×

Targa Resources Corp. Reports First Quarter 2016 Financial Results

HOUSTON, April 29, 2016 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE:TRGP) (“TRC”, the “Company” or “Targa”) today reported first quarter 2016 results.

First Quarter 2016 Financial Results

First quarter 2016 net income attributable to common shareholders of Targa Resources Corp. before impairment of goodwill was $17.5 million compared to $3.2 million for the first quarter of 2015. The net income results for the first quarter 2016 excludes a non-cash loss of $24.0 million associated with impairment of goodwill in the Gathering and Processing segment.

The Company reported earnings before interest, income taxes, depreciation and amortization, impairment of goodwill and other non-cash items (“Adjusted EBITDA”) of $264.7 million for the first quarter of 2016 compared to $258.2 million for the first quarter of 2015 (see the section of this release entitled “Targa Resources Corp. - 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”)).

“In the first quarter, we completed the purchase of all of the outstanding common units of Targa Resources Partners LP that TRC did not already own, and raised approximately $1 billion through a TRC preferred equity issuance. The combination of these important transactions with the continued solid performance of our diverse business mix and exceptional workforce, enhances Targa’s position in this difficult environment,” said Joe Bob Perkins, Chief Executive Officer of the Company.

On April 20, 2016, TRC declared a quarterly dividend of $0.9100 per share of its common stock for the three months ended March 31, 2016, or $3.64 per share on an annualized basis, flat to the previous quarter’s dividend and an increase of 10% over the dividend for the first quarter of 2015. Total cash dividends of approximately $146.1 million will be paid May 16, 2016 on all outstanding common shares to holders of record as of the close of business on May 3, 2016. Also on April 20, 2016, TRC declared the prorated initial quarterly dividend on its recently issued Series A preferred shares for the period from March 16, 2016 through March 31, 2016. Total cash dividends of approximately $3.8 million will be paid on May 13, 2016 on all outstanding TRC Series A preferred shares to holders of record as of the close of business on May 3, 2016.

The Company reported distributable cash flow for the first quarter of 2016 of $179.7 million compared to total common dividends of $146.1 million and the prorated initial cash dividend of $3.8 million declared on the TRC Series A preferred shares, resulting in dividend coverage of approximately 1.2 times.

First Quarter 2016 - Capitalization, Liquidity and Financing

On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement” or “Buy-in Transaction”), dated November 2, 2015, by and among TRC, Targa Resources Partners LP (“TRP” or “The Partnership”), the general partner of TRP and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”) pursuant to which TRC acquired indirectly all of the outstanding TRP common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the TRC/TRP 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 the outstanding TRP common units.

Pursuant to the TRC/TRP Merger Agreement, TRC agreed to cause the TRP 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, the TRP common units are no longer publicly traded. The TRP 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units remain outstanding as limited partner interests in TRP and continue to trade on the NYSE under the symbol “NGLS PRA.”

In the first quarter of 2016, TRC sold to investors in a private placement 965,100 of 9.5% Series A preferred shares at $1,030 per share that resulted in net cash proceeds to the Company of $970.4 million. The investors also received 13,550,004 Series A warrants with a strike price of $18.88 per common share and 6,533,727 Series B warrants with a strike price of $25.11 per common share. Both series of warrants have a seven year term and can be exercised commencing on September 16, 2016. TRC used the net proceeds from the private placement to repay indebtedness and for general corporate purposes.

Targa’s total consolidated debt as of March 31, 2016 was $5,071.2 million including $275.0 million outstanding under TRC’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. The consolidated debt also included $4,642.9 million in TRP debt, net of $34.0 million of debt issue costs, comprised of $150.0 million outstanding under TRP’s accounts receivable securitization facility and $4,526.9 million of TRP senior unsecured notes, net of unamortized discounts and premiums.

