Targa Resources Corp. today reported second quarter 2016 results
OREANDA-NEWS. Targa Resources Corp. (NYSE:TRGP) (“TRC”, the “Company” or “Targa”) today reported second quarter 2016 results.
Second Quarter 2016 Financial Results
Second quarter 2016 net income (loss) attributable to Targa Resources Corp. was a loss of $23.2 million compared to income of $15.2 million for the second quarter of 2015.
The Company reported earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $257.1 million for the second quarter of 2016 compared to $302.4 million for the second quarter of 2015 (see the section of this release entitled “Targa Resources Corp. - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, distributable cash flow, gross margin and operating margin, 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”)).
On July 19, 2016, TRC declared a quarterly dividend of $0.9100 per share of its common stock for the three months ended June 30, 2016, or $3.64 per share on an annualized basis, unchanged to the previous quarter’s dividend and an increase of approximately 4% over the dividend for the second quarter of 2015. Total cash dividends of approximately $151.6 million will be paid August 15, 2016 on all outstanding common shares to holders of record as of the close of business on August 2, 2016. Also on July 19, 2016, TRC declared a quarterly cash dividend of $23.75 per Series A preferred share. Total cash dividends of approximately $22.9 million will be paid on August 12, 2016 on all outstanding Series A preferred shares to holders of record as of the close of business on August 2, 2016.
The Company reported distributable cash flow for the second quarter of 2016 of $169.6 million compared to total common dividends of $151.6 million and total TRC Series A preferred dividends of $22.9 million, resulting in distribution coverage of approximately 1.0 times.
Second Quarter 2016 - Capitalization, Liquidity and Financing
Targa’s total consolidated debt as of June 30, 2016 was $5,003.3 million including $275.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility due 2020 and $157.6 million, net of unamortized discounts, outstanding on the Company’s senior secured term loan due 2022. The consolidated debt also included $4,574.8 million of Targa Resource Partners LP (“TRP” or “the Partnership”) debt, net of $31.1 million of debt issuance costs, comprised of $55.0 million outstanding under TRP’s $1.6 billion senior secured revolving credit facility, $225.0 million outstanding under TRP’s accounts receivable securitization facility and $4,325.9 million of TRP senior notes, net of unamortized discounts and premiums.
As of June 30, 2016, TRC had available senior secured revolving credit facility capacity of $395.0 million. TRP had $55.0 million outstanding under its $1.6 billion senior secured revolving credit facility and $13.3 million in outstanding letters of credit, resulting in available senior secured revolving credit facility capacity of $1,531.7 million at the Partnership. Total Targa consolidated liquidity as of June 30, 2016, including $170.9 million of cash, was approximately $2.1 billion.
During the quarter ended June 30, 2016, TRC repurchased on the open market a portion of TRP’s 5% senior notes due 2018 paying $203.7 million plus accrued interest to repurchase $201.5 million of the outstanding balance. The note repurchases resulted in a $3.3 million loss, which included a write-off of $1.1 million in related debt issuance costs.
Targa Resources Corp. – Consolidated Financial Results of Operations
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||
| 2016 | 2015 | 2016 vs. 2015 | 2016 | 2015 | 2016 vs. 2015 | |||||||||||||||||||||||||||||||||
| ($ in millions, except operating statistics and price amounts) | ||||||||||||||||||||||||||||||||||||||
| Revenues | ||||||||||||||||||||||||||||||||||||||
| Sales of commodities | $ | 1,312.9 | $ | 1,396.1 | $ | (83.2 | ) | (6 | %) | $ | 2,484.0 | $ | 2,798.3 | $ | (314.3 | ) | (11 | %) | ||||||||||||||||||||
| Fees from midstream services | 270.7 | 303.3 | (32.6 | ) | (11 | %) | 542.0 | 580.8 | (38.8 | ) | (7 | %) | ||||||||||||||||||||||||||
| Total revenues | 1,583.6 | 1,699.4 | (115.8 | ) | (7 | %) | 3,026.0 | 3,379.1 | (353.1 | ) | (10 | %) | ||||||||||||||||||||||||||
| Product purchases | 1,145.2 | 1,228.1 | (82.9 | ) | (7 | %) | 2,156.2 | 2,486.6 | (330.4 | ) | (13 | %) | ||||||||||||||||||||||||||
| Gross margin (1) | 438.4 | 471.3 | (32.9 | ) | (7 | %) | 869.8 | 892.5 | (22.7 | ) | (3 | %) | ||||||||||||||||||||||||||
