.4  21.4
SouthTX (6)  15.5   -  13.8  -
North Texas  37.9   40.4  39.6  37.8
SouthOK (6)  41.8   -  28.1  -
WestOK (6)  26.6   -  23.8  -
Badlands  8.5   3.5  6.8  3.5
   250.8   110.5  223.6  105.9
Crude oil gathered, MBbl/d  108.8   115.9  106.3  93.5
Natural gas sales, BBtu/d (3)  1,436.2   515.0  1,340.8  469.0
NGL sales, MBbl/d  205.0   84.2  176.9  80.7
Condensate sales, MBbl/d  8.0   3.3  8.3  3.6
Average realized prices (9):             
Natural gas, $/MMBtu  2.01   3.62  2.32  4.05
NGL, $/gal  0.30   0.53  0.34  0.72
Condensate, $/Bbl  34.97   63.46  41.29  82.35

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(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) Includes wellhead gathered volumes moved from Sand Hills via pipeline to SAOU for processing.
(6) Operations acquired as part of the APL merger effective February 27, 2015.
(7) Includes volumes from the 200 MMcf/d cryogenic Longhorn plant which started commercial operations in May 2014.
(8) Badlands natural gas inlet represents the total wellhead gathered volume.
(9) Average realized prices exclude the impact of hedging activities presented in Other.

Three Months Ended December 31, 2015 Compared to Three Months Ended December 31, 2014

The increase in gross margin was primarily due to the inclusion of the TPL volumes partially offset by significantly lower commodity prices. The increases in plant inlet volumes were primarily driven by the inclusion of TPL volumes and by volume increases attributable to SAOU, Sand Hills (see footnote (5) above) and Versado offset by reduced producer activity and volumes in North Texas.  Badlands crude oil volumes decreased due to reduced producer activity.  Badlands natural gas volumes increased significantly primarily due to system expansions and the Little Missouri 3 plant, which started commercial operations in January 2015.

Excluding the increased operating expenses from the TPL acquisition, other areas were significantly lower even including system expansions due to a focused cost reduction effort.

2015 Compared to 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 prices.  The increases in plant inlet volumes at SAOU, Sand Hills (see footnote (5) above) and Versado were driven by system expansions and by increased producer activity which increased available supply across the Partnership's areas of operation partially offset by reduced producer activity and volumes in North Texas.  2015 benefited from a full year operations of the Longhorn plant in North Texas, the High Plains plant in SAOU and the Little Missouri 3 plant in Badlands.  Badlands crude oil and natural gas volumes increased significantly due to plant and system expansion and increased producer activity. 

Excluding the increased operating expenses from the TPL acquisition, other areas were significantly lower even including system expansions due to a focused cost reduction effort.

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:

 Year Ended December 31, 2015
Operating statistics:              
Plant natural gas inlet, MMcf/d (1),(2) Gross
Volume (3)
 Ownership % Net Volume (3)  Pro Forma (4)  Timing
Adjustment (5)
 Actual
Reported
SAOU 234.0  100.0% 234.0  234.0   -  234.0
WestTX (6)(7) 612.8  72.8% 446.1  446.1   (72.1) 374.0
Sand Hills 163.0  100.0% 163.0  163.0   -  163.0
Versado (8) 183.2  63.0% 115.4  183.2   -  183.2
SouthTX (6) 143.1  100.0% 143.1  143.1   (23.1) 120.0
North Texas 347.6  100.0% 347.6  347.6   -  347.6
SouthOK (6) 478.9  Varies (9) 398.6  478.9   (77.4) 401.5
WestOK (6) 562.6  100.0% 562.6  562.6   (90.9) 471.7
Badlands (10) 49.2  100.0% 49.2  49.2   -  49.2
Total 2,774.5   2,459.7  2,607.8   (263.6) 2,344.2
Gross NGL production, MBbl/d (2)              
SAOU 27.3  100.0% 27.3  27.3   -  27.3
WestTX (6)(7) 71.1  72.8% 51.8  51.8   (8.4) 43.4
Sand Hills 17.4  100.0% 17.4  17.4   -  17.4
Versado 23.4  63.0% 14.7  23.4   -  23.4
SouthTX (6) 16.5  100.0% 16.5  16.5   (2.7) 13.8
North Texas 39.6  100.0% 39.6  39.6   -  39.6
SouthOK (6) 33.5  Varies (9) 29.1  33.5   (5.4) 28.1
WestOK (6) 28.4  100.0% 28.4  28.4   (4.6) 23.8
Badlands 6.8  100.0% 6.8  6.8   -  6.8
Total 264.0   231.5  244.6   (21.0) 223.6

