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Targa Resources Corp. Reports Third Quarter 2019 Financial Results and Provides Preliminary 2020 Growth Capital Outlook


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Source: Targa Resources Corp.

HOUSTON, Nov. 07, 2019 (GLOBE NEWSWIRE) — Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported third quarter 2019 results.

Third Quarter 2019 Financial Results

Third quarter 2019 net loss attributable to Targa Resources Corp. was $47.3 million compared to a net loss of $23.7 million for the third quarter of 2018.

The Company reported quarterly earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $349.6 million for the third quarter of 2019 compared to $347.2 million for the third quarter of 2018 (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”)).

“Our Gathering and Processing and Downstream systems continued to perform very well, bolstered by the partial quarter contribution of our recently completed Grand Prix NGL Pipeline,” said Joe Bob Perkins, Chief Executive Officer of the Company. “With the recent completion of Grand Prix and other important growth projects, we are beginning to demonstrate the strategic benefits of our premier integrated midstream position and our cash flow profile is expected to strengthen meaningfully, positioning Targa well over the long-term.”

On October 16, 2019, TRC declared a quarterly dividend of $0.91 per share of its common stock for the three months ended September 30, 2019, or $3.64 per share on an annualized basis. Total cash dividends of approximately $211.8 million will be paid on November 15, 2019 on all outstanding shares of common stock to holders of record as of the close of business on November 1, 2019. Also, on October 16, 2019, TRC declared a quarterly cash dividend of $23.75 per share of its Series A Preferred Stock. Total cash dividends of approximately $22.9 million will be paid on November 14, 2019 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on November 1, 2019.

The Company reported distributable cash flow for the third quarter of 2019 of $229.9 million compared to total common dividends to be paid of $211.8 million and total Series A Preferred Stock dividends to be paid of $22.9 million, resulting in dividend coverage of approximately 1.0 times.

Third Quarter 2019 – Sequential Quarter over Quarter Commentary

Third quarter 2019 Adjusted EBITDA of $349.6 million was 14 percent higher than the second quarter of 2019, driven by meaningful contributions from recently completed growth projects in Targa’s Gathering and Processing and Downstream segments. In the Gathering and Processing segment, strong volume performance in the Permian region and the Badlands, combined with lower operating expenses, was partially offset by lower natural gas liquids (“NGL”) price realizations. Sequentially lower realized NGL prices in the third quarter versus the second quarter were partially offset by realized hedge gains, which are presented in Other. Strong financial performance in the Downstream segment was led by Targa’s Grand Prix NGL Pipeline (“Grand Prix”), which commenced full operations into Mont Belvieu in August 2019. Grand Prix deliveries into Mont Belvieu averaged approximately 230 thousand barrels per day in September 2019 and are expected to further increase. Fractionation volumes in the third quarter were flat relative to the second quarter as the Company completed a scheduled turnaround and related maintenance, and Targa’s fractionation complex in Mont Belvieu has since returned to operating at a very high utilization rate. Higher sequential operating expenses in the Downstream segment were attributable to a full quarter of Train 6 operations and a partial quarter of full operations of Grand Prix.

The Company has forward natural gas basis swaps that do not qualify for hedge accounting treatment. As of September 30, 2019, the non-cash unrealized mark-to-market loss attributable to the change in fair value of the financial instruments was $101.2 million. This unrealized mark-to-market loss is attributable to unfavorable movements in forward natural gas basis prices and will be more than offset by locked-in gains to be realized in future periods from the underlying transportation arrangements.

Third Quarter 2019 – Capitalization and Liquidity

The Company’s total consolidated debt as of September 30, 2019 was $7,537.7 million including $435.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility. The consolidated debt included $7,102.7 million of Targa Resources Partners LP’s (“TRP” or the “Partnership”) debt, net of $40.7 million of debt issuance costs, with $830.0 million outstanding under TRP’s $2.2 billion senior secured revolving credit facility, $246.0 million outstanding under TRP’s accounts receivable securitization facility, $6,028.5 million of outstanding TRP senior notes, net of unamortized premiums, and $38.9 million of finance lease liabilities.

Total consolidated liquidity of the Company as of September 30, 2019, including $326.3 million of cash, was over $1.8 billion. As of September 30, 2019, TRC had available borrowing capacity under its senior secured revolving credit facility of $235.0 million. TRP had $830.0 million of borrowings and $73.8 million in letters of credit outstanding under its $2.2 billion senior secured revolving credit facility, resulting in available senior secured revolving credit facility capacity of $1,296.2 million.