| Operating expenses | 138.9 | 145.8 | (6.9 | ) | (5 | %) | 271.0 | 266.9 | 4.1 | 2 | % | |||||||||||||||||||||||||||
| Operating margin (2) | 299.5 | 325.5 | (26.0 | ) | (8 | %) | 598.8 | 625.6 | (26.8 | ) | (4 | %) | ||||||||||||||||||||||||||
| Depreciation and amortization expenses | 186.1 | 163.9 | 22.2 | 14 | % | 379.6 | 282.5 | 97.1 | 34 | % | ||||||||||||||||||||||||||||
| General and administrative expenses | 47.0 | 49.2 | (2.2 | ) | (4 | %) | 92.2 | 91.7 | 0.5 | 1 | % | |||||||||||||||||||||||||||
| Goodwill impairment | — | — | — | — | 24.0 | — | 24.0 | — | ||||||||||||||||||||||||||||||
| Other operating (income) expenses | 0.1 | — | 0.1 | — | 1.1 | 0.6 | 0.5 | 83 | % | |||||||||||||||||||||||||||||
| Income from operations | 66.3 | 112.4 | (46.1 | ) | (41 | %) | 101.9 | 250.8 | (148.9 | ) | (59 | %) | ||||||||||||||||||||||||||
| Interest expense, net | (71.4 | ) | (67.6 | ) | (3.8 | ) | (6 | %) | (124.3 | ) | (121.7 | ) | (2.6 | ) | (2 | %) | ||||||||||||||||||||||
| Equity earnings (loss) | (4.4 | ) | (1.5 | ) | (2.9 | ) | (193 | %) | (9.2 | ) | 0.5 | (9.7 | ) | NM | ||||||||||||||||||||||||
| Gain (loss) from financing activities | (3.3 | ) | (3.8 | ) | 0.5 | 13 | % | 21.4 | (12.9 | ) | 34.3 | 266 | % | |||||||||||||||||||||||||
| Other income (expense) | (0.1 | ) | (0.9 | ) | 0.8 | 89 | % | (0.2 | ) | (26.9 | ) | 26.7 | 99 | % | ||||||||||||||||||||||||
| Income tax (expense) benefit | (1.7 | ) | (14.8 | ) | 13.1 | 89 | % | (4.8 | ) | (30.1 | ) | 25.3 | 84 | % | ||||||||||||||||||||||||
| Net income (loss) | (14.6 | ) | 23.8 | (38.4 | ) | (161 | %) | (15.2 | ) | 59.7 | (74.9 | ) | (125 | %) | ||||||||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 8.6 | 8.6 | — | — | 10.7 | 41.1 | (30.4 | ) | (74 | %) | ||||||||||||||||||||||||||||
| Net income (loss) attributable to Targa Resources Corp. | (23.2 | ) | 15.2 | (38.4 | ) | (253 | %) | (25.9 | ) | 18.6 | (44.5 | ) | (239 | %) | ||||||||||||||||||||||||
| Dividends on Series A preferred stock | 22.9 | — | 22.9 | — | 26.7 | — | 26.7 | — | ||||||||||||||||||||||||||||||
| Deemed dividends on Series A preferred stock | 6.5 | — | 6.5 | — | 6.5 | — | 6.5 | — | ||||||||||||||||||||||||||||||
| Net income (loss) attributable to common shareholders | $ | (52.6 | ) | $ | 15.2 | $ | (67.8 | ) | NM | $ | (59.1 | ) | $ | 18.6 | $ | (77.7 | ) | NM | ||||||||||||||||||||
| Financial and operating data: | ||||||||||||||||||||||||||||||||||||||
| Financial data: | ||||||||||||||||||||||||||||||||||||||
| Adjusted EBITDA (3) | 257.1 | 302.4 | (45.3 | ) | (15 | %) | 521.7 | 559.0 | (37.3 | ) | (7 | %) | ||||||||||||||||||||||||||
| Distributable cash flow (4) | 169.6 | 210.6 | (41.0 | ) | (19 | %) | 347.5 | 398.1 | (50.6 | ) | (13 | %) | ||||||||||||||||||||||||||
| Capital expenditures | 114.9 | 229.1 | (114.2 | ) | (50 | %) | 291.8 | 384.9 | (93.1 | ) | (24 | %) | ||||||||||||||||||||||||||
| Business acquisitions | — | — | — | — | — | 5,024.2 | (5,024.2 | ) | (100 | %) | ||||||||||||||||||||||||||||
| Operating statistics: | ||||||||||||||||||||||||||||||||||||||
| Crude oil gathered, MBbl/d | 105.2 | 106.2 | (1.0 | ) | (1 | %) | 105.2 | 103.7 | 1.5 | 1 | % | |||||||||||||||||||||||||||
| Plant natural gas inlet, MMcf/d (5) (6) (7) | 3,523.3 | 3,528.4 | (5.1 | ) | — | 3,464.6 | 3,016.6 | 448.0 | 15 | % | ||||||||||||||||||||||||||||
| Gross NGL production, MBbl/d (7) | 321.0 | 290.6 | 30.4 | 10 | % | 302.8 | 242.7 | 60.1 | 25 | % | ||||||||||||||||||||||||||||
| Export volumes, MBbl/d (8) | 181.3 | 164.3 | 17.0 | 10 | % | 181.2 | 177.9 | 3.3 | 2 | % | ||||||||||||||||||||||||||||
| Natural gas sales, BBtu/d (6) (7) (9) | 1,958.4 | 1,998.8 | (40.4 | ) | (2 | %) | 1,966.5 | 1,614.2 | 352.3 | 22 | % | |||||||||||||||||||||||||||
| NGL sales, MBbl/d (7) (9) | 515.8 | 494.9 | 20.9 | 4 | % | 531.8 | 502.2 | 29.6 | 6 | % | ||||||||||||||||||||||||||||
| Condensate sales, MBbl/d (7) | 11.4 | 11.6 | (0.2 | ) | (1 | %) | 10.4 | 8.7 | 1.7 | 20 | % | |||||||||||||||||||||||||||
| __________ | ||||||||||||||||||||||||||||||||||||||
| (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 less 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 June 30, 2016 Compared to Three Months Ended June 30, 2015
The decrease in revenues was primarily due to lower commodity prices ($116.8 million) and decreased fee-based and other revenues ($37.1 million) from lower fractionation and export fees, partially offset by increased NGL sales volumes ($36.1 million).