_______
(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, other than for the volumes related to the APL merger, for which the denominator is 306 days.
(4) Pro forma statistics represents volumes per day while owned by the Partnership.
(5) Timing adjustment made to the Pro forma statistics to adjust for the actual reported statistics based on the full period.
(6) Operations acquired as part of the APL merger effective February 27, 2015.
(7) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in TRP's reported financials.
(8) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in TRP's reported financials.
(9) 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.
(10) Badlands natural gas inlet represents the total wellhead gathered volume.

 Three Months Ended December 31, 2015
Operating statistics:        
Plant natural gas inlet, MMcf/d (1),(2) Gross Volume (3) Ownership % Net Volume (3) Actual Reported
SAOU 241.3  100.0% 241.3 241.3
WestTX (4)(5) 634.6  72.8% 462.0 462.0
Sand Hills 154.0  100.0% 154.0 154.0
Versado (6) 185.9  63.0% 117.1 185.9
SouthTX (4) 140.3  100.0% 140.3 140.3
North Texas 335.7  100.0% 335.7 335.7
SouthOK (4) 470.7  Varies (7) 388.9 470.7
WestOK (4) 510.3  100.0% 510.3 510.3
Badlands (8) 56.9  100.0% 56.9 56.9
Total 2,729.7   2,406.5 2,557.1
Gross NGL production, MBbl/d (2)        
SAOU 27.6  100.0% 27.6 27.6
WestTX (4)(5) 73.1  72.8% 53.2 53.2
Sand Hills 16.6  100.0% 16.6 16.6
Versado 23.1  63.0% 14.6 23.1
SouthTX (4) 15.5  100.0% 15.5 15.5
North Texas 37.9  100.0% 37.9 37.9
SouthOK (4) 41.8  Varies (7) 35.1 41.8
WestOK (4) 26.6  100.0% 26.6 26.6
Badlands 8.5  100.0% 8.5 8.5
Total 270.7   235.6 250.8

_______
(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 December 31, Year Ended December 31,
  2015  2014  2015  2014 
  ($ in millions, except operating statistics and price amounts)
Gross margin $17.2 $21.9 $69.8 $123.8
Operating expenses  9.0  11.1  39.5  46.2
Operating margin $8.2 $10.8 $30.3 $77.6
Operating statistics (1):            
Plant natural gas inlet, MMcf/d (2),(3)            
LOU  278.1  213.9  200.1  284.6
VESCO  452.8  491.4  442.4  509.0
Other Coastal Straddles  184.0  424.8  254.5  394.8
   914.9  1,130.1  897.0  1,188.4
Gross NGL production, MBbl/d (3)            
LOU  8.5  7.1  7.2  9.0
VESCO  29.5  25.1  26.6  26.0
Other Coastal Straddles  6.0  12.8  8.0  12.1
   44.0  45.0  41.8  47.1
Natural gas sales, BBtu/d (3)  254.0  233.0  237.1  258.0
NGL sales, MBbl/d  32.5  36.5  31.4  40.2
Condensate sales, MBbl/d  1.0  0.9  0.8  0.7
Average realized prices:            
Natural gas, $/MMBtu  2.26  3.97  2.69  4.44
NGL, $/gal  0.36  0.59  0.39  0.80
Condensate, $/Bbl  38.30  68.43  47.72  89.70

__________
(1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the applicable reporting period and the denominator is the number of calendar days during the applicable reporting period.
(2) Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
(3) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

Three Months Ended December 31, 2015 Compared to Three Months Ended December 31, 2014

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

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

2015 Compared to 2014

The decrease in Coastal Gathering and Processing gross margin was primarily due to lower NGL prices, a less favorable frac spread and lower throughput volumes partially offset by new volumes at LOU and VESCO with higher average GPM. 