Growth Projects Update

Since the beginning of 2019, the Company has completed and commenced operations on numerous major growth projects, aggregating to approximately $4.0 billion of growth capital projects placed in-service. In addition to Grand Prix being placed in-service during the third quarter, Targa also commenced operations on its 200 million cubic feet per day (“MMcf/d”) Little Missouri 4 Plant (“LM4  Plant”) in the Badlands, its 250 MMcf/d Pembrook Plant in Permian Midland and its 250 MMcf/d Falcon Plant in Permian Delaware, and also completed a dock rebuild at its LPG export facility in Galena Park.

The fourth quarter of 2019 will be the first full quarter of margin contribution from Grand Prix, the LM4 Plant, the Pembrook Plant, the Falcon Plant, and additional export services capacity at Galena Park.

2019 Financial and Operational Expectations and 2020 Preliminary Growth Capital Outlook

Targa affirms its previously disclosed full year financial and operational outlook for 2019, despite generally lower year-to-date commodity prices versus original assumptions. Through September 30, 2019, the Company spent $1,946.2 million on net growth capital expenditures, including net contributions to investments in unconsolidated affiliates. Targa’s estimated 2019 net growth capital expenditures continues to be approximately $2.4 billion. Based on current assumptions, Targa’s preliminary outlook for 2020 net growth capital expenditures is approximately $1.2 to $1.3 billion. The timing of moving forward with new Permian gas processing plants and fractionation Train 9 in Mont Belvieu is predicated on the Company’s outlook for estimated volume growth and activity levels, which would impact whether the Company is at the lower or higher end of its estimated net growth capital range as a result of the timing of capital spend.

Asset Sales

Targa continues to evaluate and execute asset sales to reduce leverage and focus on its core operations. During the third quarter of 2019, the Company closed on the sale of an equity-method investment for $70.3 million.

The Company has also engaged Jefferies LLC to evaluate the potential divestiture of its Permian crude gathering business, which includes crude gathering and storage assets in both the Permian Midland and Permian Delaware. The potential divestiture is predicated on third party valuations adequately capturing Targa’s forward growth expectations for the assets, and no assurance can be made that a sale will be consummated.

Conference Call

The Company will host a conference call for the investment community at 11:00 a.m. Eastern time (10:00 a.m. Central time) on November 7, 2019 to discuss third quarter 2019 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 https://edge.media-server.com/mmc/p/ih4at2qd or by dialing 877-881-2598. The conference ID number for the dial-in is 4349515. Please dial in ten minutes prior to the scheduled start time. A webcast replay will be available at the link above approximately two hours after the conclusion of the event.