Lower commodity prices brought a commensurate reduction in product purchases, partially offset by increased NGL purchases.
Gathering and Processing operating margin and gross margin decreased primarily due to lower commodity prices. Logistics and Marketing operating margin and gross margin decreased due to the realization in 2015 of contract renegotiation fees, lower LPG export margin, lower fractionation margin and lower terminaling and storage throughput. 2015 results included the partial recognition of renegotiated commercial arrangements related to the Company’s crude and condensate splitter project. Lower operating expenses are due to the cost savings generated throughout the Company’s operating areas. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.
The increase in depreciation and amortization expenses primarily reflects the impact of growth investments from system expansions including the Buffalo Plant, the Edwards Plant, compressor stations and pipelines.
Lower general and administrative expenses in 2016 reflect synergies, including integrating TPL into Targa’s insurance program.
The increase in net interest expense in 2016 reflects $3.9 million of non-cash interest expense from the change in estimated redemption value of the mandatorily redeemable preferred interest for the three months ended June 30, 2016.
During the three months ended June 30, 2016, the Company repurchased $203.7 million of debt in open market purchases, which generated a loss of $3.3 million.
The increase in preferred dividends is due to the issuance of preferred stock on March 16, 2016.
Net income attributable to noncontrolling interests was flat. Distributions for the three months ended June 30, 2016 for TRP’s Preferred Units issued in November 2015 were $2.8 million, offset by lower earnings in 2016 at our joint ventures and the elimination of net income attributable to noncontrolling interests in TRP resulting from the TRC/TRP Merger in February 2016, in which TRC acquired indirectly all of the outstanding TRP common units that TRC and its subsidiaries did not already own.
The decrease in income tax expense in 2016 is due to net operating loss deferred tax benefits arising from higher tax depreciation expense at TRC as a result of the TRP Merger.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015
The decrease in revenues was primarily due to lower commodity prices ($625.5 million), partially offset by the favorable impact of inclusion of two additional months of operations of TPL during 2016 ($270.1 million). Additionally, fee-based and other revenues decreased due to lower fractionation and export fees, partially offset by the 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 lower operating margin and gross margin in 2016 were attributable to the realization in 2015 of contract renegotiation fees, lower LPG export margin, lower fractionation margin, lower terminaling and storage throughput, significantly lower commodity prices and lower throughput volumes on the Company’s gathering systems. These declines were partially offset by the inclusion of TPL operations for an additional two months in 2016. 2015 results included the partial recognition of renegotiated commercial arrangements related to the Company’s crude and condensate splitter project. Operating expenses were relatively flat compared with 2015 due to the inclusion of TPL’s operations for an additional two months in 2016, offset by to a continued focused cost reduction effort throughout the Company’s operating areas. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.
The increase in depreciation and amortization expenses is primarily due to an additional two months of TPL operations in 2016, as well as growth investments from other system expansions including the Buffalo Plant, the Edwards Plant, compressor stations and pipelines.
General and administrative expenses, which include TPL operations for an additional two months in 2016, reflect operational synergies, including integrating TPL into Targa’s insurance program.
During 2016, TRC recognized an additional impairment of goodwill of $24.0 million to finalize the $290.0 million provisional impairment recorded during the fourth quarter of 2015.
The increase in net interest expense primarily reflects higher interest expense in 2016 from an increase in borrowings resulting from the September 2015 issuance of $600.0 million of 6?% Senior Notes, partially offset by $534.3 million of open market debt repurchases during the six months ended June 30, 2016 and $14.6 million of non-cash interest income from the change in estimated redemption value of the mandatorily redeemable preferred interest for the six months ended June 30, 2016.
The decrease in equity earnings (loss) is due to lower operating results from GCF and the inclusion of an additional two months of equity losses from the T2 Joint Ventures.
Other expense in 2015 was primarily attributable to non-recurring transaction costs relate to the Atlas mergers.
During the six months ended June 30, 2016, the Company repurchased $534.3 million of debt in open market purchases, which generated a net gain of $21.4 million.
The decrease in income tax expense in 2016 is due to net operating loss deferred tax benefits arising from higher tax depreciation expense at TRC as a result of the TRP Merger.
The decrease in net income attributable to noncontrolling interests was primarily attributable to the TRC/TRP Merger in February 2016 and lower earnings in 2016 at our joint ventures, partially offset by $5.6 million of distributions for the six months ended June 30, 2016 for TRP’s Preferred Units issued in November 2015.
The increase in preferred dividends is due to the issuance of preferred stock on March 16, 2016.
