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Targa Resources Partners LP and Targa Resources Corp. Report Second Quarter 2015 Financial Results

HOUSTON, Aug. 4, 2015 (GLOBE NEWSWIRE) -- Targa Resources Partners LP (NYSE:NGLS) ("Targa Resources Partners" or the "Partnership") and Targa Resources Corp. (NYSE:TRGP) ("TRC" or the "Company") today reported second quarter results.

Targa Resources Partners – Second Quarter 2015 Financial Results

Second quarter 2015 net income attributable to Targa Resources Partners was $45.8 million compared to $108.8 million for the second quarter of 2014. Net income per diluted limited partner unit was $0.01 in the second quarter of 2015 compared to $0.64 for the second quarter of 2014. The Partnership reported earnings before interest, income taxes, depreciation and amortization and other non-cash items ("Adjusted EBITDA") of $303.2 million for the second quarter of 2015 compared to $228.7 million for the second quarter of 2014. The Partnership's distributable cash flow for the second quarter of 2015 of $218.4 million corresponds to distribution coverage of approximately 1.1 times the $200.4 million in total distributions to be paid on August 14, 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 strong results through the first half of 2015 are reflective of the execution, diversity and resiliency of our businesses, and of the successful integration of the assets acquired in our mergers at the end of February. Our volume growth in Field Gathering & Processing through the first half of the year results from our positioning in some of the most active basins, and complements Targa's premier downstream business. Our results are driving quarter-over-quarter distribution and dividend growth consistent with our expectations for the year," said Joe Bob Perkins, Chief Executive Officer of the Partnership and of the Company.

On July 21, 2015, the Partnership announced a cash distribution for the second quarter 2015 of $0.8250 per common unit, or $3.30 per unit on an annualized basis, representing an increase of approximately 1% over the distribution for the first quarter 2015 and 6% over the distribution for the second quarter 2014. The cash distribution will be paid on August 14, 2015 on all outstanding common units to holders of record as of the close of business on August 3, 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. – Second Quarter 2015 Financial Results

TRC reported net income available to common shareholders of $15.2 million for the second quarter 2015 compared to $26.4 million for the second quarter 2014. The net income per diluted common share was $0.27 in the second quarter of 2015 compared to net income per diluted common share of $0.63 for the second quarter of 2014.

The Company, which as of June 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.

Second quarter 2015 distributions to be paid on August 14, 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 July 21, 2015, TRC declared a quarterly dividend of $0.8750 per share of its common stock for the three months ended June 30, 2015, or $3.50 per share on an annualized basis, representing increases of approximately 5% over the previous quarter's dividend and 27% over the dividend for the second quarter of 2014. Total cash dividends of approximately $49.0 million will be paid August 17, 2015 on all outstanding common shares to holders of record as of the close of business on August 3, 2015.

The Company's distributable cash flow for the second quarter 2015 was $51.9 million compared to $49.2 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 Second Quarter 2015 - Capitalization, Liquidity and Financing

Total funded debt of the Partnership as of June 30, 2015 was $5,303.0 million including $878.0 million outstanding under the Partnership's $1.6 billion senior secured revolving credit facility, $124.2 million outstanding under the Partnership's accounts receivable securitization facility, and $4,300.8 million of senior unsecured notes, net of unamortized discounts.

As of June 30, 2015, after giving effect to $20.5 million in outstanding letters of credit, the Partnership had available revolver capacity of $701.5 million.

On April 13, 2015, we and Targa Resources Partners Finance Corporation (collectively, the "Partnership Issuers") commenced an offer to exchange (the "Exchange Offer") any and all of the outstanding 2020 APL Notes, for an equal amount of new unsecured 6⅝% Senior Notes due 2020 issued by the Partnership Issuers (the "6⅝% Notes" or the "TRP 6⅝% Notes"). On April 27, 2015, we had received tenders and consents from holders of approximately 96.3% of the total outstanding 2020 APL Notes. As a result, the minimum tender condition to the Exchange Offer and related consent solicitation was satisfied, and the APL Issuers entered into a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2020 APL Notes.

In May 2015, upon the closing of the Exchange Offer, we issued $342.1 million aggregate principal amount of the TRP 6⅝% Notes to holders of the 2020 APL Notes which were validly tendered for exchange. The related $5.6 million premium, resulting from acquisition date fair value accounting, will be amortized as an adjustment to interest expense over the remaining term of the TRP 6⅝% Notes.