Targa Resources Corp. – Consolidated Financial Results of Operations

Three Months Ended September 30,                     Nine Months Ended September 30,                  
2019     2018     2019 vs. 2018     2019     2018     2019 vs. 2018  
(In millions)  
Revenues:
Sales of commodities $ 1,594.2 $ 2,654.1 $ (1,059.9 ) (40 %) $ 5,254.8 $ 6,981.4 $ (1,726.6 ) (25 %)
Fees from midstream services 308.3 332.3 (24.0 ) (7 %) 942.4 904.9 37.5 4 %
Total revenues 1,902.5 2,986.4 (1,083.9 ) (36 %) 6,197.2 7,886.3 (1,689.1 ) (21 %)
Product purchases 1,328.1 2,383.5 (1,055.4 ) (44 %) 4,415.7 6,229.7 (1,814.0 ) (29 %)
Gross margin (1) 574.4 602.9 (28.5 ) (5 %) 1,781.5 1,656.6 124.9 8 %
Operating expenses 200.2 194.9 5.3 3 % 600.8 538.7 62.1 12 %
Operating margin (1) 374.2 408.0 (33.8 ) (8 %) 1,180.7 1,117.9 62.8 6 %
Depreciation and amortization expense 244.3 206.3 38.0 18 % 718.9 607.1 111.8 18 %
General and administrative expense 69.9 63.2 6.7 11 % 223.5 176.9 46.6 26 %
Other operating (income) expense 18.4 61.8 (43.4 ) (70 %) 21.7 15.7 6.0 38 %
Income (loss) from operations 41.6 76.7 (35.1 ) (46 %) 216.6 318.2 (101.6 ) (32 %)
Interest expense, net (89.1 ) (78.2 ) (10.9 ) (14 %) (241.8 ) (124.2 ) (117.6 ) (95 %)
Equity earnings (loss) 10.0 3.0 7.0 233 % 15.9 6.4 9.5 148 %
Gain (loss) from financing activities (1.4 ) (2.0 ) 0.6 30 %
Gain (loss) from sale of equity-method investment 65.8 65.8 65.8 65.8
Change in contingent considerations (16.6 ) 16.6 100 % (8.8 ) (12.1 ) 3.3 27 %
Income tax (expense) benefit 3.8 3.9 (0.1 ) (3 %) 10.0 (37.7 ) 47.7 127 %
Net income (loss) 32.1 (11.2 ) 43.3 NM 56.3 148.6 (92.3 ) (62 %)
Less: Net income (loss) attributable to noncontrolling interests 79.4 12.5 66.9 NM 152.7 40.4 112.3 278 %
Net income (loss) attributable to Targa Resources Corp. (47.3 ) (23.7 ) (23.6 ) (100 %) (96.4 ) 108.2 (204.6 ) (189 %)
Dividends on Series A Preferred Stock 22.9 22.9 68.8 68.8
Deemed dividends on Series A Preferred Stock 8.4 7.4 1.0 14 % 24.4 21.5 2.9 13 %
Net income (loss) attributable to common shareholders $ (78.6 ) $ (54.0 ) $ (24.6 ) (46 %) $ (189.6 ) $ 17.9 $ (207.5 ) NM
Financial data:
Adjusted EBITDA (1) $ 349.6 $ 347.2 $ 2.4 $ 970.3 $ 958.3 $ 12.0 1 %
Distributable cash flow (1) 229.9 287.2 (57.3 ) (20 %) 619.4 728.5 (109.1 ) (15 %)
Growth capital expenditures (2) 511.3 984.4 (473.1 ) (48 %) 2,203.4 2,230.0 (26.6 ) (1 %)
Maintenance capital expenditures (3) 31.0 33.3 (2.3 ) (7 %) 101.5 80.4 21.1 26 %
(1) Gross margin, operating margin, Adjusted EBITDA, and distributable cash flow are non-GAAP financial measures and are discussed under “Targa Resources Corp. – Non-GAAP Financial Measures.”
(2) Growth capital expenditures, net of contributions from noncontrolling interest, were $1,870.8 million and $1,824.0 million for the nine months ended September 30, 2019 and 2018. Net contributions to investments in unconsolidated affiliates were $75.4 million and $99.9 million for the nine months ended September 30, 2019 and 2018.
(3) Maintenance capital expenditures, net of contributions from noncontrolling interests, were $95.5 million and $78.8 million for the nine months ended September 30, 2019 and 2018.
NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018

The decrease in commodity sales reflects lower NGL, natural gas, and condensate prices ($1,352.5 million), the unfavorable impact of mark-to-market hedges ($102.0 million) and lower petroleum products and condensate volumes ($62.2 million), partially offset by higher NGL, crude marketing and natural gas volumes ($373.3 million), the favorable impact of equity volume hedges ($59.5 million) and higher crude marketing prices ($20.1 million).

The decrease in fees from midstream services is largely due to lower gas gathering fees attributable to the Company’s non-cash take in-kind equity volumes, partially offset by an overall increase in gas gathered volumes. Subsequent to the Company’s January 2018 adoption of ASC 606, Revenue from Contracts with Customers, non-cash take in-kind volumes, which have exposure to commodity prices, received from a customer are presented as a component of fees from midstream services with a corresponding offset to product purchases and have no impact to the Company’s operating margin or gross margin.

The decrease in product purchases reflects decreased NGL, natural gas and condensate prices, partially offset by increases in volumes.

Lower 2019 operating margin and gross margin reflect decreased segment results for Gathering and Processing, offset by increased segment results for Logistics and Marketing. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis. Operating margin and gross margin also include the effect of hedges as discussed in “Review of Segment Performance – Other.”

Depreciation and amortization expense increased primarily due to higher depreciation related to major growth projects placed in service, including additional processing plants and associated infrastructure in the Permian Basin and Grand Prix.

General and administrative expense increased primarily due to higher compensation and benefits costs as a result of increased staffing levels, partially offset by lower professional services and lower contract labor.

During the third quarter of 2019, the Company wrote down certain assets to their recoverable amounts. In the prior year, a loss on sale was recognized associated with the Company’s refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD.

Interest expense, net, increased due to higher average borrowings, partially offset by higher capitalized interest related to the Company’s major growth investments.

The increase in equity earnings is primarily due to higher earnings from GCX.

During the third quarter of 2019, the Company closed on the sale of an equity-method investment for $70.3 million that resulted in the recognition of a gain of $65.8 million.