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, | ||||||||||||||||||||||||||||||||||||
| 2016 | 2015 | 2016 vs. 2015 | 2016 | 2015 | 2016 vs. 2015 | ||||||||||||||||||||||||||||||||
| Gross margin | $ | 222.4 | $ | 232.6 | $ | (10.2 | ) | (4 | %) | $ | 416.5 | $ | 384.8 | $ | 31.7 | 8 | % | ||||||||||||||||||||
| Operating expenses | 83.3 | 87.9 | (4.6 | ) | (5 | %) | 161.8 | 153.4 | 8.4 | 5 | % | ||||||||||||||||||||||||||
| Operating margin | $ | 139.1 | $ | 144.7 | $ | (5.6 | ) | (4 | %) | $ | 254.7 | $ | 231.4 | $ | 23.3 | 10 | % | ||||||||||||||||||||
| Operating statistics (1): | |||||||||||||||||||||||||||||||||||||
| Plant natural gas inlet, MMcf/d (2),(3) | |||||||||||||||||||||||||||||||||||||
| SAOU (4) | 259.2 | 237.7 | 21.5 | 9 | % | 251.3 | 227.1 | 24.2 | 11 | % | |||||||||||||||||||||||||||
| WestTX (5) | 493.3 | 433.2 | 60.1 | 14 | % | 477.1 | 285.5 | 191.6 | 67 | % | |||||||||||||||||||||||||||
| Sand Hills | 135.8 | 171.5 | (35.7 | ) | (21 | %) | 143.4 | 165.0 | (21.6 | ) | (13 | %) | |||||||||||||||||||||||||
| Versado | 168.8 | 185.6 | (16.8 | ) | (9 | %) | 174.4 | 179.5 | (5.1 | ) | (3 | %) | |||||||||||||||||||||||||
| Permian | 1,057.1 | 1,028.0 | 29.1 | 1,046.2 | 857.1 | 189.1 | |||||||||||||||||||||||||||||||
| SouthTX (5) | 265.4 | 150.9 | 114.5 | 76 | % | 220.5 | 100.0 | 120.5 | 121 | % | |||||||||||||||||||||||||||
| North Texas | 327.5 | 356.1 | (28.6 | ) | (8 | %) | 327.5 | 358.0 | (30.5 | ) | (9 | %) | |||||||||||||||||||||||||
| SouthOK (5) | 470.7 | 487.2 | (16.5 | ) | (3 | %) | 464.3 | 329.6 | 134.7 | 41 | % | ||||||||||||||||||||||||||
| WestOK (5) | 445.6 | 597.4 | (151.8 | ) | (25 | %) | 466.3 | 405.4 | 60.9 | 15 | % | ||||||||||||||||||||||||||
| Central | 1,509.2 | 1,591.6 | (82.4 | ) | 1,478.6 | 1,193.0 | 285.6 | ||||||||||||||||||||||||||||||
| Badlands (6) | 51.2 | 46.8 | 4.4 | 9 | % | 52.5 | 44.5 | 8.0 | 18 | % | |||||||||||||||||||||||||||
| Total Field | 2,617.5 | 2,666.4 | (48.9 | ) | 2,577.3 | 2,094.6 | 482.7 | ||||||||||||||||||||||||||||||
| Coastal | 905.8 | 862.2 | 43.6 | 5 | % | 887.2 | 922.0 | (34.8 | ) | (4 | %) | ||||||||||||||||||||||||||
| Total | 3,523.3 | 3,528.6 | (5.3 | ) | 0 | % | 3,464.5 | 3,016.6 | 447.9 | 15 | % | ||||||||||||||||||||||||||
| Gross NGL production, MBbl/d (3) | |||||||||||||||||||||||||||||||||||||
| SAOU (4) | 32.2 | 27.7 | 4.5 | 16 | % | 30.7 | 26.5 | 4.2 | 16 | % | |||||||||||||||||||||||||||
| WestTX (5) | 61.9 | 50.5 | 11.4 | 23 | % | 57.2 | 33.2 | 24.0 | 72 | % | |||||||||||||||||||||||||||
| Sand Hills (4) | 14.1 | 18.4 | (4.3 | ) | (23 | %) | 14.9 | 17.7 | (2.8 | ) | (16 | %) | |||||||||||||||||||||||||
| Versado | 20.2 | 24.1 | (3.9 | ) | (16 | %) | 21.1 | 23.3 | (2.2 | ) | (9 | %) | |||||||||||||||||||||||||
| Permian | 128.4 | 120.7 | 7.7 | 123.9 | 100.7 | 23.2 | |||||||||||||||||||||||||||||||
| SouthTX (5) | 31.4 | 19.8 | 11.6 | 59 | % | 27.3 | 13.0 | 14.3 | 110 | % | |||||||||||||||||||||||||||
| North Texas | 37.0 | 41.1 | (4.1 | ) | (10 | %) | 36.3 | 40.9 | (4.6 | ) | (11 | %) | |||||||||||||||||||||||||
| SouthOK (5) | 47.3 | 31.5 | 15.8 | 50 | % | 37.6 | 21.1 | 16.5 | 78 | % | |||||||||||||||||||||||||||