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

Total funded debt of the Company as of June 30, 2015, excluding debt of the Partnership, was $617.3 million including $460.0 million outstanding under the Company's $670.0 million senior secured revolving credit facility due 2020 and $157.3 million, net of unamortized discounts, outstanding on the Company's senior secured term loan due 2022. This resulted in $210.0 million in available revolver capacity as of June 30, 2015.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 10:30 a.m. Eastern time (9:30 a.m. Central time) on August 4, 2015 to discuss second 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 73452645. 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 June 30, Six Months Ended June 30,
2015 2014 2015 2014
($ in millions, except per unit data and operating statistics)
Revenues $ 1,699.4 $ 2,000.6 $ 3,379.1 $ 4,295.3
Product purchases 1,237.0 1,616.6 2,505.3 3,531.7
Gross margin (1) 462.4 384.0 873.8 763.6
Operating expenses 136.9 106.6 248.2 210.9
Operating margin (2) 325.5 277.4 625.6 552.7
Depreciation and amortization expenses 163.9 85.8 282.5 165.3
General and administrative expenses 46.8 39.1 87.1 74.8
Other operating (income) expenses -- (0.4) 0.5 (1.0)
Income from operations 114.8 152.9 255.5 313.6
Interest expense, net (62.2) (34.9) (113.1) (68.1)
Equity earnings (1.5) 4.2 0.5 9.1
Other income (expense) 1.9 -- (11.0) --
Income tax (expense) benefit 0.3 (1.3) (0.8) (2.4)
Net income 53.3 120.9 131.1 252.2
Less: Net income attributable to noncontrolling interests 7.5 12.1 12.5 21.0
Net income attributable to Targa Resources Partners LP $ 45.8 $ 108.8 $ 118.6 $ 231.2
Net income attributable to general partner 44.6 35.8 87.1 69.6
Net income attributable to limited partners 1.2 73.0 31.5 161.6
Net income attributable to Targa Resources Partners LP $ 45.8 $ 108.8 $ 118.6 $ 231.2
Basic net income per limited partner unit $ 0.01 $ 0.64 $ 0.20 $ 1.43
Diluted net income per limited partner unit 0.01 0.64 0.20 1.42
Financial data:
Adjusted EBITDA (3) $ 303.2 $ 228.7 $ 560.2 $ 463.1
Distributable cash flow (4) 218.4 177.6 409.6 369.3
Capital expenditures 229.1 215.5 384.9 390.9
Operating data:
Crude oil gathered, MBbl/d 106.2 83.8 103.7 79.3
Plant natural gas inlet, MMcf/d (5),(6),(7) 3,528.4 2,113.8 3,016.6 2,081.2
Gross NGL production, MBbl/d (7) 290.6 155.9 242.7 149.4
Export volumes, MBbl/d (8) 164.3 159.0 177.9 137.4
Natural gas sales, BBtu/d (6),(7) 1,976.6 879.8 1,595.9 873.6
NGL sales, MBbl/d (7) 496.5 379.5 503.3 381.3
Condensate sales, MBbl/d (7) 11.6 5.0 8.7 4.3
 
(1) Gross margin is a non-GAAP financial measure and is discussed under "Targa Resources Partners - Non-GAAP Financial Measures."
(2) Operating margin is a non-GAAP financial measure and is discussed under "Targa Resources Partners - Non-GAAP Financial Measures."
(3) Adjusted EBITDA is net income attributable to Targa Resources Partners LP before: interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and redemptions, 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 APL (the "APL merger"), non-cash compensation on Partnership equity grants, transactions costs related to 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 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 and redemptions, early debt extinguishments, non-cash compensation on Partnership equity grants, 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. 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 our Galena Park Marine terminal that are destined for international markets.

Targa Resources Partners – Review of Consolidated Second Quarter Results

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

Revenues from commodity sales declined as the effect of significantly lower commodity prices ($1,310.6 million) exceeded the favorable impacts of inclusion of a full quarter of operations of Targa Pipeline Partners ("TPL") ($401.7 million); other volume increases ($524.7 million); and favorable hedge settlements ($21.1 million). Fee-based revenues increased $61.9 million, of which $53.8 million relates to the inclusion of the TPL operations.

The higher gross margins in 2015 were attributable to inclusion of TPL operations, increased throughput related to other system expansions and increased producer activity, recognition of a renegotiated commercial contract and increased terminaling and storage fees in our Logistics and Marketing segments, partially offset by decreased commodity prices. This significant growth in our asset base also brought a higher level of operating expenses for 2015. 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.

General and administrative expenses were higher primarily due to the inclusion of TPL general and administrative costs.

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

Lower equity earnings in unconsolidated investments were attributable to the inclusion of equity losses related to the unconsolidated investment entities associated with the APL merger.

Net income attributable to noncontrolling interests decreased due to lower earnings in 2015 at Cedar Bayou Fractionators, VESCO and Versado joint ventures, partially offset by the inclusion of earnings at TPL's joint ventures.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Revenues declined as the effect of significantly lower commodity prices ($2,767.4 million) exceeded the favorable impacts of the inclusion of four months of operations of TPL ($540.6 million); other volume increases ($1,132.1 million); and favorable hedge settlements ($48.9 million). Fee-based revenues increased $129.6 million, of which $71.0 million relates to the inclusion of the TPL fee revenues.