During 2019, the Permian Acquisition contingent consideration earn-out period ended and resulted in a final payment in May. During 2018, the Company recorded an expense resulting primarily from an increase in fair value of the contingent consideration liability. The fair value change was primarily attributable to a shorter discount period.

The change in income tax benefit is primarily due to a lower annual effective tax rate and higher tax benefits related to share-based awards that vested during the quarter.

Net income attributable to noncontrolling interests was higher in 2019 due to earnings allocated to noncontrolling interest holders in Targa Badlands, Grand Prix and Train 6.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

The decrease in commodity sales reflects lower commodity prices ($2,640.8 million) and lower petroleum products volumes due to the sale of certain petroleum logistics storage and terminaling facilities in the fourth quarter of 2018 ($85.3 million), partially offset by higher NGL, crude marketing and natural gas volumes ($936.4 million) and the favorable impact of hedges ($65.8 million). Higher exports and crude gathering fees resulted in increased fees from midstream services.

The decrease in product purchases reflects decreased NGL, natural gas and condensate prices, partially offset by increases in volumes.

Higher 2019 operating margin and gross margin reflect increased segment results for Logistics and Marketing, offset by decreased segment results for Gathering and Processing. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis. Operating margin and gross margin also include the effect of hedges as discussed in “Review of Segment Performance – Other.”

Depreciation and amortization expense increased primarily due to higher depreciation related to major growth projects placed in service, including additional processing plants and associated infrastructure in the Permian Basin and Grand Prix.

General and administrative expense increased primarily due to higher compensation and benefits costs as a result of increased staffing levels and higher system costs.

Interest expense, net, increased due to higher average borrowings, partially offset by higher capitalized interest related to the Company’s major growth investments. During 2018, the Company recognized non-cash interest income resulting from a decrease in the estimated redemption value of the mandatorily redeemable interests, primarily attributable to the February 2018 amendments to such arrangements.

The increase in equity earnings is primarily due to higher earnings from GCX.

During 2019, the Company closed on the sale of an equity-method investment for $70.3 million that resulted in the recognition of a gain of $65.8 million.

The change in income tax (expense) benefit was primarily due to lower net income before tax, a lower annual effective tax rate and higher tax benefits related to share-based payment awards that vested during the period.

Net income attributable to noncontrolling interests was higher in 2019 due to earnings allocated to noncontrolling interest holders in Targa Badlands, Grand Prix and Train 6.

Review of Segment Performance

The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin and gross margin as important performance measures of the core profitability of its operations. These measures are key components of internal financial reporting and are reviewed for consistency and trend analysis. For a discussion of operating margin and gross margin, see “Targa Resources Corp. ― Non-GAAP Financial Measures ― Operating Margin” and “Targa Resources Corp. ― Non-GAAP Financial Measures ― Gross Margin.” Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation.

The Company operates in two primary segments: (i) Gathering and Processing; and (ii) Logistics and Marketing.

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 (including the Midland and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) 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
September 30,
                    Nine Months Ended
September 30,
   
2019     2018     2019 vs. 2018   2019     2018       2019 vs. 2018  
Gross margin $ 328.8 $ 373.7 $ (44.9 ) (12 %) $ 1,006.1 $ 1,046.3 $ (40.2 ) (4 %)
Operating expenses 120.2 118.4 1.8 2 % 375.2 327.9 47.3 14 %
Operating margin $ 208.6 $ 255.3 $ (46.7 ) (18 %) $ 630.9 $ 718.4 $ (87.5 ) (12 %)
Operating statistics (1):      
Plant natural gas inlet, MMcf/d (2),(3)    
Permian Midland (4)   1,546.7 1,161.7 385.0 33 %   1,438.7 1,100.8 337.9 31 %
Permian Delaware   629.4 470.5 158.9 34 %   552.2 432.5 119.7 28 %
Total Permian   2,176.1 1,632.2 543.9   1,990.9 1,533.3 457.6
   
SouthTX (5)   328.6 364.1 (35.5 ) (10 %)   335.3 397.8 (62.5 ) (16 %)
North Texas   228.2 247.6 (19.4 ) (8 %)   227.6 243.0 (15.4 ) (6 %)
SouthOK (6)   590.8 568.2 22.6 4 %   606.1 549.4 56.7 10 %
WestOK   329.2 353.9 (24.7 ) (7 %)   335.2 350.8 (15.6 ) (4 %)
Total Central   1,476.8 1,533.8 (57.0 )   1,504.2 1,541.0 (36.8 )
   