| WestOK (5) | 29.7 | 30.5 | (0.8 | ) | (3 | %) | 28.3 | 20.4 | 7.9 | 39 | % | ||||||||||||||||||||||||||
| Central | 145.4 | 122.9 | 22.5 | 129.5 | 95.4 | 34.1 | |||||||||||||||||||||||||||||||
| Badlands | 7.0 | 7.5 | (0.5 | ) | (7 | %) | 7.3 | 5.8 | 1.5 | 26 | % | ||||||||||||||||||||||||||
| Total Field | 280.8 | 251.1 | 29.7 | 260.7 | 201.9 | 58.8 | |||||||||||||||||||||||||||||||
| Coastal | 40.1 | 39.4 | 0.7 | 2 | % | 42.2 | 40.9 | 1.3 | 3 | % | |||||||||||||||||||||||||||
| Total | 320.9 | 290.5 | 30.4 | 10 | % | 302.9 | 242.8 | 60.1 | 25 | % | |||||||||||||||||||||||||||
| Crude oil gathered, MBbl/d | 105.2 | 106.2 | (1.0 | ) | (1 | %) | 105.2 | 103.7 | 1.5 | 1 | % | ||||||||||||||||||||||||||
| Natural gas sales, BBtu/d (3) | 1,605.8 | 1,783.6 | (177.8 | ) | (10 | %) | 1,646.5 | 1,435.4 | 211.1 | 15 | % | ||||||||||||||||||||||||||
| NGL sales, MBbl/d | 256.1 | 220.8 | 35.3 | 16 | % | 237.7 | 185.9 | 51.8 | 28 | % | |||||||||||||||||||||||||||
| Condensate sales, MBbl/d | 10.9 | 11.4 | (0.5 | ) | (4 | %) | 10.2 | 8.5 | 1.7 | 20 | % | ||||||||||||||||||||||||||
| Average realized prices (7): | |||||||||||||||||||||||||||||||||||||
| Natural gas, $/MMBtu | 1.64 | 2.37 | (0.73 | ) | (31 | %) | 1.70 | 2.47 | (0.77 | ) | (31 | %) | |||||||||||||||||||||||||
| NGL, $/gal | 0.36 | 0.38 | (0.02 | ) | (5 | %) | 0.32 | 0.38 | (0.06 | ) | (16 | %) | |||||||||||||||||||||||||
| Condensate, $/Bbl | 37.94 | 48.81 | (10.87 | ) | (22 | %) | 32.21 | 46.13 | (13.92 | ) | (30 | %) | |||||||||||||||||||||||||
| _______ | |||||||||||||||||||||||||||||||||||||
| (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 June 30, 2016 Compared to Three Months Ended June 30, 2015
The decrease in gross margin was primarily due to lower commodity prices. Throughput volumes were relatively flat. The plant inlet volume increase in the Permian region was driven by SAOU and WestTX. The volume increase at SouthTX partially offset an overall volume decrease in the Central region. All other Permian and Central region business units experienced reduced producer activity and volumes. NGL production and NGL sales volumes increased and natural gas sales volumes decreased primarily due to increased ethane recovery at SouthOK and increased volumes at SouthTX during the second quarter of 2016. Badlands natural gas volumes increased due to plant and system expansions, while crude oil volumes were relatively flat.
Despite increased expenses associated with the commencement of commercial operations in April 2016 at the Buffalo Plant in WestTX and planned maintenance in Sand Hills and Versado greater than the comparable period, operating expenses decreased primarily due to a continued focus on cost reductions.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015
The increase in gross margin was primarily due to the inclusion of the TPL volumes for two full quarters of 2016 partially offset by significantly lower commodity prices and lower throughput volumes on other systems. The plant inlet volume increases in the Permian region attributable to SAOU were offset by reduced producer activity and planned maintenance at Sand Hills and Versado and 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 continued focused cost reduction effort.
