February 20, 2019 - 4:05 PM EST
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Energy Transfer Reports Fourth Quarter 2018 Results with Record Performance and Continued Growth

DALLAS

  • Net income attributable to partners of $617 million, reflecting an increase over previous periods primarily due to the impact of the Merger.
  • Record Adjusted EBITDA of $2.67 billion, up 29 percent from the fourth quarter of 2017.
  • Record Distributable Cash Flow attributable to partners of $1.52 billion, up 29 percent from the fourth quarter of 2017.
  • Distribution coverage ratio of 1.90x, yielding excess coverage of $716 million of Distributable Cash Flow attributable to partners in excess of distributions.
  • Reaffirms 2019 outlook for Adjusted EBITDA of $10.6 billion to $10.8 billion and capital expenditures of approximately $5 billion.

Energy Transfer LP (NYSE:ET) (“ET” or the “Partnership”) today reported financial results for the quarter and year ended December 31, 2018.

ET reported net income attributable to partners for the three months ended December 31, 2018 of $617 million, an increase of $366 million compared to the three months ended December 31, 2017. For the prior period, net income attributable to partners continues to reflect only the amount of net income attributable to the legacy ETE partners prior to the Merger, as discussed below.

Adjusted EBITDA for the three months ended December 31, 2018 was $2.67 billion, an increase of $592 million compared to the three months ended December 31, 2017. Results were supported by increases in all of the Partnership’s core operations, with record operating performance in ET’s NGL, interstate and intrastate businesses.

On a pro forma basis for the Merger, Distributable Cash Flow attributable to partners, as adjusted, for the three months ended December 31, 2018 was a record $1.52 billion, an increase of $338 million compared to the three months ended December 31, 2017. The increase was primarily due to the increase in Adjusted EBITDA.

Key accomplishments and current developments:

Strategic

  • ET and Energy Transfer Operating, L.P. (“ETO”, formerly Energy Transfer Partners, L.P. or “ETP”) completed a simplification merger transaction on October 19, 2018 (the “Merger”) whereby the publicly held common units of ETP were exchanged for 1.28 common units of ET. Consequently, the former common unitholders of ETP, along with the existing common unitholders of ET, now comprise the current common unitholders of ET.

Operational

  • Frac VI, a 150,000 barrel per day fractionator at Mont Belvieu, was placed in service in February 2019.
  • Bakken Pipeline completed a successful open season in January 2019 to bring the current system capacity to 570,000 barrels per day.
  • The North Texas natural gas pipeline 160,000 MMBtu per day expansion was placed in service in January 2019.
  • Mariner East 2, a 350-mile NGL pipeline, was placed into service for both intrastate and interstate service in December 2018.
  • Construction of a 150,000 barrel per day fractionator (Frac VII) at Mont Belvieu and Lone Star Express 352-mile NGL pipeline expansion were announced in November 2018.

Financial

  • In January 2019, ET announced a quarterly distribution of $0.305 per unit ($1.220 annualized) on ET common units for the quarter ended December 31, 2018.
  • In January 2019, ETO issued an aggregate $4.00 billion principal amount of senior notes and used the net proceeds to repay in full ET’s outstanding senior secured term loan, redeem certain outstanding senior notes at maturity, repay a portion of the borrowings outstanding under ET’s revolving credit facility and for general partnership purposes.
  • As of December 31, 2018, ETO’s $6.00 billion revolving credit facilities had an aggregate $2.24 billion of available capacity, and ETO’s leverage ratio, as defined by its credit agreement, was 3.38x.

Energy Transfer benefits from a portfolio of assets with exceptional product and geographic diversity. The Partnership’s multiple segments generate high-quality, balanced earnings with no single segment contributing more than a quarter of the Partnership’s consolidated Adjusted EBITDA in 2018. The great majority of the Partnership’s segment margins are fee-based and therefore have limited commodity price sensitivity.

Conference call information:

The Partnership has scheduled a conference call for 8:00 a.m. Central Time, Thursday, February 21, 2019 to discuss its fourth quarter 2018 results. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com and will also be available for replay on the Partnership’s website for a limited time.