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 the Partnership'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 December 31,  Year Ended December 31,
  2015  2014  2015  2014 
  ($ in millions, except operating statistics)
Gross margin (1) $139.3 $164.1  $613.9 $613.3
Operating expenses (1)  41.5  43.1   174.4  168.2
Operating margin $97.8 $121.0  $439.5 $445.1
Operating statistics, MBbl/d (2):             
Fractionation volumes (3)  327.7  371.7   342.7  350.0
LSNG treating volumes  21.5  21.2   22.4  23.4
Benzene treating volumes  21.5  21.2   22.4  23.4

_______
(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 December 31, 2015 Compared to Three Months Ended December 31, 2014

Logistics Assets gross margin decreased primarily due to lower LPG export and fractionation margin, and decreased terminaling and storage activities.  LPG export volumes (which are reflected in both the Logistics Assets and Marketing and Distribution segments) averaged 192 MBbl/d in the fourth quarter of 2015 compared to a record 225 MBbl/d for the same period last year.  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), and by a decrease in supply volume. Terminaling and storage volumes decreased due to lower customer throughput.

Operating expenses decreased due to lower fuel and power expense and lower export-related costs, partially offset by lower system product gains and higher maintenance costs.

2015 Compared to 2014

Logistics Assets gross margin was flat due to the recognition of the renegotiated commercial arrangements related to the Partnership's Channelview Splitter project and increased terminaling and storage activities offset by lower LPG export and fractionation margins. Slightly higher LPG export volumes (which are reflected in both the Logistics Assets and Marketing and Distribution segments), averaged 183 MBbl/d in 2015 compared to 177 MBbl/d last year.

Fractionation gross margin was lower due to the variable effects of fuel and power, which are largely reflected in lower operating expenses (see footnote (1) above), and by a decrease in supply volume. Terminaling and storage volumes increased due to higher customer throughput.

Operating expenses increased due to lower 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 December 31,  Year Ended December 31,
  2015  2014   2015  2014 
  ($ in millions, except operating statistics and price amounts)
Gross margin $74.4 $80.9 $283.8 $298.0
Operating expenses  9.5  10.7  41.6  48.4
Operating margin $64.9 $70.2 $242.2 $249.6
Operating statistics (1):            
NGL sales, MBbl/d  450.2  476.1  432.3  423.3
Average realized prices:            
NGL realized price, $/gal  0.44  0.74  0.46  0.93

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

Three Months Ended December 31, 2015 Compared to Three Months Ended December 31, 2014

Marketing and Distribution gross margin decreased primarily due to lower LPG export volumes (which are reflected in both Logistics Assets and Marketing and Distribution segments), the expiration and recognition of a contract settlement in 2014 and a lower price environment.  The lower gross margin was partially offset by higher marketing gains.

Operating expenses decreased primarily due to lower terminal expense.

2015 Compared to 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.  The lower gross margin was partially offset by higher LPG export margin, higher marketing gains and higher terminal activity.  Slightly higher LPG export volumes are reflected in both the Logistics Assets and Marketing and Distribution segments.

Operating expenses decreased due to lower barge expense and lower terminal expense.  