The higher gross margins in 2015 were attributable to increased Field Gathering and Processing throughput volumes associated with the TPL operations and other system expansions and increased producer activity, recognition of a renegotiated commercial contract, higher LPG exports and increased terminaling and storage fees in our Logistics and Marketing segments, partially offset by decreased commodity prices. This significant growth in our asset base also brought a higher level of operating expenses for 2015. 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 four months of TPL's tangible and intangible asset depreciation and amortization, the increased planned amortization of the Badlands intangible assets and higher depreciation related to growth investments placed in service after June 2014, including the international export expansion project, continuing development at Badlands and other system expansions.

General and administrative expenses were primarily higher due to the inclusion of four months of TPL general and administrative costs.

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

Lower equity earnings in unconsolidated investments were attributable to the inclusion of equity losses related to the unconsolidated investment entities associated with the APL merger.

Other expense in 2015 was primarily attributable to transaction costs related to the APL merger.

Net income attributable to noncontrolling interests decreased due to lower earnings in 2015 at Cedar Bayou Fractionators, VESCO and Versado joint ventures, partially offset by the inclusion of earnings at TPL's joint ventures.

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 June 30, Six Months Ended June 30,
2015 2014 2015 2014
($ in millions, except operating statistics and price amounts)
Gross margin $ 215.6 $ 144.1 $ 350.0 $ 282.9
Operating expenses 77.4 46.4 132.7 91.2
Operating margin $ 138.2 $ 97.7 $ 217.3 $ 191.7
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
SAOU (4) 237.7 177.0 227.1 171.5
WestTX (5) 433.2 -- 285.5 --
Sand Hills 171.5 159.8 165.0 163.2
Versado 185.6 170.2 179.5 162.6
SouthTX (5) 150.9 -- 100.0 --
North Texas (6) 356.1 357.6 358.0 344.5
SouthOK (5) 487.2 -- 329.6 --
WestOK (5) 597.4 -- 405.4 --
Badlands (7) 46.8 38.1 44.5 36.3
2,666.4 902.7 2,094.6 878.1
Gross NGL production, MBbl/d (3)
SAOU 27.7 25.2 26.5 24.7
WestTX (5) 50.5 -- 33.2 --
Sand Hills 18.4 18.4 17.7 18.3
Versado 24.1 21.5 23.3 20.2
SouthTX (5) 19.8 -- 13.0 --
North Texas 41.1 37.6 40.9 35.5
SouthOK (5) 31.5 -- 21.1 --
WestOK (5) 30.5 -- 20.4 --
Badlands 7.5 3.3 5.8 3.2
251.1 106.0 201.9 101.9
Crude oil gathered, MBbl/d 106.2 83.8 103.7 79.3
Natural gas sales, BBtu/d (3) 1,522.9 454.7 1,183.8 440.6
NGL sales, MBbl/d 192.9 80.5 156.1 78.0
Condensate sales, MBbl/d 10.6 4.1 7.8 3.5
Average realized prices (8):
Natural gas, $/MMBtu 2.35 4.24 2.44 4.43
NGL, $/gal 0.37 0.77 0.37 0.81
Condensate, $/Bbl 48.07 90.36 45.45 89.92
 
(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 our 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 June 30, 2015 Compared to Three Months Ended June 30, 2014

The increase in gross margin was due to the inclusion of the TPL activity acquired effective February 27, 2015. The impact of the significantly lower commodity sales prices more than offset the impact of the other throughput volumes increases. The other increases in plant inlet volumes were driven by system expansions and by increased producer activity which increased available supply across our areas of operation partially offset by the impact of severe weather and flooding conditions in North Texas. The second quarter of 2015 also benefited from 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. Higher natural gas and NGL sales reflect similar factors. Badlands crude oil and natural gas volumes increased significantly due to producer activities and system expansion.

Higher operating expenses were primarily driven by the inclusion of TPL operating expenses. Increased expenses associated with the commencement of operations of the Longhorn, High Plains and Little Missouri 3 plants were partially offset by reduced contract labor costs and compression and system maintenance expenses.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

The six months results were impacted by the same factors as discussed above for the three month comparison of 2015 to 2014.