As of March 31, 2016, TRC had available senior secured revolving credit facility capacity of $395.0 million. TRP had no outstanding borrowings under its $1.6 billion senior secured revolving credit facility, $12.2 million in outstanding letters of credit and $56.5 million of available capacity under its accounts receivable securitization, resulting in available borrowing capacity of $1,644.3 million at the Partnership. Total Targa consolidated liquidity as of March 31, 2016, including $114.5 million of cash, was over $2.1 billion.

During the quarter ended March 31, 2016, Targa repurchased on the open market a portion of various series of TRP senior notes paying $330.6 million plus accrued interest to repurchase $357.8 million of the outstanding balances. The note repurchases resulted in a $24.7 million gain, which included a write-off of $2.4 million in related deferred debt issuance costs. Subsequent to the end of the first quarter 2016, Targa has repurchased on the open market an additional $96.0 million of the outstanding balances.

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 April 29, 2016 to discuss first quarter 2016 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/events.cfm or by dialing 877-881-2598. The pass code for the dial-in is 86747191. 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 Corp. – Consolidated Financial Results of Operations

Three Months Ended March 31,
2016 2015 2016 vs. 2015
($ in millions, except operating statistics and price amounts)
Revenues
Sales of commodities$ 1,171.0 $ 1,402.2 $ (231.2) 16%
Fees from midstream services 271.4 277.5 (6.1) 2%
Total revenues 1,442.4 1,679.7 (237.3) 14%
Product purchases 1,011.0 1,258.6 (247.6) 20%
Gross margin (1) 431.4 421.1 10.3 2%
Operating expenses 132.1 121.1 11.0 9%
Operating margin (2) 299.3 300.0 (0.7) -
Depreciation and amortization expenses 193.5 118.6 74.9 63%
General and administrative expenses 45.3 42.6 2.7 6%
Goodwill impairment 24.0 24.0 0%
Other operating (income) expenses 1.0 0.6 0.4 67%
Income from operations 35.5 138.2 (102.7) 74%
Interest expense, net (52.9) (54.1) 1.2 2%
Equity earnings (4.8) 1.9 (6.7) NM
Gain (loss) from financing activities 24.7 (9.1) 33.8 NM
Gain (loss) on mark-to-market derivative instruments 0%
Other income (expense) (0.1) (26.0) 25.9 100%
Income tax (expense) benefit (3.1) (15.2) 12.1 80%
Net income (loss) (0.7) 35.7 (36.4) 102%
Less: Net income (loss) attributable to noncontrolling interests 2.0 32.5 (30.5) 94%
Net income (loss) attributable to Targa Resources Corp. (2.7) 3.2 (5.9) 184%
Dividends on Series A preferred stock 3.8 3.8 NM
Net income (loss) attributable to common shareholders$ (6.5) $ 3.2 $ (9.7) NM
Financial and operating data:
Financial data:
Adjusted EBITDA (3) 264.7 258.2 6.5 3%
Distributable cash flow (4) 179.7 188.6 (8.9) 5%
Capital expenditures 176.9 1,755.3 (1,578.4) 90%
Business Acquisitions 5024.2 (5,024.2) 100%
Operating statistics:
Crude oil gathered, MBbl/d 105.3 101.2 4.1 4%
Plant natural gas inlet, MMcf/d (5) (6) (7) 3,405.9 2,499.1 906.8 36%
Gross NGL production, MBbl/d (7) 284.6 193.7 90.9 47%
Export volumes, MBbl/d (8) 181.0 191.7 (10.7) 6%
Natural gas sales, BBtu/d (6) (7) (9) 1,974.6 1,225.2 749.3 61%
NGL sales, MBbl/d (7) (9) 547.8 509.6 38.2 8%
Condensate sales, MBbl/d (7) 9.5 5.8 3.7 63%
__________
(1) Gross margin is a non-GAAP financial measure and is discussed under “Targa Resources Corp. - Non-GAAP Financial Measures.”
(2) Operating margin is a non-GAAP financial measure and is discussed under “Targa Resources Corp. - Non-GAAP Financial Measures.”
(3) Adjusted EBITDA is net income(loss) available to TRC 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 equity grants; transaction costs related to business acquisitions; net income attributable to TRP preferred limited partners; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of depreciation and amortization expenses. This is a non-GAAP financial measure and is discussed under “Targa Resources Corp. – Non-GAAP Financial Measures.”
(4) Distributable cash flow is Adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on debt obligations, current cash tax expenses and maintenance capital expenditures (net of any reimbursements of project costs). This measure includes the impact of noncontrolling interests on the prior adjustment items. This is a non-GAAP financial measure and is discussed under “Targa Resources Corp. – 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.
(9) Includes the impact of intersegment eliminations.