Other

  Three Months Ended December 31, Year Ended December 31,
  2015  2014  2015  2014 
             
  (In millions)
Gross margin $23.5 $4.4 $84.2 $ (8.0)
Operating margin $23.5 $4.4 $84.2 $ (8.0)


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 our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our 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 December 31, 2015 Three Months Ended December 31, 2014
 (In millions, except volumetric data and price amounts)
  Volume Settled  Price Spread (1) Gain (Loss)  Volume Settled  Price Spread (1) Gain (Loss)
Natural Gas (BBtu)16.8$0.85$ 14.3  6.1$0.17$ 1.1 
NGL (MMBbl)0.3 13.33  4.0  0.2 11.86  2.9 
Crude Oil (MMBbl)0.2 39.00  7.8  0.2 18.74  4.2 
Non-Hedge Accounting (2)     (2.2)      (3.8)
Ineffectiveness (3)     (0.4)      - 
    $ 23.5     $ 4.4 
            
 Year Ended December 31, 2015 Year Ended December 31, 2014
 (In millions, except volumetric data and price amounts)
  Volume Settled  Price Spread (1) Gain (Loss)  Volume Settled  Price Spread (1) Gain (Loss)
Natural Gas (BBtu)51.8$0.71/MMBtu$ 37.0  21.9$(0.27)/MMBtu$ (5.9)
NGL (MMBbl)76.4 0.29/Bbl  22.1  0.6 5.79/Bbl  3.6 
Crude Oil (MMBbl)0.8 9.37/Bbl  21.6  0.9 (1.07)/Bbl  (1.0)
Non-Hedge Accounting (2)     2.6       (4.8)
Ineffectiveness (3)     0.9       0.1 
    $ 84.2     $ (8.0)

______________
(1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
(2) Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes.
(3) 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 $67.9 million related to these novated contracts were received during the year ended December 31, 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 Partners LP is a 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. On February 17, 2016 TRC completed the acquisition of all outstanding common units of the Partnership. Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. TRC owns, operates, acquires, and develops a diversified portfolio of complementary midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, and selling natural gas; storing, fractionating, treating, transporting, and selling NGLs and NGL products, including services to LPG exporters; gathering, storing, and terminaling crude oil; storing, terminaling, and selling refined petroleum products.

The principal executive offices of TRC 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.

On February 17, 2016, TRC completed the previously announced transactions contemplated by the TRC/TRP Merger Agreement, by and among TRP, Targa Resources GP LLC, TRC and Merger Sub pursuant to which TRC acquired indirectly all of TRP's outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP, with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of TRP's outstanding common units.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share. No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.

Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause TRP's common units to be delisted from the NYSE and deregistered under the Exchange Act. As a result of the completion of the TRC/TRP Merger, TRP's common units are no longer publicly traded. The Series A Preferred Units remain outstanding as limited partner interests in TRP and continue to trade on the NYSE under the symbol "NGLS PRA."

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, impairment of goodwill, 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 Partnership equity grants, changes in fair value of contingent consideration and mandatory redeemable preferred interests, transaction costs related to 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 December 31, Year Ended December 31,
   2015  2014  2015  2014 
    (In millions) (In millions)
Reconciliation of net income to Distributable Cash flow:            
Net income attributable to Targa Resources Partners LP $ (190.1) $ 108.2  $ (23.0) $ 467.7 
Depreciation and amortization expenses   228.8    93.7    677.1    346.5 
Goodwill impairments   290.0    -    290.0    - 
Deferred income tax expense (benefit)   0.1    0.5    (0.2)   1.6 
Non-cash interest expense, net (1)   3.3    2.5    12.6    11.2 
Loss from financing activities   (3.3)   12.4    (2.8)   12.4 
(Earnings) loss from unconsolidated affiliates (2)   1.4    (4.3)   2.5    (18.0)
Distributions from unconsolidated affiliates (2)   3.8    4.3    15.0    18.0 
Compensation on TRP equity grants (2)   3.8    2.2    16.6    9.2 
Change in redemption value of other long-term liabilities   (30.6)   -    (30.6)   - 
Change in contingent consideration   (1.2)   -    (1.2)   - 
(Gain) loss on sale or disposition of assets   (7.8)   0.8    (8.0)   (4.8)
Risk management activities   18.8    3.8    64.8    4.7 
Maintenance capital expenditures   (24.9)   (23.6)   (97.9)   (79.1)
Transactions costs related to business acquisitions (2)   (0.1)   -    14.8    - 
Other (3)   (55.0)   (1.2)   (61.9)   (6.2)
Targa Resources Partners LP distributable cash flow $ 237.0  $ 199.3  $ 867.8  $ 763.2 