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 June 30, 2015
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2) Gross Volume (3) Ownership % Net Volume (3) Actual Reported
SAOU 237.7 100.0% 237.7 237.7
WestTX (4)(5) 595.0 72.8% 433.2 433.2
Sand Hills 171.5 100.0% 171.5 171.5
Versado (6) 185.6 63.0% 116.9 185.6
SouthTX (4) 150.9 100.0% 150.9 150.9
North Texas 356.1 100.0% 356.1 356.1
SouthOK (4) 487.2 Varies (7) 405.8 487.2
WestOK (4) 597.4 100.0% 597.4 597.4
Badlands (8) 46.8 100.0% 46.8 46.8
2,828.2 2,516.3 2,666.4
Gross NGL production, MBbl/d (2)
SAOU 27.7 100.0% 27.7 27.7
WestTX (4)(5) 69.3 72.8% 50.5 50.5
Sand Hills 18.4 100.0% 18.4 18.4
Versado 24.1 63.0% 15.2 24.1
SouthTX (4) 19.8 100.0% 19.8 19.8
North Texas 41.1 100.0% 41.1 41.1
SouthOK (4) 31.5 Varies (7) 28.1 31.5
WestOK (4) 30.5 100.0% 30.5 30.5
Badlands 7.5 100.0% 7.5 7.5
269.9 238.8 251.1
 
(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 our reported financials.
(6) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in our 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 our 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 June 30, Six Months Ended June 30,
2015 2014 2015 2014
($ in millions, except operating statistics and price amounts)
Gross margin $ 17.0 $ 33.4 $ 34.8 $ 69.8
Operating expenses 10.5 11.6 20.7 22.0
Operating margin $ 6.5 $ 21.8 $ 14.1 $ 47.8
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
LOU 171.8 307.5 172.2 316.2
VESCO 419.6 519.9 428.6 505.3
Other Coastal Straddles 270.8 383.7 321.2 381.6
862.2 1,211.1 922.0 1,203.1
Gross NGL production, MBbl/d (3)
LOU 6.7 9.7 6.5 9.8
VESCO 24.3 28.4 24.6 25.8
Other Coastal Straddles 8.4 11.8 9.8 11.8
39.4 49.9 40.9 47.4
Natural gas sales, BBtu/d (3) 238.5 259.3 233.4 273.4
NGL sales, MBbl/d 29.5 43.1 30.8 41.8
Condensate sales, MBbl/d 0.8 0.7 0.8 0.6
Average realized prices:
Natural gas, $/MMBtu 2.73 4.65 2.87 4.84
NGL, $/gal 0.41 0.83 0.42 0.88
Condensate, $/Bbl 58.95 98.57 53.17 98.32
 
(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 June 30, 2015 Compared to Three Months Ended June 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 the idling of the Big Lake plant in November 2014 and the Lowry plant in June 2015 under current market conditions; third party and planned operational issues affecting VESCO; and the decline of leaner off-system supply volumes.

Operating expenses decreased primarily due to the idling of the Big Lake plant in November 2014.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

The six months results were impacted by the same factors as discussed above for the three month comparison of 2015 to 2014.

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 our 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 June 30, Six Months Ended June 30,
2015 2014 2015 2014
($ in millions, except operating statistics)
Gross margin (1) $ 157.6 $ 148.0 $ 321.6 $ 284.6
Operating expenses (1) 44.9 39.4 83.5 79.2
Operating margin $ 112.7 $ 108.6 $ 238.1 $ 205.4
Operating statistics, MBbl/d (2):
Fractionation volumes (3) 357.8 346.3 349.3 329.5
LSNG treating volumes 25.0 23.2 22.2 23.8
Benzene treating volumes 25.0 23.2 22.2 23.8
 
(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 June 30, 2015 Compared to Three Months Ended June 30, 2014

Logistics Assets gross margin was higher primarily due to partial recognition of renegotiated commercial arrangements related to our condensate splitter project and increased terminaling and storage activities, partially offset by lower fractionation and export margin. The benefit from the increase in fractionation supply was offset by the variable effects of fuel and power (which are largely reflected in lower operating expenses (see footnote (1) above)). LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 164 MBbl/d in the second quarter of 2015 compared to 159 MBbl/d for the same period last year.

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

In terms of operating margin, results were higher primarily due to a partial recognition of renegotiated commercial arrangements related to our condensate splitter project and increased terminaling and storage activities, partially offset by lower fractionation operating margin. Fractionation results were impacted by lower system product gains and higher maintenance costs. LPG export results were approximately flat reflecting the offsetting factors of slightly higher volumes, lower average fee rates and lower export related operating costs.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Logistics Assets gross margin was higher primarily due to partial recognition of renegotiated commercial arrangements related to our condensate splitter project, increased terminaling and storage activities, higher LPG export results, partially offset by lower treating and reservation fees. Higher fractionation volumes were offset by the variable effects of fuel and power (which are largely offset by lower operating expenses (see footnote (1) above)). LPG export volumes, which benefit both the Logistics Assets and Marketing and Distribution segments, averaged 178 MBbl/d in 2015 compared to 137 MBbl/d for 2014.