Review of Consolidated Results

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015

The decrease in revenues was primarily due to significantly lower commodity prices ($522.2 million) partially offset by the favorable impacts of inclusion of two additional months of operations of Atlas Pipeline Partners, L.P., which we acquired in the first quarter of 2015 and refer to as “TPL”, during 2016 ($270.1 million). Fee-based and other revenues decreased slightly due to lower fractionation and export fees offset by the additional impact of an additional two months of TPL’s fee revenue in 2016 ($40.9 million).

Lower commodity prices brought a commensurate reduction in product purchases, partially offset by the inclusion of two additional months of operations from TPL in 2016 ($137.5 million).

The higher gross margin in 2016 was attributable to the inclusion of TPL operations, increased throughput related to other system expansions in TRC’s Gathering and Processing segment, offset by a decrease in TRC’s Logistics and Marketing segment due to lower fractionation margin, fees in 2015 from renegotiated commercial arrangements related to the Company’s crude and condensate splitter project, lower LPG export margin, and lower terminaling and storage throughput. Higher operating expenses are due to the inclusion of TPL’s operations for a full quarter in 2016, partially offset by the cost savings generated throughout TRC’s operating areas. See “—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 primarily reflects the impact of TPL operations and growth investments from other system expansions.

Higher general and administrative expenses in 2016 reflect the impact of the inclusion of TPL for an additional two months in 2016.

During 2016, TRC recognized an additional impairment of goodwill of $24.0 million to finalize the $290 million provisional impairment recorded during the fourth quarter of 2015.

The decrease in net interest expense primarily reflects $18.5 million of non-cash interest income from the change in estimated redemption value of the mandatorily redeemable preferred interest as of March 31, 2016 which is offset by higher interest expense in 2016 from increased borrowings.

Other expense in 2015 was primarily attributable to non-recurring transaction costs relate to the Atlas mergers.

During 2016, TRC recognized a gain of $24.7 million on open market debt repurchases and other financing activities compared to a loss of $9.1 million related to the reduction of the TRC term loan in 2015.

The decrease in net income attributable to noncontrolling interests was primarily attributable to the TRC/TRP Merger, in which TRC acquired indirectly all of the outstanding TRP common units that TRC and its subsidiaries did not already own. There was also a decrease due to lower earnings in 2016 at our joint ventures.

TRC is forecasting a large tax loss for 2016 and a relatively small book loss for the same period. Further, TRC has pre-tax book income for the current quarter. Consequently, the application of interim reporting rules has resulted in an income tax expense that varies significantly from the customary relationship between income tax expense and pre-tax accounting income for the quarter.

Review of Segment Performance

The following discussion of segment performance includes inter-segment revenues. The Company 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 Corp. - 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 Company operates in two primary divisions: (i) Gathering and Processing, previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing (also referred to as the Downstream Business), previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution.

Concurrent with TRC’s acquisition of TRP, management reevaluated the Company’s reportable segments and determined that its divisions are the appropriate level of disclosure for the Company’s reportable segments. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in the Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of the Logistics and Marketing division is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team.