Gross Operating Statistics Compared to Actual Reported
The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field portion of the Gathering and Processing segment:
| Three Months Ended June 30, 2016 | ||||||||||||||||
| Operating statistics: | ||||||||||||||||
| Plant natural gas inlet, MMcf/d (1),(2) | Gross Volume (3) | Ownership % | Net Volume (3) | Actual Reported | ||||||||||||
| SAOU (4) | 259.2 | 100 | % | 259.2 | 259.2 | |||||||||||
| WestTX (5)(6)(7) | 677.6 | 73 | % | 493.3 | 493.3 | |||||||||||
| Sand Hills (4) | 135.8 | 100 | % | 135.8 | 135.8 | |||||||||||
| Versado (8) | 168.8 | 63 | % | 106.3 | 168.8 | |||||||||||
| Total Permian | 1,241.4 | 994.6 | 1,057.1 | |||||||||||||
| SouthTX (5) | 265.4 | 100 | % | 265.4 | 265.4 | |||||||||||
| North Texas | 327.5 | 100 | % | 327.5 | 327.5 | |||||||||||
| SouthOK (5) | 470.7 | Varies (9) | 393.7 | 470.7 | ||||||||||||
| WestOK (5) | 445.6 | 100 | % | 445.6 | 445.6 | |||||||||||
| Total Central | 1,509.2 | 1,432.2 | 1,509.2 | |||||||||||||
| Badlands (10) | 51.2 | 100 | % | 51.2 | 51.2 | |||||||||||
| Total Field | 2,801.8 | 2,478.0 | 2,617.5 | |||||||||||||
| Gross NGL production, MBbl/d (2) | ||||||||||||||||
| SAOU (4) | 32.2 | 100 | % | 32.2 | 32.2 | |||||||||||
| WestTX (5)(6)(7) | 85.0 | 73 | % | 61.9 | 61.9 | |||||||||||
| Sand Hills (4) | 14.1 | 100 | % | 14.1 | 14.1 | |||||||||||
| Versado (8) | 20.2 | 63 | % | 12.7 | 20.2 | |||||||||||
| Total Permian | 151.5 | 120.9 | 128.4 | |||||||||||||
| SouthTX (5) | 31.4 | 100 | % | 31.4 | 31.4 | |||||||||||
| North Texas | 37.0 | 100 | % | 37.0 | 37.0 | |||||||||||
| SouthOK (5) | 47.3 | Varies (9) | 44.0 | 47.3 | ||||||||||||
| WestOK (5) | 29.7 | 100 | % | 29.7 | 29.7 | |||||||||||
| Total Central | 145.4 | 142.1 | 145.4 | |||||||||||||
| Badlands | 7.0 | 100 | % | 7.0 | 7.0 | |||||||||||
| Total Field | 303.9 | 270.0 | 280.8 | |||||||||||||
| ______ | ||||||||||||||||
| (1 | ) | Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. | |
| (2 | ) | Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes. | |
| (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 TRC’s reported financials. | |
| (7 | ) | Includes the Buffalo Plant that commenced commercial operations in April 2016. | |
| (8 | ) | Versado is a consolidated subsidiary and its financial results are presented on a gross basis in TRC’s reported financials. | |
| (9 | ) | SouthOK includes the Centrahoma joint venture, of which TPL owns 60% and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in TRC’s reported financials. | |
| (10 | ) | Badlands natural gas inlet represents the total wellhead gathered volume. | |
| 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 (4) | 237.7 | 100 | % | 237.7 | 237.7 | |||||||||||
| WestTX (5)(6) | 595.0 | 73 | % | 433.2 | 433.2 | |||||||||||
| Sand Hills (4) | 171.5 | 100 | % | 171.5 | 171.5 | |||||||||||
| Versado (7) | 185.6 | 63 | % | 116.9 | 185.6 | |||||||||||
| Permian | 1,189.8 | 959.3 | 1,028.0 | |||||||||||||
| SouthTX (5) | 150.9 | 100 | % | 150.9 | 150.9 | |||||||||||
| North Texas | 356.1 | 100 | % | 356.1 | 356.1 | |||||||||||
| SouthOK (5) | 487.2 | Varies (8) | 408.1 | 487.2 | ||||||||||||
| WestOK (5) | 597.4 | 100 | % | 597.4 | 597.4 | |||||||||||
| Central | 1,591.6 | 1,512.5 | 1,591.6 | |||||||||||||
| Badlands (9) | 46.8 | 100 | % | 46.8 | 46.8 | |||||||||||
| Total Field | 2,828.2 | 2,518.6 | 2,666.4 | |||||||||||||
| Gross NGL production, MBbl/d (2) | ||||||||||||||||
| SAOU (4) | 27.7 | 100 | % | 27.7 | 27.7 | |||||||||||
| WestTX (5)(6) | 69.3 | 73 | % | 50.5 | 50.5 | |||||||||||
| Sand Hills (4) | 18.4 | 100 | % | 18.4 | 18.4 | |||||||||||
| Versado (7) | 24.1 | 63 | % | 15.2 | 24.1 | |||||||||||
| Permian | 139.5 | 111.8 | 120.7 | |||||||||||||
| SouthTX (5) | 19.8 | 100 | % | 19.8 | 19.8 | |||||||||||
| North Texas | 41.1 | 100 | % | 41.1 | 41.1 | |||||||||||
| SouthOK (5) | 31.5 | Varies (8) | 28.1 | 31.5 | ||||||||||||
| WestOK (5) | 30.5 | 100 | % | 30.5 | 30.5 | |||||||||||
| Central | 122.9 | 119.5 | 122.9 | |||||||||||||
| Badlands | 7.5 | 100 | % | 7.5 | 7.5 | |||||||||||
| Total Field | 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. | |
| (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 | ) | 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 TRC’s 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. | |
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 the Company’s other operations, as well as transporting natural gas and NGLs.