 _______
(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; impairment of goodwill; 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 Partnership equity grants; transaction costs related to business acquisitions; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests 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 its assets to generate cash sufficient to pay interest costs, support its indebtedness and make distributions to its investors.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income attributable to Targa Resources Partners LP. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income. 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 December 31, Year Ended December 31,
  2015  2014   2015   2014 
            
       (In millions)
Reconciliation of Net Income to Adjusted EBITDA           
Net income attributable to Targa Resources Partners LP $ (190.1) $ 108.2 $ (23.0) $ 467.7 
Interest expense, net   30.6    39.7   207.8    143.8 
Income tax expense   0.2    1.1   0.6    4.8 
Depreciation and amortization expenses   228.8    93.7   677.1    346.5 
Provisional goodwill impairment   290.0    -   290.0    - 
(Gain) loss on sale or disposition of assets   (7.8)   0.8   (8.0)   (4.8)
(Gain) Loss from financing activities   (3.3)   12.4   (2.8)   12.4 
(Earnings) loss from unconsolidated affiliates (1)   1.4    (4.3)  2.5    (18.0)
Distributions from unconsolidated affiliates and preferred partner interests (1)   9.9    4.3   21.1    18.0 
Change in contingent consideration   (1.2)   -   (1.2)   - 
Compensation on TRP equity grants (1)   3.8    2.2   16.6    9.2 
Transaction costs related to business acquisitions (1)   (0.1)   -   14.8    - 
Risk management activities   18.8    3.8   64.8    4.7 
Other   -    -   0.6    - 
Noncontrolling interests adjustment (2)   (56.3)   (3.6)  (69.7)   (14.0)
Targa Resources Partners LP Adjusted EBITDA $ 324.7  $ 258.3 $ 1,191.2  $ 970.3 

_________
(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 December 31, Year Ended December 31,
  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 $ 346.1  $ 266.8 $ 1,083.9  $ 838.5 
Net income attributable to noncontrolling interests   49.2    (6.5)  31.9    (37.4)
Interest expense   30.6    39.7   207.8    143.8 
Non-cash interest expense, net (1)   (3.3)   (2.4)  (12.6)   (11.2)
(Earnings) loss from unconsolidated affiliates (2)   1.4    (4.3)  2.5    (18.0)
Distributions from unconsolidated affiliates and preferred interests (2)   9.9    4.3   21.1    18.0 
Transaction costs related to business acquisitions (2)   (0.1)   -   14.8    
Current income tax expense   0.1    0.6   0.8    3.2 
Other (3)   (32.5)   (4.7)  (67.6)   (18.4)
Changes in operating assets and liabilities which used (provided) cash:           
Accounts receivable and other assets   (97.0)   (214.5)  (254.9)   (58.6)
Accounts payable and other liabilities   20.3    179.3   163.5    110.4 
Targa Resources Partners LP Adjusted EBITDA $ 324.7  $ 258.3 $ 1,191.2  $ 970.3 

________
(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 December 31, Year Ended December 31,
  2015  2014  2015  2014 
  (In millions)
Reconciliation of Targa Resources Partners LP gross     
margin and operating margin to net income:           
Gross margin $ 452.0  $ 398.2  $ 1,785.6  $ 1,569.6 
Operating expenses   (122.8)   (109.4)   (504.6)   (433.0)
Operating margin   329.2    288.8    1,281.0    1,136.6 
Depreciation and amortization expenses   (228.8)   (93.7)   (677.1)   (346.5)
General and administrative expenses   (23.5)   (24.6)   (153.6)   (139.8)
Provisional goodwill impairment   (290.0)   -    (290.0)   - 
Interest expense, net   (30.6)   (39.7)   (207.8)   (143.8)
Income tax expense   (0.2)   (1.1)   (0.6)   (4.8)
Gain (loss) on sale or disposition of assets   7.9    (0.8)   8.0    4.8 
Loss from financing activities   3.4    (12.4)   2.8    (12.4)
Other, net   (6.7)   (1.8)   (17.6)   11.0 
Net income $ (239.3) $ 114.7  $ (54.9) $ 505.1 