Gathering and Processing Segment

The Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The 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; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

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

Three Months Ended March 31,
2016 2015 2016 vs. 2015
Gross margin$ 194.1 $ 152.6 $ 41.5 27%
Operating expenses 78.5 65.6 12.9 20%
Operating margin$ 115.6 $ 87.0 $ 28.6 33%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
SAOU (4) 243.5 216.5 27.0 12%
WestTX (5) 461.0 136.2 324.8 238%
Sand Hills (4) 151.1 158.5 (7.4) 5%
Versado 180.0 173.3 6.7 4%
Permian 1,035.6 684.5 351.1
SouthTX (5) 175.7 48.6 127.1 262%
North Texas 327.5 360.0 (32.5) 9%
SouthOK (5) 457.9 170.2 287.7 169%
WestOK (5) 487.0 211.2 275.8 131%
Central 1,448.1 790.0 658.1
Badlands (6) 53.7 42.1 11.6 28%
Total Field 2,537.4 1,516.6 1,020.8
Coastal 868.6 982.4 (113.8) 12%
Total 3,406.0 2,499.0 907.0 36%
Gross NGL production, MBbl/d (3)
SAOU (4) 29.2 25.3 3.9 15%
WestTX (5) 52.4 15.8 36.6 232%
Sand Hills (4) 15.7 17.0 (1.3) 8%
Versado 21.9 22.5 (0.6) 3%
Permian 119.2 80.6 38.6
SouthTX (5) 23.1 6.1 17.0 279%
North Texas 35.7 40.6 (4.9) 12%
SouthOK (5) 28.0 9.9 18.1 183%
WestOK (5) 26.9 10.2 16.7 164%
Central 113.7 66.8 46.9
Badlands 7.6 3.9 3.7 95%
Total Field 240.5 151.3 89.2
Coastal 44.2 42.4 1.8 4%
Total 284.7 193.7 91.0 47%
Crude oil gathered, MBbl/d 105.3 101.2 4.1 4%
Natural gas sales, BBtu/d (3) 1,687.2 1,083.3 604.0 56%
NGL sales, MBbl/d 219.3 150.5 68.8 46%
Condensate sales, MBbl/d 9.5 5.7 3.8 67%
Average realized prices (7):
Natural gas, $/MMBtu 1.75 2.65 (0.90) 34%
NGL, $/gal 0.28 0.39 (0.11) 29%
Condensate, $/Bbl 25.65 40.70 (15.05) 37%
_______
(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 TRC’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 wellhead gathered volumes moved from Sand Hills via pipeline to SAOU for processing.
(5) Operations acquired as part of the APL merger effective February 27, 2015.
(6) Badlands natural gas inlet represents the total wellhead gathered volume.
(7) Average realized prices exclude the impact of hedging activities presented in Other.

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015

The increase in gross margin was primarily due to the inclusion of the TPL volumes for a full quarter of 2016 partially offset by significantly lower commodity prices and slightly lower throughput volumes on our other systems. The plant inlet volume increases in the Permian region attributable to SAOU, Sand Hills (see footnote (4) above) and Versado were offset in the Central region by reduced producer activity and volumes in North Texas. Badlands crude oil and natural gas volumes increased due to plant and system expansions. Coastal plant inlet volumes decreased due to current market conditions and the decline of off-system volumes partially offset by additional higher GPM volumes.

Excluding the impact of adding operating expenses for TPL and system expansions, operating expenses for most areas were significantly lower 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 Gathering and Processing segment:

Three Months Ended March 31, 2016
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2) Gross Volume (3) Ownership % Net Volume (3) Actual Reported
SAOU (4) 243.5 100% 243.5 243.5
WestTX (5)(6) 633.2 73% 461.0 461.0
Sand Hills (4) 151.1 100% 151.1 151.1
Versado (7) 180.0 63% 113.4 180.0
Permian 1,207.8 969.0 1,035.6
SouthTX (5) 175.7 100% 175.7 175.7
North Texas 327.5 100% 327.5 327.5
SouthOK (5) 457.9 Varies (8) 380.9 457.9
WestOK (5) 487.0 100% 487.0 487.0
Central 1,448.1 1,371.1 1,448.1
Badlands (9) 53.7 100% 53.7 53.7
Total Field 2,709.6 2,393.8 2,537.4
Gross NGL production, MBbl/d (2)
SAOU (4) 29.2 100% 29.2 29.2
WestTX (5)(6) 72.0 73% 52.4 52.4
Sand Hills (4) 15.7 100% 15.7 15.7
Versado (7) 21.9 63% 13.8 21.9
Permian 138.8 111.1 119.2
SouthTX (5) 23.1 100% 23.1 23.1
North Texas 35.7 100% 35.7 35.7
SouthOK (5) 28.0 Varies (8) 24.7 28.0
WestOK (5) 26.9 100% 26.9 26.9
Central 113.7 110.4 113.7
Badlands 7.6 100% 7.6 7.6
Total Field 260.1 229.1 240.5
______
(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.
(3) For these 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.
(4) Includes wellhead gathered volumes moved from Sand Hills to SAOU for processing.
(5) Operations acquired as part of the APL merger effective February 27, 2015.
(6) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.
(7) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in TRC’s reported financials.
(8) 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 TRC’s reported financials.
(9) Badlands natural gas inlet represents the total wellhead gathered volume.


Three Months Ended March 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 (6) 216.5 100% 216.5 216.5 - 216.5
WestTX (7)(8) 543.3 73% 395.5 395.5 (259.3) 136.2
Sand Hills (6) 158.5 100% 158.5 158.5 - 158.5
Versado (9) 173.3 63% 109.2 173.3 - 173.3
Permian 1,091.6 879.7 943.8 (259.3) 684.5
SouthTX (7) 141.1 100% 141.1 141.1 (92.5) 48.6
North Texas 360.0 100% 360.0 360.0 - 360.0
SouthOK (7) 494.1 Varies (10) 415.1 494.1 (323.9) 170.2
WestOK (7) 613.2 100% 613.2 613.2 (402.0) 211.2
Central 1,608.4 1,529.3 1,608.4 (818.4) 790.0
Badlands (11) 42.1 100% 42.1 42.1 - 42.1
Total Field 2,742.1 2,451.1 2,594.3 (1,077.7) 1,516.6
Gross NGL production, MBbl/d (2)
SAOU (6) 25.3 100% 25.3 25.3 - 25.3
WestTX (7)(8) 63.0 73% 45.9 45.9 (30.1) 15.8
Sand Hills (6) 17.0 100% 17.0 17.0 - 17.0
Versado (9) 22.5 63% 14.2 22.5 - 22.5
Permian 127.8 102.3 110.7 (30.1) 80.6
SouthTX (7) 17.7 100% 17.7 17.7 (11.6) 6.1
North Texas 40.6 100% 40.6 40.6 - 40.6
SouthOK (7) 28.7 Varies (10) 25.4 28.7 (18.8) 9.9
WestOK (7) 29.6 100% 29.6 29.6 (19.4) 10.2
Central 116.7 113.3 116.7 (49.9) 66.8
Badlands 3.9 100% 3.9 3.9 - 3.9
Total Field 248.4 219.6 231.2 (79.9) 151.3
______
(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.
(3) For these 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, other than for the volumes related to the APL merger, for which the denominator is 31 days.
(4) Pro forma statistics represents volumes per day while owned by TRC.
(5) Timing adjustment made to the pro forma statistics to adjust for the actual reported statistics based on the full period.
(6) Includes wellhead gathered volumes moved from Sand Hills to SAOU for processing.
(7) Operations acquired as part of the APL merger effective February 27, 2015.
(8) Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.
(9) Versado is a consolidated subsidiary and its financial results are presented on a gross basis in TRC’s reported financials.
(10) 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 TRC’s reported financials.
(11) Badlands natural gas inlet represents the total wellhead gathered volume.

Logistics and Marketing Segment

The Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of Targa’s other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of Targa’s other operations, as well as transporting natural gas and NGLs. The Logistics and Marketing operations are generally connected to and supplied in part by TRC’s Gathering and Processing segment and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington.