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

In terms of operating margin, results were higher primarily due to partial recognition of renegotiated commercial arrangements related to our condensate splitter project, increased terminaling and storage activities, and higher LPG export results, partially offset by lower treating and reservation fees. LPG export results were higher reflecting the higher volumes and lower export related operating costs, partially offset by lower average fee rates. Fractionation results were approximately flat reflecting the offsetting factors of higher volumes, lower system product gains and higher maintenance.

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 June 30, Six Months Ended June 30,
2015 2014 2015 2014
($ in millions, except operating statistics and price amounts)
Gross margin $ 61.6 $ 65.7 $ 139.4 $ 143.4
Operating expenses 10.6 12.4 22.1 25.5
Operating margin $ 51.0 $ 53.3 $ 117.3 $ 117.9
Operating statistics (1):
NGL sales, MBbl/d 397.9 384.9 438.5 385.7
Average realized prices:
NGL realized price, $/gal 0.46 0.92 0.50 1.03
 
(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 June 30, 2015 Compared to Three Months Ended June 30, 2014

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

Operating Expenses decreased primarily due to lower barge expense.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 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, and lower refinery LPG supply. LPG export results (which benefit both Logistics Assets and Marketing and Distribution segments) were higher.

Operating Expenses decreased primarily due to lower barge and railcar expense.

Other

Three Months Ended June 30, Six Months Ended June 30,
2015 2014 2015 2014
(In millions)
Gross margin $ 17.1 $ (4.0) $ 38.8 $ (10.1)
Operating margin $ 17.1 $ (4.0) $ 38.8 $ (10.1)

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. We have hedged the commodity price associated with a portion of our expected (i) natural gas equity volumes in Field Gathering and Processing Operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing as well as in the LOU portion of the Coastal Gathering and Processing Operations that result from percent of proceeds or liquid processing arrangements by entering into derivative instruments. Because we are essentially forward-selling a portion of our plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

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

Three Months Ended June 30, 2015 Three Months Ended June 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)
Natural Gas (BBtu) 11.2 $ 0.67 $ 7.5 5.3 $ (0.45) $ (2.4)
NGL (MMBbl) 0.7 8.86 6.2 0.1 4.88 0.5
Crude Oil (MMBbl) 0.3 9.00 2.7 0.2 (12.50) (2.5)
Non-Hedge Accounting (3) 1.0 0.2
Ineffectiveness (4) (0.30) 0.2
$ 17.1 $ (4.0)
Six Months Ended June 30, 2015 Six Months Ended June 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)
Natural Gas (BBtu) 18.8 $ 0.76 $ 14.2 9.8 $ (0.69) $ (6.8)
NGL (MMBbl) 0.9 10.33 9.3 0.2 0.49 0.1
Crude Oil (MMBbl) 0.5 16.00 8.0 0.4 (10.00) (4.0)
Non-Hedge Accounting (3) 6.6 0.5
Ineffectiveness (4) 0.7 0.1
$ 38.8 $ (10.1)
 
(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.

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 $23.1 million and $31.5 million related to these novated contracts were received during the three and six months ended June 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 and redemptions, early debt extinguishments, non-cash compensation on Partnership equity grants, transaction costs related to business acquisitions, earnings/losses from unconsolidated affiliates net of distributions and asset disposals, 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 cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for the Partnership's unitholders since it serves as an indicator of the Partnership's success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Partnership is generating cash flow at a level that can sustain or support an increase in its quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit's yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).

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

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

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

Three Months Ended June 30, Six Months Ended June 30,
2015 2014 2015 2014
(In millions)
Reconciliation of net income to distributable cash flow:
Net income attributable to Targa Resources Partners LP $ 45.8 $ 108.8 $ 118.6 $ 231.2
Depreciation and amortization expenses 163.9 85.8 282.5 165.3
Deferred income tax expense (benefit) (0.3) 0.3 0.3 0.7
Non-cash interest expense, net (1) 3.0 3.3 6.0 6.7
(Earnings) loss from unconsolidated affiliates (2) 1.5 (4.2) (0.5) (9.1)
Distributions from unconsolidated affiliates (2) 4.3 4.2 7.0 9.1
Compensation on TRP equity grants (2) 5.1 2.3 8.9 4.9
(Gain) loss on sale or disposition of assets (0.1) (0.5) (0.2) (1.2)
Risk management activities 24.8 (0.4) 24.2 (0.7)
Maintenance capital expenditures (27.6) (20.0) (46.6) (33.7)
Transaction costs related to business acquisitions (2) 0.6 -- 14.3 --
Other (3) (2.6) (2.0) (4.9) (3.9)
Targa Resources Partners LP distributable cash flow $ 218.4 $ 177.6 $ 409.6 $ 369.3
 
(1) Includes amortization of debt issuance costs, discount and premium.
(2) The definition of Adjusted EBITDA was revised 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 and redemptions, 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 acquisitions; earnings/losses from unconsolidated affiliates net of distributions and the non-controlling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by the Partnership and by external users of its financial statements such as investors, commercial banks and others. 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.