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 December 31,  Year Ended December 31,
    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. $ (232.0) $ 92.3  $ (151.4) $ 423.0 
  Less: Net income of Targa Resources Partners LP   239.3    (114.7)   54.9    (505.1)
Net loss for TRC Non-Partnership   7.3    (22.4)   (96.5)   (82.1)
  TRC Non-Partnership income tax expense   (14.7)   13.3    39.0    63.2 
  Distributions from the Partnership   61.4    51.6    243.2    190.8 
  Loss on financing activities   -    -    12.9    - 
  Non-cash interest expense (1)   0.8    -    2.7    - 
  Depreciation - Non-Partnership assets   -    4.2    -    4.5 
  Transaction costs related to business acquisitions (1)   0.1    -    12.5    - 
  Current cash tax expense (2)   -    (12.1)   (6.5)   (63.5)
  Taxes funded with cash on hand (3)   -    2.9    6.5    11.8 
Distributable cash flow $ 54.9  $ 37.5  $ 213.8  $ 124.7 
________
 (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 $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 months and year ended December 31, 2015 and 2014.
 (3) 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,
    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  $ 2.7  $ 15.9  $ 10.2 
  Incentive Distribution Rights   43.9    38.4    173.4    139.8 
  Common Units held by TRC   13.5    10.5    53.9    40.8 
Total distributions declared by Targa Resources Partners LP   61.4    51.6    243.2    190.8 
 Income (expenses) of TRC Non-Partnership            
  General and administrative expenses   (1.7)   (1.2)   (8.1)   (8.2)
  Interest expense, net (1)   (4.9)   (0.9)   (21.4)   (3.3)
  Current cash tax expense (2)   -    (12.1)   (6.5)   (63.5)
  Taxes funded with cash on hand (3)   -    2.9    6.5    11.8 
  Other income (expense)   0.1    (2.8)   0.1    (2.9)
Distributable cash flow $ 54.9  $ 37.5  $ 213.8  $ 124.7 

_________________

(1) Excludes non-cash interest expense.
(2) 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 months and year ended December 31, 2015 and 2014.
(3) Current period portion of amount established at our IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes.

Forward-Looking Statements

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

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

Jennifer Kneale
Vice President – Finance

Matthew Meloy
Executive Vice President and Chief Financial Officer

 
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit amounts)
 Three Months Ended  Year Ended
 December 31,  December 31,
 2015  2014  2015  2014 
REVENUES           
Sale of commodities$ 1,345.7  $ 1,742.0  $ 5,465.4  $ 7,595.2 
Fees from midstream services  301.7    290.9    1,193.2    1,021.3 
Total Revenues  1,647.3    2,032.9    6,658.6    8,616.5 
COSTS AND EXPENSES           
Product purchases  1,195.3    1,634.7    4,873.0    7,046.9 
Operating expenses  122.8    109.4    504.6    433.0 
Depreciation and amortization expenses  228.8    93.7    677.1    346.5 
General and administrative expenses  23.5    24.6    153.6    139.8 
Goodwill impairment  290.0    -    290.0    - 
Other operating (income) expenses  (7.8)   2.1    (7.1)   (3.0)
Total costs and expenses  1,852.6    1,864.5    6,491.2    7,963.2 
INCOME FROM OPERATIONS  (205.3)   168.4    167.4    653.3 
Other income (expense):           
Interest expense, net  (30.6)   (39.7)   (207.8)   (143.8)
Equity earnings (loss)  (1.4)   4.3    (2.5)   18.0 
Loss from financing activities  3.4    (12.4)   2.8    (12.4)
Other  (5.2)   (4.8)   (14.2)   (5.2)
Income before income taxes  (239.1)   115.8    (54.3)   509.9 
Income tax (expense) benefit  (0.2)   (1.1)   (0.6)   (4.8)
NET INCOME  (239.3)   114.7    (54.9)   505.1 
Less: Net income attributable to noncontrolling interests  (49.2)   6.5    (31.9)   37.4 
NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP$ (190.1) $ 108.2  $ (23.0) $ 467.7 
            