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

Three Months Ended March 31,
2016 2015 2016 vs. 2015
($ in millions)
Gross margin $ 210.6 $ 246.8 $ (36.2) 15%
Operating expenses 53.6 55.5 (1.9) 3%
Operating margin $ 157.0 $ 191.3 $ (34.3) 18%
Operating statistics MBbl/d (1):
Fractionation volumes (2)(3) 295.5 340.6 (45.1) 13%
LSNG treating volumes (2) 21.0 19.4 1.6 8%
Benzene treating volumes (2) 21.0 19.4 1.6 8%
Export volumes, MBbl/d (4) 181.0 191.7 (10.7) 6%
NGL sales, MBbl/d 482.0 469.6 12.3 3%
Average realized prices:
NGL realized price, $/gal $0.41 $0.54 $(0.13) 25%
_______
(1) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year.
(2) 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.
(3) Fractionation volumes reflect those volumes delivered and settled under fractionation contracts.
(4) 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.

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015

Logistics and marketing gross margin decreased due to lower fractionation margin, the realization of contract renegotiation fees in 2015, lower LPG export margin, and lower terminaling and storage throughput, partially offset by marketing gains. Fractionation gross margin decreased due to lower supply volume and a decrease in system product gains, partially offset by the variable effects of fuel and power which are largely reflected in lower operating expenses (see footnote (2) above). 2015 results included the partial recognition of renegotiated commercial arrangements related to TRC’s crude and condensate splitter project. LPG export margin decreased due to market conditions resulting in lower fees and reduced demand.

Operating expenses decreased due to lower fuel and power expense partially offset by higher taxes and maintenance expense.

Other

Three Months Ended March 31,
2016 2015 2016 vs. 2015
($ in millions)
Gross margin $26.8 $21.7 $5.1
Operating margin $26.8 $21.7 $5.1

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 Targa’s commodity risk management activities is to mitigate a portion of the impact of commodity prices on its operating cash flow. The Company has hedged the commodity price associated with a portion of its expected (i) natural gas equity volumes and (ii) NGL and condensate equity volumes in its Gathering and Processing Operations that result from percent of proceeds or liquid processing arrangements by entering into derivative instruments. Because the Company 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 March 31, 2016 Three Months Ended March 31, 2015
(In millions, except volumetric data and price amounts)
Volume
Settled
Price
Spread
(1)
Gain
(Loss)
Volume
Settled
Price
Spread
(1)
Gain
(Loss)
2016 vs. 2015
Natural Gas (BBtu) 19.6 $0.67 $13.2 7.6 $0.88 $6.7 $6.5
NGL (Mgal) 26.2 0.15 3.8 10.3 0.30 3.1 0.7
Crude Oil (MBbl) 0.3 23.67 7.1 0.2 26.50 5.3 1.8
Non-Hedge Accounting (2) 2.7 5.6 (2.9)
Ineffectiveness (3) 0.0 1.0 (1.0)
$26.8 $21.7 $5.1
______________
(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 Company 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 $8.7 million related to these novated contracts were received during the quarter ended March 31, 2016 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.

Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream energy companies in North America. Targa 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 Targa 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 Corp. - Non-GAAP Financial Measures

This press release includes the Company’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 Company’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.

Adjusted EBITDA

The Company defines Adjusted EBITDA as net income(loss) available to TRC 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 equity grants; transaction costs related to business acquisitions; net income attributable to TRP preferred limited partners; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by the Company and by external users of its financial statements such as investors, commercial banks and others. The economic substance behind the Company’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 pay dividends to our investors.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable to Targa Resources Corp. Adjusted EBITDA should not be considered as an alternative to 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 Company’s results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in the Company’s industry, its 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.

Distributable Cash Flow

The Company defines distributable cash flow as Adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on debt obligations, current cash tax expenses and maintenance capital expenditures (net of any reimbursements of project costs). This measure includes the impact of noncontrolling interests on the prior adjustment items.