Subsequent to the Merger, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in the limited and general partner interests in Sunoco LP and USA Compression Partners LP (“USAC”), as well as its ownership of Lake Charles LNG Company, LLC (“Lake Charles LNG”).

Energy Transfer LP (NYSE: ET) owns and operates one of the largest and most diversified portfolios of energy assets in the United States, with a strategic footprint in all of the major U.S. production basins, ET is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (NGL) and refined product transportation and terminalling assets; NGL fractionation; and various acquisition and marketing assets. ET, through its ownership of Energy Transfer Operating, L.P., formerly known as Energy Transfer Partners, L.P., also owns the general partner interests, the incentive distribution rights and 28.5 million common units of Sunoco LP (NYSE: SUN), and the general partner interests and 39.7 million common units of USA Compression Partners, LP (NYSE: USAC). For more information, visit the Energy Transfer LP website at www.energytransfer.com.

Sunoco LP (NYSE: SUN) is a master limited partnership that distributes motor fuel to approximately 10,000 convenience stores, independent dealers, commercial customers and distributors located in more than 30 states. SUN’s general partner is owned by Energy Transfer Operating, L.P., a subsidiary of Energy Transfer LP (NYSE: ET). For more information, visit the Sunoco LP website at www.sunocolp.com.

USA Compression Partners, LP (NYSE: USAC) is a growth-oriented Delaware limited partnership that is one of the nation’s largest independent providers of compression services in terms of total compression fleet horsepower. USAC partners with a broad customer base composed of producers, processors, gatherers and transporters of natural gas and crude oil. USAC focuses on providing compression services to infrastructure applications primarily in high-volume gathering systems, processing facilities and transportation applications. For more information, visit the USAC website at www.usacompression.com.

Forward-Looking Statements

This news release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnership’s Annual Report on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events.

The information contained in this press release is available on our website at www.energytransfer.com.

 

ENERGY TRANSFER LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)
(unaudited)
   

December 31,
2018

December 31,
2017

ASSETS
Current assets $ 6,750 $ 10,683
 
Property, plant and equipment, net 66,963 61,088
 
Advances to and investments in unconsolidated affiliates 2,642 2,705
Other non-current assets, net 1,006 886
Intangible assets, net 6,000 6,116
Goodwill 4,885   4,768  
Total assets $ 88,246   $ 86,246  
LIABILITIES AND EQUITY
Current liabilities $ 9,310 $ 7,897
 
Long-term debt, less current maturities 43,373 43,671
Non-current derivative liabilities 104 145
Deferred income taxes 2,926 3,315
Other non-current liabilities 1,184 1,217
 
Commitments and contingencies
Redeemable noncontrolling interests 499 21
 
Equity:
Total partners’ capital (deficit) 20,559 (1,196 )
Noncontrolling interest 10,291   31,176  
Total equity 30,850   29,980  
Total liabilities and equity $ 88,246   $ 86,246  
 
   

ENERGY TRANSFER LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit data)
(unaudited)
 