Badlands (7), (8)   120.8 90.5 30.3 33 %   103.4 83.3 20.1 24 %
Total Field 3,773.7 3,256.5 517.2 3,598.5 3,157.6 440.9
   
Coastal   721.0 783.3 (62.3 ) (8 %)   765.1 724.5 40.6 6 %
   
Total 4,494.7 4,039.8 454.9 11 % 4,363.6 3,882.1 481.5 12 %
NGL production, MBbl/d (3)
Permian Midland (4) 216.5 152.2 64.3 42 % 199.8 148.0 51.8 35 %
Permian Delaware 82.3 58.9 23.4 40 % 71.4 51.6 19.8 38 %
Total Permian   298.8 211.1 87.7   271.2 199.6 71.6
SouthTX (5) 41.5 49.0 (7.5 ) (15 %) 44.0 52.5 (8.5 ) (16 %)
North Texas 27.3 29.6 (2.3 ) (8 %) 26.9 28.1 (1.2 ) (4 %)
SouthOK (6) 69.5 61.2 8.3 14 % 65.4 53.8 11.6 22 %
WestOK 19.2 20.7 (1.5 ) (7 %) 22.4 19.9 2.5 13 %
Total Central   157.5 160.5 (3.0 )   158.7 154.3 4.4
Badlands (8) 14.0 10.5 3.5 33 % 12.2 10.5 1.7 16 %
Total Field 470.3 382.1 88.2 442.1 364.4 77.7
Coastal 45.4 47.3 (1.9 ) (4 %) 47.0 42.8 4.2 10 %
Total 515.7 429.4 86.3 20 % 489.1 407.2 81.9 20 %
Crude oil gathered, Badlands, MBbl/d 164.3 161.7 2.6 2 % 167.0 139.9 27.1 19 %
Crude oil gathered, Permian, MBbl/d 95.2 75.1 20.1 27 % 86.1 63.8 22.3 35 %
Natural gas sales, BBtu/d (3) 2,056.6 1,817.6 239.0 13 % 2,011.2 1,821.1 190.1 10 %
NGL sales, MBbl/d 398.0 329.6 68.4 21 % 382.4 311.3 71.1 23 %
Condensate sales, MBbl/d 11.0 12.6 (1.6 ) (13 %) 12.2 12.8 (0.6 ) (5 %)
Average realized prices (9):      
Natural gas, $/MMBtu 1.02 1.93 (0.91 ) (47 %) 1.19 2.03 (0.84 ) (41 %)
NGL, $/gal 0.27 0.75 (0.48 ) (64 %) 0.35 0.67 (0.32 ) (48 %)
Condensate, $/Bbl 50.94 58.31 (7.37 ) (13 %) 49.79 58.49 (8.70 ) (15 %)
(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.
(2) Plant natural gas inlet represents the Company’s undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than Badlands.
(3) Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.
(4) Permian Midland includes operations in WestTX, of which the Company owns 72.8%, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in the Company’s reported financials.
(5) SouthTX includes the Raptor Plant, of which the Company owns a 50% interest through the Carnero Joint Venture. SouthTX also includes the Silver Oak II Plant, of which the Company owned a 100% interest until it was contributed to the Carnero Joint Venture in May 2018. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(6) SouthOK includes the Centrahoma Joint Venture, of which the Company owns 60%, and other plants that are owned 100% by us. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(7) Badlands natural gas inlet represents the total wellhead gathered volume.
(8) As of April 3, 2019, Targa owns 55% of Targa Badlands through a joint venture (the “Badlands Joint Venture”), prior to which the Company owned a 100% interest. The Badlands Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(9) Average realized prices exclude the impact of hedging activities presented in Other.

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018

The decrease in gross margin was primarily due to lower commodity prices, partially offset by higher Permian and Badlands volumes. The impact of lower commodity prices in 2019 excludes the third quarter realized gain from the Company’s hedging activities presented in Other. NGL production, NGL sales and natural gas sales increased primarily due to higher inlet volumes and increased NGL recoveries. In the Permian, natural gas gathered volumes and NGL production increased due to incremental processing capacity available with the commencement of operations at the Johnson Plant in the fourth quarter of 2018, the Hopson Plant in the second quarter of 2019 and the Pembrook Plant in the third quarter of 2019, while total crude oil gathered volumes increased due to production from new wells. In the Badlands, natural gas gathered volumes and NGL production increased due to incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019, while total crude oil gathered volumes increased due to production from new wells.