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

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

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

Three Months Ended June 30, Six Months Ended June 30,
2015 2014 2015 2014
(In millions)
Reconciliation of Net Income to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP $ 45.8 $ 108.8 $ 118.6 $ 231.2
Interest expense, net 62.2 34.9 113.1 68.1
Income tax expense (benefit) (0.3) 1.3 0.8 2.4
Depreciation and amortization expenses 163.9 85.8 282.5 165.3
Gain on sale or disposition of assets (0.1) (0.5) (0.2) (1.2)
(Earnings) loss from unconsolidated affiliates (1) 1.5 (4.2) (0.5) (9.1)
Distributions from unconsolidated affiliates (1) 4.3 4.2 7.0 9.1
Compensation on TRP equity grants (1) 5.1 2.3 8.9 4.9
Transaction costs related to business acquisitions (1) 0.6 -- 14.3 --
Risk management activities 24.8 (0.4) 24.2 (0.7)
Noncontrolling interests adjustment (2) (4.6) (3.5) (8.5) (6.9)
Targa Resources Partners LP Adjusted EBITDA $ 303.2 $ 228.7 $ 560.2 $ 463.1
 
(1) The definition of Adjusted EBITDA was revised 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 June 30, Six Months Ended June 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 $ 209.8 $ 140.4 $ 522.3 $ 456.8
Net income attributable to noncontrolling interests (7.5) (12.1) (12.5) (21.0)
Interest expense 62.2 34.9 113.1 68.1
Non-cash interest expense, net (1) (3.0) (3.3) (6.0) (6.7)
(Earnings) loss from unconsolidated affiliates (2) 1.5 (4.2) (0.5) (9.1)
Distributions from unconsolidated affiliates (2) 4.3 4.2 7.0 9.1
Transaction costs related to business acquisitions (2) 0.6 -- 14.3 --
Current income tax expense -- 1.0 0.5 1.7
Other (3) (11.7) (4.5) (24.8) (9.1)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivables, inventories and other assets (19.9) 152.3 (204.6) 41.1
Accounts payable and other liabilities 66.9 (80.0) 151.4 (67.8)
Targa Resources Partners LP Adjusted EBITDA $ 303.2 $ 228.7 $ 560.2 $ 463.1
 
(1) Includes amortization of debt issuance costs, discount and premium.
(2) The definition of Adjusted EBITDA was revised 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 gain or loss on debt repurchase and redemptions.

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

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

Three Months Ended June 30, Six Months Ended June 30,
2015 2014 2015 2014
(In millions)
Reconciliation of Targa Resources Partners LP gross margin and operating margin to net income:
Gross margin $ 462.4 $ 384.0 $ 873.8 $ 763.6
Operating expenses (136.9) (106.6) (248.2) (210.9)
Operating margin 325.5 277.4 625.6 552.7
Depreciation and amortization expenses (163.9) (85.8) (282.5) (165.3)
General and administrative expenses (46.8) (39.1) (87.1) (74.8)
Interest expense, net (62.2) (34.9) (113.1) (68.1)
Income tax (expense) benefit 0.3 (1.3) (0.8) (2.4)
Gain on sale or disposition of assets 0.1 0.5 0.2 1.2
Other, net 0.3 4.1 (11.2) 8.9
Targa Resources Partners LP net income $ 53.3 $ 120.9 $ 131.1 $ 252.2

Targa Resources Corp. - Non-GAAP Financial Measures

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

Distributable Cash Flow - The Company defines distributable cash flow as distributions due to it from the Partnership, less the Company's specific general and administrative costs as a separate public reporting entity, the interest carry costs associated with its debt and taxes attributable to the Company's earnings.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 attributable to Targa Resources Corp. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Corp. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of the Company's results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income attributable to Targa Resources Corp. and is defined differently by different companies in the Company's industry, the Company's definition of distributable cash flow may not be compatible to similarly titled measures of other companies, thereby diminishing its utility.