Three Months Ended
December 31,
Year Ended
December 31,
2018   2017 2018   2017
REVENUES $ 13,573 $ 11,451 $ 54,087 $ 40,523
COSTS AND EXPENSES:
Cost of products sold 9,977 8,721 41,658 30,966
Operating expenses 809 704 3,089 2,644
Depreciation, depletion and amortization 750 677 2,859 2,554
Selling, general and administrative 187 119 702 599
Impairment losses 431   940   431   1,039  
Total costs and expenses 12,154   11,161   48,739   37,802  
OPERATING INCOME 1,419 290 5,348 2,721
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized (544 ) (482 ) (2,055 ) (1,922 )
Equity in earnings (losses) of unconsolidated affiliates 86 (84 ) 344 144
Impairment of investment in unconsolidated affiliate (313 ) (313 )
Losses on extinguishments of debt (6 ) (64 ) (112 ) (89 )
Gains (losses) on interest rate derivatives (70 ) (9 ) 47 (37 )
Other, net (35 ) 73   62   206  
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) 850 (589 ) 3,634 710
Income tax expense (benefit) from continuing operations (2 ) (1,747 ) 4   (1,833 )
INCOME FROM CONTINUING OPERATIONS 852 1,158 3,630 2,543
Income (loss) from discontinued operations, net of income taxes   10   (265 ) (177 )
NET INCOME 852 1,168 3,365 2,366
Less: Net income attributable to noncontrolling interest 220 917 1,632 1,412
Less: Net income attributable to redeemable noncontrolling interests 15     39    
NET INCOME ATTRIBUTABLE TO PARTNERS 617 251 1,694 954
Convertible Unitholders’ interest in income 12 33 37
General Partner’s interest in net income     3   2  
Limited Partners’ interest in net income $ 617   $ 239   $ 1,658   $ 915  
NET INCOME PER LIMITED PARTNER UNIT:
Basic $ 0.26 $ 0.22 $ 1.16 $ 0.85
Diluted $ 0.26 $ 0.22 $ 1.15 $ 0.83
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING:
Basic 2,332.1 1,079.2 1,423.8 1,078.2
Diluted 2,339.4 1,151.5 1,461.4 1,150.8
 
   

ENERGY TRANSFER LP AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION

(Dollars and units in millions)
(unaudited)
 
Three Months Ended
December 31,
Year Ended
December 31,
2018   2017 2018   2017
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a) (b):
Net income $ 852 $ 1,168 $ 3,365 $ 2,366
(Income) loss from discontinued operations (10 ) 265 177
Interest expense, net 544 482 2,055 1,922
Impairment losses 431 940 431 1,039
Income tax expense (benefit) from continuing operations (2 ) (1,747 ) 4 (1,833 )
Depreciation, depletion and amortization 750 677 2,859 2,554
Non-cash compensation expense 23 23 105 99
(Gains) losses on interest rate derivatives 70 9 (47 ) 37
Unrealized (gains) losses on commodity risk management activities (244 ) (37 ) 11 (59 )
Losses on extinguishments of debt 6 64 112 89
Inventory valuation adjustments 135 (16 ) 85 (24 )
Impairment of investment in an unconsolidated affiliate 313 313
Equity in (earnings) losses of unconsolidated affiliates (86 ) 84 (344 ) (144 )
Adjusted EBITDA related to unconsolidated affiliates 152 162 655 716
Adjusted EBITDA from discontinued operations 44 (25 ) 223
Other, net 38   (79 ) (21 ) (155 )
Adjusted EBITDA (consolidated) 2,669 2,077 9,510 7,320
Adjusted EBITDA related to unconsolidated affiliates (152 ) (162 ) (655 ) (716 )
Distributable Cash Flow from unconsolidated affiliates 95 102 407 431
Interest expense, net (544 ) (497 ) (2,057 ) (1,958 )
Subsidiary preferred unitholders’ distributions (54 ) (12 ) (170 ) (12 )
Current income tax expense (7 ) (10 ) (472 ) (39 )
Transaction-related income taxes 470
Maintenance capital expenditures (137 ) (157 ) (510 ) (479 )
Other, net 19   5   49   67  
Distributable Cash Flow (consolidated) 1,889 1,346 6,572 4,614
Distributable Cash Flow attributable to Sunoco LP (100%) (115 ) (89 ) (446 ) (449 )
Distributions from Sunoco LP 43 68 166 259
Distributable Cash Flow attributable to USAC (100%) (55 ) (148 )
Distributions from USAC 21 73
Distributable Cash Flow attributable to PennTex Midstream Partners, LP (“PennTex”) (100%) (c) (19 )
Distributions from PennTex to ETO (c) 8
Distributable Cash Flow attributable to noncontrolling interest in other non-wholly-owned consolidated subsidiaries (294 ) (151 ) (874 ) (350 )
Distributable Cash Flow attributable to the partners of ET – pro forma for the Merger (a) 1,489 1,174 5,343 4,063
Transaction-related expenses 27   4   52   57  
Distributable Cash Flow attributable to the partners of ET, as adjusted – pro forma for the Merger (a) $ 1,516   $ 1,178   $ 5,395   $ 4,120  
 