Operating expenses were relatively flat with increased operating expenses in the Permian, due to gas plant and system expansions, partially offset by reductions in other regions.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

The decrease in gross margin was primarily due to lower commodity prices, partially offset by higher Permian and Badlands volumes. The impact of lower commodity prices in 2019 excludes the realized gain from the Company’s hedging activities presented in Other. NGL production, NGL sales and natural gas sales increased primarily due to higher inlet volumes and increased NGL recoveries. In the Permian, natural gas gathered volumes and NGL production increased due to incremental processing capacity available with the commencement of operations at the Johnson Plant in the fourth quarter of 2018, the Hopson Plant in the second quarter of 2019 and the Pembrook Plant in the third quarter of 2019. In the Badlands, natural gas gathered volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. Total crude oil gathered volumes increased in both the Permian region and the Badlands due to production from new wells.

The increase in operating expenses was primarily driven by gas plant and system expansions in the Permian region and the Badlands. Operating expenses in other areas were relatively flat.

Logistics and Marketing Segment

The Logistics and Marketing segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling and marketing of NGLs and NGL products, including services to liquefied petroleum gas (“LPG”) exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of the Company’s other businesses. The Logistics and Marketing segment also includes Grand Prix, which integrates the Company’s gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with the Company’s downstream facilities in Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by the Company’s Gathering and Processing segment and, except for pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

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

Three Months Ended
September 30,
        Nine Months Ended
September 30,
   
  2019     2018     2019 vs. 2018     2019     2018     2019 vs. 2018  
(In millions)  
Gross margin $ 310.4 $ 249.4 $ 61.0 24 % $ 792.4 $ 653.1 $ 139.3 21 %
Operating expenses 81.5 75.9 5.6 7 % 227.4 211.4 16.0 8 %
Operating margin $ 228.9 $ 173.5 $ 55.4 32 % $ 565.0 $ 441.7 $ 123.3 28 %
Operating statistics MBbl/d (1):            
Fractionation volumes (2) 508.8 454.5 54.3 12 % 492.8 419.0 73.8 18 %
Export volumes (3) 239.2 208.2 31.0 15 % 228.1 200.2 27.9 14 %
Pipeline throughput (4) 131.8 131.8 44.4 44.4
NGL sales 672.1 555.7 116.4 21 % 620.9 526.7 94.2 18 %
Average realized prices:
NGL realized price, $/gal $ 0.43 $ 0.88 $ (0.45 ) (51 %) $ 0.50 $ 0.80 $ (0.30 ) (38 %)
(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 period and the denominator is the number of calendar days during the period.
(2) Fractionation contracts include pricing terms composed of base fees and fuel and power components that 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. Fractionation volumes for 2019 reflect volumes delivered and fractionated, whereas fractionation volumes for 2018 reflect volumes delivered and settled under fractionation contracts.
(3) Export volumes represent the quantity of NGL products delivered to third-party customers at the Company’s Galena Park Marine Terminal that are destined for international markets.
(4) Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu.

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018

Logistics and Marketing gross margin increased due to higher NGL transportation, fractionation and services margin, higher marketing margin, and higher LPG export margin, partially offset by lower terminaling and storage throughput. NGL transportation, fractionation and services margin increased due to volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes as a result of the commencement of operations of Train 6 in the second quarter of 2019. Fractionation and services margin was unfavorably impacted by fewer short-term high fee fractionation contracts in the third quarter of 2019 compared to the same period last year, and by a planned maintenance turnaround of the Company’s Cedar Bayou fractionator. Marketing margin increased due to optimization of gas and liquids arrangements. LPG export margin increased due to higher volumes. Terminaling and storage throughput decreased due to the sale of certain petroleum logistics terminals in the fourth quarter of 2018.

Operating expenses increased due to higher maintenance, higher fuel and power costs that are largely passed through to customers, and higher compensation and benefits primarily attributable to Grand Prix and Train 6 operations, partially offset by the sale of certain petroleum logistics terminals in the fourth quarter of 2018.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

Logistics and Marketing gross margin increased due to higher NGL transportation, fractionation and services margin, higher LPG export margin, and higher marketing margin, partially offset by lower terminaling and storage throughput. NGL transportation, fractionation and services margin increased due to volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes as a result of the commencement of operations of Train 6 in the second quarter of 2019. Fractionation and services margin was unfavorably impacted by fewer short-term high fee fractionation contracts in the third quarter of 2019 compared to the same period last year, and by a planned maintenance turnaround of the Company’s Cedar Bayou fractionator. LPG export margin increased due to higher volumes. Marketing margin increased due to optimization of gas and liquids arrangements. Terminaling and storage throughput decreased due to the sale of certain petroleum logistics terminals in the fourth quarter of 2018.