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

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

Three Months Ended June 30, Six Months Ended June 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. $ 23.8 $ 103.2 $ 59.7 $ 210.2
Less: Net income of Targa Resources Partners LP (53.3) (120.9) (131.1) (252.2)
Net loss for TRC Non-Partnership (29.5) (17.7) (71.4) (42.0)
TRC Non-Partnership income tax expense 15.1 14.2 29.3 35.7
Distributions from the Partnership 61.4 46.3 120.4 90.3
Loss on debt redemptions and amendments 3.8 -- 12.9 --
Non-cash interest expense (1) 0.9 -- 1.2 --
Depreciation - Non-Partnership assets -- 0.1 -- 0.1
Transaction costs related to business acquisitions (1) 0.2 -- 12.3 --
Current cash tax expense (2) (2.3) (17.1) (4.8) (34.1)
Taxes funded with cash on hand (3) 2.3 2.9 4.8 5.9
Distributable cash flow $ 51.9 $ 28.7 $ 104.7 $ 55.9
 
(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 $2.4 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 six months ended June 30, 2015 and 2014, and includes $(1.1) million and $3.9 million adjustments to account for differences between taxes used to derive cash available for distribution and book taxes for the three and six months ended June 30, 2015.
(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 June 30, Six Months Ended June 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 $ 2.5 $ 7.9 $ 4.9
Incentive Distribution Rights 43.9 33.7 85.6 65.4
Common Units held by TRC 13.5 10.1 26.9 20.0
Total distributions declared by Targa Resources Partners LP 61.4 46.3 120.4 90.3
Income (expenses) of TRC Non-Partnership
General and administrative expenses (2.4) (2.5) (4.6) (4.7)
Interest expense, net (1) (7.1) (0.8) (10.8) (1.5)
Current cash tax expense (2) (2.3) (17.1) (4.8) (34.1)
Taxes funded with cash on hand (3) 2.3 2.9 4.8 5.9
Other income (expense) -- (0.1) (0.3) --
Distributable cash flow $ 51.9 $ 28.7 $ 104.7 $ 55.9
 
(1) Excludes non-cash interest expense.
(2) Excludes $1.2 million and $2.4 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 six months ended June 30, 2015 and 2014, and includes $(1.1) million and $3.9 million adjustments to account for differences between taxes used to derive cash available for distribution and book taxes for the three and six months ended June 30, 2015.
(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
Senior Director – Finance