Logistics and Marketing operations are generally connected to and supplied in part by the Company’s Gathering and Processing segments 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 June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||
| 2016 | 2015 | 2016 vs. 2015 | 2016 | 2015 | 2016 vs. 2015 | |||||||||||||||||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||||||||||||||||||||
| Gross margin | $ | 197.6 | $ | 221.8 | $ | (24.2 | ) | (11 | %) | $ | 407.9 | $ | 468.9 | $ | (61.0 | ) | (13 | %) | ||||||||||||||||||||
| Operating expenses | 55.8 | 58.1 | (2.3 | ) | (4 | %) | 109.4 | 113.5 | (4.1 | ) | (4 | %) | ||||||||||||||||||||||||||
| Operating margin | $ | 141.8 | $ | 163.7 | $ | (21.9 | ) | (13 | %) | $ | 298.5 | $ | 355.4 | $ | (56.9 | ) | (16 | %) | ||||||||||||||||||||
| Operating statistics MBbl/d (1): | ||||||||||||||||||||||||||||||||||||||
| Fractionation volumes (2)(3) | 329.8 | 357.8 | (28.0 | ) | (8 | %) | 312.7 | 349.3 | (36.6 | ) | (10 | %) | ||||||||||||||||||||||||||
| LSNG treating volumes (2) | 23.1 | 25.0 | (1.9 | ) | (8 | %) | 22.0 | 22.2 | (0.2 | ) | (1 | %) | ||||||||||||||||||||||||||
| Benzene treating volumes (2) | 23.1 | 25.0 | (1.9 | ) | (8 | %) | 22.0 | 22.2 | (0.2 | ) | (1 | %) | ||||||||||||||||||||||||||
| Export volumes, MBbl/d (4) | 181.3 | 164.3 | 17.0 | 10 | % | 181.2 | 177.9 | 3.3 | 2 | % | ||||||||||||||||||||||||||||
| NGL sales, MBbl/d | 463.6 | 387.9 | 75.7 | 20 | % | 472.8 | 428.6 | 44.2 | 10 | % | ||||||||||||||||||||||||||||
| Average realized prices: | ||||||||||||||||||||||||||||||||||||||
| NGL realized price, $/gal | $ | 0.48 | $ | 0.46 | $ | 0.02 | 4 | % | $ | 0.44 | $ | 0.51 | $ | (0.07 | ) | (14 | %) | |||||||||||||||||||||
| _______ | ||||||||||||||||||||||||||||||||||||||
| (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 quarter 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 and Marketing 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 June 30, 2016 Compared to Three Months Ended June 30, 2015
Logistics and Marketing gross margin decreased due to the realization in 2015 of contract renegotiation fees related to the Company’s crude and condensate splitter project, lower LPG export margin, lower fractionation margin and lower terminaling and storage throughput. LPG export margin decreased due to lower fees partially offset by higher volumes. Fractionation gross margin decreased due to lower supply volume, a decrease in system product gains and was partially impacted by the variable effects of lower fuel and power which are largely reflected in lower operating expenses (see footnote (2) above).
Operating expenses decreased primarily due to lower fuel and power expense, and lower maintenance expense resulting from continued focused cost reduction efforts. These decreases were partially offset by higher taxes and labor associated with the start-up of CBF Train 5.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015
The six month results were impacted by the same factors as discussed above for the quarter. An additional offsetting driver was increased marketing gains in 2016.
Other
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2016 | 2015 | 2016 vs. 2015 | 2016 | 2015 | 2016 vs. 2015 | |||||||||||||||||||
| ($ in millions) | ||||||||||||||||||||||||
| Gross margin | $ | 18.6 | $ | 17.1 | $ | 1.5 | $ | 45.7 | $ | 38.8 | $ | 6.9 | ||||||||||||
| Operating margin | $ | 18.6 | $ | 17.1 | $ | 1.5 | $ | 45.7 | $ | 38.8 | $ | 6.9 | ||||||||||||
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 June 30, 2016 | Three Months Ended June 30, 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) | 10.7 | $ | 1.27 | $ | 13.6 | 5.1 | $ | 1.72 | $ | 8.7 | $ | 4.9 | ||||||||||||||||
| NGL (MMgal) | 28.1 | 0.01 | 0.3 | 10.6 | 0.71 | 7.5 | (7.2 | ) | ||||||||||||||||||||
| Crude oil (MBbl) | 0.3 | 15.72 | 4.4 | 0.2 | 24.89 | 5.2 | (0.8 | ) | ||||||||||||||||||||
| Non-hedge accounting (2) | - | (4.0 | ) | 4.0 | ||||||||||||||||||||||||
| Ineffectiveness (3) | 0.3 | (0.3 | ) | 0.6 | ||||||||||||||||||||||||
| $ | 18.6 | $ | 17.1 | $ | 1.5 | |||||||||||||||||||||||
| Six Months Ended June 30, 2016 | Six Months Ended June 30, 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) | 20.2 | $ | 1.33 | $ | 26.8 | 10.1 | $ | 1.48 | $ | 14.9 | $ | 11.9 | ||||||||||||||||
| NGL (MMgal) | 58.9 | 0.07 | 4.0 | 15.0 | 0.63 | 9.5 | (5.5 | ) | ||||||||||||||||||||
| Crude oil (MBbl) | 0.5 | 23.82 | 11.5 | 0.4 | 28.73 | 10.5 | 1.0 | |||||||||||||||||||||
| Non-hedge accounting (2) | 3.1 | 3.2 | (0.1 | ) | ||||||||||||||||||||||||
| Ineffectiveness (3) | 0.3 | 0.7 | (0.4 | ) | ||||||||||||||||||||||||
| $ | 45.7 | $ | 38.8 | $ | 6.9 | |||||||||||||||||||||||
| ______________ | ||||||||||||||||||||||||||||
| (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 $6.3 million and $15.1 million related to these novated contracts were received during the three and six months ended June 30, 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 Adjusted EBITDA, distributable cash flow, 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 its 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, the Company’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.