Operating expenses increased due to higher fuel and power costs that are largely passed through to customers, higher maintenance, and higher compensation and benefits and higher taxes primarily attributable to Grand Prix and Train 6 operations, partially offset by the sale of certain petroleum logistics terminals in the fourth quarter of 2018.

Other

    Three Months Ended September 30,             Nine Months Ended September 30,          
    2019     2018     2019 vs. 2018     2019     2018     2019 vs. 2018  
    (In millions)  
Gross margin $ (63.3 ) $ (20.8 ) $ (42.5 ) $ (15.2 ) $ (42.2 ) $ 27.0
Operating margin $ (63.3 ) $ (20.8 ) $ (42.5 ) $ (15.2 ) $ (42.2 ) $ 27.0

Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin. The primary purpose of the Company’s commodity risk management activities is to mitigate a portion of the impact of commodity prices on the Company’s operating cash flow. The Company has entered into derivative instruments to hedge the commodity price associated with a portion of the Company’s expected natural gas, NGL and condensate equity volumes in the Company’s Gathering and Processing operations that result from percent of proceeds/liquids processing arrangements. Because the Company is essentially forward-selling a portion of the Company’s future plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

The Company has also entered into swaps and basis swaps that do not qualify for hedge accounting treatment. The mark-to-market gains/losses related to these derivative instruments represent unrealized, non-cash changes in the fair value of the instruments. For the three and nine months ended September 30, 2019, the unrealized mark-to-market losses are primarily attributable to unfavorable movements in natural gas forward basis prices and will be more than offset by locked-in gains to be realized in future periods from the underlying transportation arrangements.

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

    Three Months Ended September 30, 2019     Three Months Ended September 30, 2018  
    (In millions, except volumetric data and price amounts)  
    Volume
Settled
    Price
Spread (1)
    Gain
(Loss)
    Volume
Settled
    Price
Spread (1)
    Gain
(Loss)
 
Natural gas (BBtu) 18.8 $ 1.07 $ 20.1 15.7 $ 0.82 $ 12.9
NGL (MMgal) 110.0 0.17 18.5 99.0 (0.27 ) (26.4 )
Crude oil (MBbl) 0.4 (1.76 ) (0.7 ) 0.5 (15.81 ) (8.1 )
Non-hedge accounting (2) (101.2 ) 0.8
$ (63.3 ) $ (20.8 )
    Nine Months Ended September 30, 2019     Nine Months Ended September 30, 2018  
    (In millions, except volumetric data and price amounts)  
    Volume
Settled
    Price
Spread (1)
    Gain
(Loss)
    Volume
Settled
    Price
Spread (1)
    Gain
(Loss)
 
Natural gas (BBtu) 47.0 $ 1.29 $ 60.6 48.6 $ 0.74 $ 35.8
NGL (MMgal) 252.1 0.11 27.9 286.3 (0.17 ) (49.7 )
Crude oil (MBbl) 1.1 (2.28 ) (2.6 ) 1.5 (13.10 ) (20.0 )
Non-hedge accounting (2) (101.1 ) (8.3 )
$ (15.2 ) $ (42.2 )
(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.

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. The Company 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, transporting and selling natural gas; transporting, storing, fractionating, treating and selling NGLs and NGL products, including services to LPG exporters; and gathering, storing, terminaling and selling crude oil.

For more information, please visit the Company’s website at 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) attributable to TRC before interest, income taxes, depreciation and amortization, and other items that the Company believes should be adjusted consistent with the Company’s core operating performance. The adjusting items are detailed in the Adjusted EBITDA reconciliation table and its footnotes. 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 TRC. 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, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs).

Distributable cash flow is a significant performance metric used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by it (prior to the establishment of any retained cash reserves by the Company’s 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 the Company’s decision-making processes.