Matthew Meloy
Executive Vice President, Chief Financial Officer and Treasurer

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED BALANCE SHEETS
(In millions)
June 30, 2015 December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents $ 85.5 $ 72.3
Trade receivables 602.0 566.8
Inventories 124.8 168.9
Assets from risk management activities 91.8 44.4
Other current assets 5.2 3.8
Total current assets 909.3 856.2
Property, plant and equipment, net 9,684.3 4,824.6
Intangible assets, net 1,735.6 591.9
Long-term assets from risk management activities 40.3 15.8
Goodwill 557.9 --
Other long-term assets 310.2 88.7
Total assets $ 13,237.6 $ 6,377.2
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities $ 684.4 $ 645.9
Account receivable securitization facility 124.2 182.8
Liabilities from risk management activities 1.9 5.2
Total current liabilities 810.5 833.9
Long-term debt 5,178.8 2,783.4
Long-term liabilities from risk management activities 5.3 --
Other long-term liabilities 95.7 71.5
Owners' equity:
Targa Resources Partners LP owner's equity 6,849.9 2,517.2
Noncontrolling interests in subsidiaries 297.4 171.2
Total owners' equity 7,147.3 2,688.4
Total liabilities and owners' equity $ 13,237.6 $ 6,377.2
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit amounts)
Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
REVENUES $ 1,699.4 $ 2,000.6 $ 3,379.1 $ 4,295.3
COSTS AND EXPENSES
Product purchases 1,237.0 1,616.6 2,505.3 3,531.7
Operating expenses 136.9 106.6 248.2 210.9
Depreciation and amortization expenses 163.9 85.8 282.5 165.3
General and administrative expenses 46.8 39.1 87.1 74.8
Other operating (income) expenses -- (0.4) 0.5 (1.0)
Total costs and expenses 1,584.6 1,847.7 3,123.6 3,981.7
INCOME FROM OPERATIONS 114.8 152.9 255.5 313.6
Other income (expense):
Interest expense, net (62.2) (34.9) (113.1) (68.1)
Equity earnings (loss) (1.5) 4.2 0.5 9.1
Other 1.9 -- (11.0) --
Income before income taxes 53.0 122.2 131.9 254.6
Income tax (expense) benefit 0.3 (1.3) (0.8) (2.4)
NET INCOME 53.3 120.9 131.1 252.2
Less: Net income attributable to noncontrolling interests 7.5 12.1 12.5 21.0
NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP $ 45.8 $ 108.8 $ 118.6 $ 231.2
Net income attributable to general partner $ 44.6 $ 35.8 $ 87.1 $ 69.6
Net income attributable to limited partners 1.2 73.0 31.5 161.6
Net income attributable to Targa Resources Partners LP $ 45.8 $ 108.8 $ 118.6 $ 231.2
Net income per limited partner unit - basic $ 0.01 $ 0.64 $ 0.20 $ 1.43
Net income per limited partner unit - diluted $ 0.01 $ 0.64 $ 0.20 $ 1.42
Weighted average limited partner units outstanding - basic 181.9 114.2 159.7 113.3
Weighted average limited partner units outstanding - diluted 182.6 114.9 160.1 113.9
TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED CASH FLOW INFORMATION
(In millions)
Six Months Ended June 30,
2015 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 131.1 $ 252.2
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense 6.0 6.7
Compensation on equity grants 8.9 4.9
Depreciation and amortization expense 282.5 165.3
Accretion of asset retirement obligations 2.6 2.2
Deferred income tax expense (benefit) 0.3 0.7
Equity earnings of unconsolidated affiliates (0.5) (9.1)
Distributions received from unconsolidated affiliates 6.9 9.1
Risk management activities 31.5 (0.7)
(Gain) loss on sale or disposal of assets (0.2) (1.2)
Changes in operating assets and liabilities 53.2 26.7
Net cash provided by operating activities 522.3 456.8
CASH FLOWS FROM INVESTING ACTIVITIES
Outlays for property, plant and equipment (436.2) (419.6)
Business acquisition, net of cash acquired (828.7) --
Return of capital from unconsolidated affiliate 0.1 3.6
Other, net (1.3) 2.3
Net cash used in investing activities (1,266.1) (413.7)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility 1,343.0 950.0
Repayments of credit facility (465.0) (850.0)
Borrowings from accounts receivable securitization facility 253.4 67.8
Repayments of accounts receivable securitization facility (312.0) (113.2)
Proceeds from issuance of senior notes 1,100.0 --
Redemption of APL senior notes (1,168.8) --
Costs in connection with financing arrangements (14.6) (1.7)
Proceeds from sale of common units 295.8 168.1
Repurchase of common units under compensation plans (2.1) --
Contributions received from General Partner 58.7 --
Contributions received from noncontrolling interests 5.9 --
Distributions paid to unitholders (331.7) (237.1)
Distributions to noncontrolling interests (5.6) (17.2)
Net cash provided by (used in) financing activities 757.0 (33.3)
Net change in cash and cash equivalents 13.2 9.8
Cash and cash equivalents, beginning of period 72.3 57.5
Cash and cash equivalents, end of period $ 85.5 $ 67.3
TARGA RESOURCES CORP.
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts)
Three Months Ended June 30, Six Months Ended June 30,
2015 2014 2015 2014
REVENUES $ 1,699.4 $ 2,000.6 $ 3,379.1 $ 4,295.3
COSTS AND EXPENSES
Product purchases 1,237.0 1,616.6 2,505.3 3,531.7
Operating expenses 136.9 106.6 248.2 210.9
Depreciation and amortization expenses 163.9 85.9 282.5 165.4
General and administrative expenses 49.2 41.6 91.7 79.5
Other operating income -- (0.4) 0.6 (1.0)
Total costs and expenses 1,587.0 1,850.3 3,128.3 3,986.5
INCOME FROM OPERATIONS 112.4 150.3 250.8 308.8
Other income (expense):
Interest expense, net (70.2) (35.7) (125.1) (69.6)
Equity earnings (1.5) 4.2 0.5 9.1
Gain (loss) on debt redemption and amendments (3.8) -- (12.9) --
Other 1.7 (0.1) (23.5) --
Income before income taxes 38.6 118.7 89.8 248.3
Income tax (expense) benefit (14.8) (15.5) (30.1) (38.1)
NET INCOME 23.8 103.2 59.7 210.2
Less: Net income attributable to noncontrolling interests 8.6 76.8 41.1 164.2
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 15.2 $ 26.4 $ 18.6 $ 46.0
Net income available per common share - basic $ 0.27 $ 0.63 $ 0.37 $ 1.10
Net income available per common share - diluted $ 0.27 $ 0.63 $ 0.36 $ 1.09
Weighted average shares outstanding - basic 55.9 42.0 50.9 42.0
Weighted average shares outstanding - diluted 56.1 42.1 51.0 42.1
TARGA RESOURCES CORP.
FINANCIAL SUMMARY (unaudited)
KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS
(In millions)
June 30, 2015
Cash and cash equivalents:
TRC Non-Partnership $ 20.2
Targa Resources Partners 85.5
Total cash and cash equivalents $ 105.7
Total funded debt:
Current
Targa Resources Partners $ 124.2
Long term
TRC Non-Partnership 617.3
Targa Resources Partners 5,178.8
Total long-term debt 5,796.1
Total funded debt: $ 5,920.3

Source:Targa Resources Partners LP