   
Three Months Ended
December 31,
Year Ended
December 31,
2018   2017 2018   2017
Distributions to partners – pro forma for the Merger (a):
Limited Partners (d) $ 799 $ 708 $ 3,104 $ 2,669
General Partner 1   1   4   4
Total distributions to be paid to partners $ 800   $ 709   $ 3,108   $ 2,673
Common Units outstanding – end of period – pro forma for the Merger (a) 2,619.4   2,532.5   2,619.4   2,532.5
Distribution coverage ratio – pro forma for the Merger (a)(b) 1.90x 1.66x 1.74x 1.54x
 

(a) The closing of the Merger (as discussed above) has impacted the Partnership’s calculation of Distributable Cash Flow attributable to partners, as well as the number of ET Common Units outstanding and the amount of distributions to be paid to partners. In order to provide information on a comparable basis for pre-Merger and post-Merger periods, the Partnership has included certain pro forma information.

Pro forma Distributable Cash Flow attributable to partners reflects the following merger related impacts:

  • ETO is reflected as a wholly-owned subsidiary and pro forma Distributable Cash Flow attributable to partners reflects ETO’s consolidated Distributable Cash Flow (less certain other adjustments, as follows).
  • Distributions from Sunoco LP and USAC include distributions to both ET and ETO.
  • Distributions from PennTex are separately included in Distributable Cash Flow attributable to partners.
  • Distributable Cash Flow attributable to noncontrolling interest in our other non-wholly-owned subsidiaries is subtracted from consolidated Distributable Cash Flow to calculate Distributable Cash Flow attributable to partners.

Pro forma distributions to partners include actual distributions to legacy ET partners, as well as pro forma distributions to legacy ETO partners. Pro forma distributions to ETO partners are calculated assuming (i) historical ETO common units converted under the terms of the Merger and (ii) distributions on such converted common units were paid at the historical rate paid on ET Common Units.

Pro forma Common Units outstanding include actual Common Units outstanding, in addition to Common Units assumed to be issued in the Merger, which are based on historical ETO common units converted under the terms of the Merger.

For the year ended December 31, 2017, the calculation of Distributable Cash Flow and the amounts reflected for distributions to partners and common units outstanding also reflect the pro forma impacts of the Sunoco Logistics Merger as though the merger had occurred on January 1, 2017.

(b) Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio are non-GAAP financial measures used by industry analysts, investors, lenders, and rating agencies to assess the financial performance and the operating results of ET’s fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities, or other GAAP measures.

There are material limitations to using measures such as Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio, including the difficulty associated with using either as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP, such as segment margin, operating income, net income, and cash flow from operating activities.

Definition of Adjusted EBITDA

We define Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on our proportionate ownership.

Adjusted EBITDA is used by management to determine our operating performance and, along with other financial and volumetric data, as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.

Definition of Distributable Cash Flow

We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and deferred income taxes. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investee’s distributable cash flow.

Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.

On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ET’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among our subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:

  • For subsidiaries with publicly traded equity interests, other than ETO, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to our partners includes distributions to be received by the parent company with respect to the periods presented.
  • For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiaries, but Distributable Cash Flow attributable to partners reflects only the amount of Distributable Cash Flow of such subsidiaries that is attributable to our ownership interest.

For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded.

Definition of Distribution Coverage Ratio

Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to partners, as adjusted, divided by distributions expected to be paid to the partners of ET in respect of such period.

(c) Beginning with the second quarter of 2017, PennTex became a wholly-owned subsidiary of ETO. The amounts reflected above for PennTex relate only to the first quarter of 2017, and no distributable cash flow has been attributed to noncontrolling interests in PennTex subsequent to March 31, 2017.