The following table presents a reconciliation of net income attributable to TRC to Adjusted EBITDA and Distributable Cash Flow for the periods indicated:

Three Months Ended September 30,   Nine Months Ended September 30,  
2019     2018     2019     2018  
(In millions)  
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA and Distributable Cash Flow  
Net income (loss) attributable to TRC $ (47.3 ) $ (23.7 ) $ (96.4 ) $ 108.2
Income attributable to TRP preferred limited partners 2.8 2.8 8.4 8.4
Interest (income) expense, net (1) 89.1 78.2 241.8 124.2
Income tax expense (benefit) (3.8 ) (3.9 ) (10.0 ) 37.7
Depreciation and amortization expense 244.3 206.3 718.9 607.1
(Gain) loss on sale or disposition of assets 0.5 61.1 3.6 14.3
Write-down of assets 17.9 17.9
(Gain) loss from sale of equity-method investment (65.8 ) (65.8 )
(Gain) loss from financing activities (2) 1.4 2.0
Equity (earnings) loss (10.0 ) (3.0 ) (15.9 ) (6.4 )
Distributions from unconsolidated affiliates and preferred partner interests, net 14.0 7.5 33.4 21.4
Change in contingent considerations 16.6 8.8 12.1
Compensation on equity grants 16.1 13.8 49.0 40.7
Risk management activities 100.7 (0.8 ) 100.8 8.3
Noncontrolling interests adjustments (3) (8.9 ) (7.7 ) (25.6 ) (19.7 )
TRC Adjusted EBITDA (4)   $   349.6     $   347.2   $   970.3   $   958.3  
Distributions to TRP preferred limited partners (2.8 ) (2.8 ) (8.4 ) (8.4 )
Splitter Agreement (5) 43.1 43.1
Interest expense on debt obligations (6) (88.0 ) (67.5 ) (247.0 ) (185.7 )
Maintenance capital expenditures (31.0 ) (33.3 ) (101.5 ) (80.4 )
Noncontrolling interests adjustments of maintenance capital expenditures 2.1 0.5 6.0 1.6
Distributable Cash Flow   $   229.9     $   287.2   $   619.4     $   728.5  
(1) Includes the change in estimated redemption value of the mandatorily redeemable preferred interests.
(2) Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments.
(3) Noncontrolling interest portion of depreciation and amortization expense.
(4) Beginning in the second quarter of 2019, the Company revised the Company’s reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA to exclude the Splitter Agreement adjustment previously included in the comparative periods presented herein. For all comparative periods presented, the Company’s Adjusted EBITDA measure previously included the Splitter Agreement adjustment, which represented the recognition of the annual cash payment received under the condensate splitter agreement ratably over four quarters. The effect of these revisions reduced TRC’s Adjusted EBITDA by $10.8 million and $32.3 million for the three and nine months ended September 30, 2018. There was no impact to Distributable Cash Flow.
(5) In Distributable Cash Flow, Splitter Agreement represents the annual cash payment in the period received.
(6) Excludes amortization of interest expense.


Gross Margin

The Company defines gross margin as revenues less product 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 less producer payments and other natural gas and crude oil purchases; and
  • service fees related to natural gas and crude oil gathering, treating and processing.

Logistics and Marketing segment gross margin consists primarily of:

  • service fees (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 the Company’s equity volumes 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 the Company’s 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 (loss) attributable to TRC. 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 with 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 net income of the Company to operating margin and gross margin for the periods indicated:

Three Months Ended September 30,   Nine Months Ended September 30,  
2019     2018     2019     2018  
(In millions)  
Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin  
Net income (loss) attributable to TRC $ (47.3 ) $ (23.7 ) $ (96.4 ) $ 108.2
Net income (loss) attributable to noncontrolling interests 79.4 12.5 152.7 40.4
Net income (loss) 32.1 (11.2 ) 56.3 148.6
Depreciation and amortization expense 244.3 206.3 718.9 607.1
General and administrative expense 69.9 63.2 223.5 176.9
Interest (income) expense, net 89.1 78.2 241.8 124.2
Income tax expense (benefit) (3.8 ) (3.9 ) (10.0 ) 37.7
(Gain) loss on sale or disposition of assets 0.5 61.1 3.6 14.3
Write-down of assets 17.9 17.9
(Gain) loss from sale of equity-method investment (65.8 ) (65.8 )
(Gain) loss from financing activities 1.4 2.0
Change in contingent considerations 16.6 8.8 12.1
Other, net (10.0 ) (2.3 ) (15.7 ) (5.0 )
Operating margin 374.2 408.0 1,180.7 1,117.9
Operating expenses 200.2 194.9 600.8 538.7
Gross margin   $   574.4     $   602.9     $   1,781.5     $   1,656.6  

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 Report on Form 10-K for the year ended December 31, 2018, and any subsequently filed 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 the Company’s investor relations department by email at [email protected] or by phone at (713) 584-1133.

Sanjay Lad
Senior Director, Finance & Investor Relations

Jennifer Kneale
Chief Financial Officer



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