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 its 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 TRC. 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 the Company’s industry, the Company’s definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making 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 June 30, | Six Months Ended June 30, | |||||||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA and Distributable Cash Flow | ||||||||||||||||||||
| Net income (loss) attributable to TRC | $ | (23.2 | ) | $ | 15.2 | $ | (25.9 | ) | $ | 18.6 | ||||||||||
| Impact of TRC/TRP Merger on NCI | — | 1.1 | (3.9 | ) | 28.6 | |||||||||||||||
| Income attributable to TRP preferred limited partners | 2.8 | — | 5.6 | — | ||||||||||||||||
| Interest expense, net | 71.4 | 67.6 | 124.3 | 121.7 | ||||||||||||||||
| Income tax expense | 1.7 | 14.8 | 4.8 | 30.1 | ||||||||||||||||
| Depreciation and amortization expenses | 186.1 | 163.9 | 379.6 | 282.5 | ||||||||||||||||
| Goodwill impairment | — | — | 24.0 | — | ||||||||||||||||
| (Gain) loss on sale or disposition of assets | — | (0.1 | ) | 0.9 | (0.2 | ) | ||||||||||||||
| (Gain) loss from financing activities | 3.3 | 3.8 | (21.4 | ) | 12.9 | |||||||||||||||
| (Earnings) loss from unconsolidated affiliates | 4.4 | 1.5 | 9.2 | (0.5 | ) | |||||||||||||||
| Distributions from unconsolidated affiliates and preferred partner interests, net | 3.0 | 6.9 | 8.8 | 10.4 | ||||||||||||||||
| Compensation on equity grants | 7.2 | 6.5 | 15.2 | 12.4 | ||||||||||||||||
| Transaction costs related to business acquisitions | — | 1.0 | — | 26.8 | ||||||||||||||||
| Risk management activities | 6.6 | 24.8 | 12.6 | 24.2 | ||||||||||||||||
| Noncontrolling interests adjustments (1) | (6.2 | ) | (4.6 | ) | (12.1 | ) | (8.5 | ) | ||||||||||||
| TRC Adjusted EBITDA | $ | 257.1 | $ | 302.4 | $ | 521.7 | $ | 559.0 | ||||||||||||
| Distributions to TRP preferred limited partners | (2.8 | ) | — | (5.6 | ) | — | ||||||||||||||
| Interest expenses on debt obligations (2) | (65.9 | ) | (66.2 | ) | (135.6 | ) | (117.9 | ) | ||||||||||||
| Current cash tax expense (3) | — | — | — | — | ||||||||||||||||
| Maintenance capital expenditures | (20.2 | ) | (27.6 | ) | (35.2 | ) | (46.6 | ) | ||||||||||||
| Noncontrolling interests adjustments of maintenance capex | 1.4 | 2.0 | 2.2 | 3.6 | ||||||||||||||||
| Distributable Cash Flow | $ | 169.6 | $ | 210.6 | $ | 347.5 | $ | 398.1 | ||||||||||||
| _________ | ||||||||||||||||||||
| (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 the Company’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 revenues (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 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 management 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 definitions 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 June 30, | Six Months Ended June 30, | |||||||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Reconciliation of TRC gross margin and operating margin to net income (loss) attributable to TRC: | ||||||||||||||||||||
| Gross margin | $ | 438.4 | $ | 471.3 | $ | 869.8 | $ | 892.5 | ||||||||||||
| Operating expenses | (138.9 | ) | (145.8 | ) | (271.0 | ) | (266.9 | ) | ||||||||||||
| Operating margin | 299.5 | 325.5 | 598.8 | 625.6 | ||||||||||||||||
| Depreciation and amortization expenses | (186.1 | ) | (163.9 | ) | (379.6 | ) | (282.5 | ) | ||||||||||||
| General and administrative expenses | (47.0 | ) | (49.2 | ) | (92.2 | ) | (91.7 | ) | ||||||||||||
| Goodwill impairment | — | — | (24.0 | ) | — | |||||||||||||||
| Interest expense, net | (71.4 | ) | (67.6 | ) | (124.3 | ) | (121.7 | ) | ||||||||||||
| Income tax expense | (1.7 | ) | (14.8 | ) | (4.8 | ) | (30.1 | ) | ||||||||||||
| Gain (loss) on sale or disposition of assets | — | 0.1 | (0.9 | ) | 0.2 | |||||||||||||||
| Gain (loss) from financing activities | (3.3 | ) | (3.8 | ) | 21.4 | (12.9 | ) | |||||||||||||
| Other, net | (4.6 | ) | (2.5 | ) | (9.6 | ) | (27.2 | ) | ||||||||||||
| Net income (loss) | (14.6 | ) | 23.8 | (15.2 | ) | 59.7 | ||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interests | 8.6 | 8.6 | 10.7 | 41.1 | ||||||||||||||||
| Net income (loss) attributable to TRC | $ | (23.2 | ) | $ | 15.2 | $ | (25.9 | ) | $ | 18.6 | ||||||||||
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