Net income attributable to preferred limited partners$ 2.4  $ -  $ 2.4  $ - 
Net income attributable to general partner  40.1    40.5    172.1    148.7 
Net income attributable to limited partners  (232.6)   67.7    (197.5)   319.0 
Net income attributable to Targa Resources Partners LP$ (190.1) $ 108.2  $ (23.0) $ 467.7 
            
Net income per limited partner unit - basic$ (1.26) $ 0.58  $ (1.15) $ 2.78 
Net income per limited partner unit - diluted$ (1.26) $ 0.58  $ (1.15) $ 2.77 
            
Weighted average limited partner units outstanding - basic  184.8    116.8    172.3    114.7 
Weighted average limited partner units outstanding - diluted  185.1    117.1    172.3    115.1 


 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,
  2015  2014  2015  2014 
 REVENUES           
 Sales of commodities$ 1,345.7  $ 1,742.0  $ 5,465.4  $ 7,595.2 
 Fees from midstream services  301.7    290.9    1,193.2    1,021.3 
 Total revenues  1,647.3    2,032.9    6,658.6    8,616.5 
 COSTS AND EXPENSES           
 Product purchases  1,195.3    1,634.7    4,873.0    7,046.9 
 Operating expenses  122.8    109.4    504.6    433.1 
 Depreciation and amortization expenses  228.8    97.9    677.1    351.0 
 General and administrative expenses  25.1    25.8    161.7    148.0 
 Goodwill impairment  290.0    -    290.0    - 
 Other operating income  (7.8)   2.0    (7.1)   (3.0)
 Total costs and expenses  1,854.2    1,869.8    6,499.3    7,976.0 
 INCOME FROM OPERATIONS  (206.9)   163.1    159.3    640.5 
 Other income (expense):           
 Interest expense, net  (36.4)   (40.6)   (231.9)   (147.1)
 Equity earnings  (1.4)   4.3    (2.5)   18.0 
 Loss on financing activities  3.3    (12.4)   (10.1)   (12.4)
 Other  (5.1)   (7.5)   (26.6)   (8.0)
 Income (loss) before income taxes  (246.5)   106.9    (111.8)   491.0 
 Income tax (expense) benefit  14.5    (14.4)   (39.6)   (68.0)
 NET INCOME (LOSS)  (232.0)   92.5    (151.4)   423.0 
 Less: Net income (loss) attributable to noncontrolling interests  (258.9)   66.9    (209.7)   320.7 
 NET INCOME AVAILABLE TO COMMON SHAREHOLDERS$ 26.9  $ 25.6  $ 58.3  $ 102.3 
             
 Net income available per common share - basic$ 0.48  $ 0.61  $ 1.09  $ 2.44 
 Net income available per common share - diluted$ 0.48  $ 0.61  $ 1.09  $ 2.43 
             
 Weighted average shares outstanding - basic  56.0    42.0    53.5    42.0 
 Weighted average shares outstanding - diluted  56.0    42.1    53.6    42.1 


TARGA RESOURCES CORP. 
FINANCIAL SUMMARY (unaudited)  
KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS
(In millions)     
       
     December 31, 2015
Cash and cash equivalents:  
 TRC Non-Partnership$ 4.8 
 Targa Resources Partners  135.4 
  Total cash and cash equivalents$ 140.2 
Total funded debt:  
Current  
 Targa Resources Partners$ 219.3 
Long term  
 TRC Non-Partnership  597.5 
 Targa Resources Partners  5,164.0 
  Total long-term debt  5,761.5 
   Total funded debt:$ 5,980.8 

 

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