Distributable cash flow is a significant performance metric used by the Company and by external users of its financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by it (prior to the establishment of any retained cash reserves by our board of directors) to the cash dividends the Company expects to pay its shareholders. Using this metric, management and external users of its financial statements can quickly compute the coverage ratio of estimated cash flows to 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 its quarterly dividend rates.

Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income (loss) attributable to Targa Resources Corp. Distributable cash flow should not be considered as an alternative to GAAP net income (loss) available to common and preferred shareholders. 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 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 our industry, its 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 Company to Adjusted EBITDA and Distributable Cash Flow for the periods indicated:

Three Months Ended March 31,
2016 2015
(In millions)
Reconciliation of Net Income (Loss) to attributable to TRC to Adjusted EBITDA and Distributable Cash Flow
Net income (loss) available to TRC $ (2.7) $ 3.2
Impact of TRC/TRP Merger on NCI (3.8) 27.5
Income attributable to TRP preferred limited partners 2.8 -
Interest expense, net 52.9 54.1
Income tax expense 3.1 15.2
Depreciation and amortization expenses 193.5 118.6
Goodwill impairment 24.0 -
(Gain) loss on sale or disposition of assets 0.9 0.7
(Gain) loss from financing activities (24.7) 9.1
(Earnings) loss from unconsolidated affiliates 4.8 (1.7)
Distributions from unconsolidated affiliates and preferred partner interests, net 5.8 2.7
Compensation on equity grants 8.0 5.9
Transaction costs related to business acquisitions - 25.8
Risk management activities 5.9 0.7
Noncontrolling interests adjustments (1) (5.8) (3.6)
TRC Adjusted EBITDA $ 264.7 $ 258.2
Distributions to TRP preferred limited partners (2.8) -
Interest expenses on debt obligations (2) (69.6) (50.9)
Current cash tax expense (3) - -
Maintenance capital expenditures (15.0) (20.3)
Noncontrolling interests adjustments of maintenance capex 2.4 1.6
Distributable Cash Flow $ 179.7 $ 188.6
_________
(1) Noncontrolling interest portion of depreciation and amortization expenses.
(2) Excludes amortization of interest expense.
(3) Includes adjustment to account for differences between cash and book taxes.

Gross Margin

The Company defines gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as by TRP’s contract mix and commodity hedging program.

Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas, condensate, crude oil and NGLs and fee revenues related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases.

Logistics and Marketing segment gross margin consists primarily of

  • service fee revenue (including the pass-through of energy costs included in fee rates),
  • system product gains and losses, and
  • NGL and natural gas sales, less NGL and natural gas purchases, transportation costs and the net inventory change

The gross margin impacts of cash flow hedge settlements are reported in Other.

Operating Margin

The Company defines operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of its operations.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. The Company 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 Company and by external users of the Company’s financial statements, including investors and commercial banks, to assess:

  • the financial performance of the Company’s assets without regard to financing methods, capital structure or historical cost basis;

  • the Company’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

  • the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of the Company’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 Company’s industry, the Company’s definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP 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 March 31,
2016 2015
(In millions)
Reconciliation of TRC gross margin and operating margin to net income (loss) attributable to TRC:
Gross margin $ 431.4 $ 421.1
Operating expenses (132.1) (121.1)
Operating margin 299.3 300.0
Depreciation and amortization expenses (193.5) (118.6)
General and administrative expenses (45.3) (42.6)
Goodwill impairment (24.0) -
Interest expense, net (52.9) (54.1)
Income tax expense (3.1) (15.2)
Gain (loss) on sale or disposition of assets (0.9) -
Gain (loss) from financing activities 24.7 (9.1)
Other, net (5.0) (24.7)
Net income (loss) (0.7) 35.7
Net income (loss) attributable to noncontrolling interests 2.0 32.5
Net income (loss) attributable to TRC $ (2.7) $ 3.2

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 Company expects, believes or anticipates 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 Company’s control, which could cause results to differ materially from those expected by management of 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, natural gas liquids and crude oil, 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 Company’s filings with the Securities and Exchange Commission, including its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not 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

Source:Targa Resources Corp.