(d) Includes distributions to unitholders who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units and reinvest those distributions in ETE Series A convertible preferred units representing limited partner interests in the Partnership. The quarter ended March 31, 2018 was the final quarter of participation in the plan.

 
ENERGY TRANSFER LP AND SUBSIDIARIES
SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
 

As a result of the Merger in October 2018, our reportable segments were reevaluated and currently reflect the following segments.

 
Three Months Ended
December 31,
2018   2017
Segment Adjusted EBITDA:
Intrastate transportation and storage $ 306 $ 146
Interstate transportation and storage 479 342
Midstream 402 393
NGL and refined products transportation and services 569 433
Crude oil transportation and services 636 544
Investment in Sunoco LP 180 158
Investment in USAC 104
All other (7 ) 61
Total Segment Adjusted EBITDA $ 2,669   $ 2,077

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment Margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment Margin is similar to the GAAP measure of gross margin, except that Segment Margin excludes charges for depreciation, depletion and amortization.

In addition, for certain segments, the sections below include information on the components of Segment Margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of Segment Margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of Segment Margin are calculated consistent with the calculation of Segment Margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

Following is a reconciliation of Segment Margin to operating income, as reported in the Partnership’s consolidated statements of operations:

  Three Months Ended
December 31,
2018   2017
Segment Margin:
Intrastate transportation and storage $ 350 $ 205
Interstate transportation and storage 495 317
Midstream 609 568
NGL and refined products transportation and services 840 582
Crude oil transportation and services 939 683
Investment in Sunoco LP 183 277
Investment in USAC 149
All other 45 102
Intersegment eliminations (14 ) (4 )
Total segment margin 3,596 2,730
 
Less:
Operating expenses 809 704
Depreciation, depletion and amortization 750 677
Selling, general and administrative 187 119
Impairment losses 431   940  
Operating income $ 1,419   $ 290  
 

Intrastate Transportation and Storage

 
Three Months Ended
December 31,
2018   2017
Natural gas transported (BBtu/d) 11,708 8,944
Revenues $ 1,127 $ 741
Cost of products sold 777   536  
Segment margin 350 205
Unrealized (gains) losses on commodity risk management activities 5 (21 )
Operating expenses, excluding non-cash compensation expense (48 ) (44 )
Selling, general and administrative expenses, excluding non-cash compensation expense (7 ) (5 )
Adjusted EBITDA related to unconsolidated affiliates 6   11  
Segment Adjusted EBITDA $ 306   $ 146  

Transported volumes increased primarily due to favorable market pricing spreads, as well as the impact of reflecting Regency Intrastate Gas LP (“RIGS”) as a consolidated subsidiary. RIGS was previously reflected as an unconsolidated affiliate until ETO acquired the remaining interest in April 2018.

Segment Adjusted EBITDA. For the three months ended December 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:

  • an increase of $154 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; and
  • a net increase of $13 million due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, retained fuel revenues, operating expenses, and selling, general and administrative expenses of $24 million, $2 million, $5 million and $2 million, respectively, and a decrease of $6 million in Adjusted EBITDA related to unconsolidated affiliates; partially offset by
  • a decrease of $7 million in realized storage margin primarily due to lower realized derivative gains; and
  • a decrease of $2 million in transportation fees, excluding the impact of consolidating RIGS as discussed above, primarily due to a non-recurring adjustment to a transportation services agreement, partially offset by Red Bluff Express coming online and new contracts.
 

Interstate Transportation and Storage

 
Three Months Ended
December 31,
2018   2017
Natural gas transported (BBtu/d) 11,062 7,185
Natural gas sold (BBtu/d) 18 18
Revenues $ 495 $ 317
Operating expenses, excluding non-cash compensation, amortization and accretion expenses (120 ) (80 )
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (8 ) (7 )
Adjusted EBITDA related to unconsolidated affiliates 118 115
Other (6 ) (3 )
Segment Adjusted EBITDA $ 479   $ 342  

Transported volumes reflected an increase of 2,223 BBtu/d as a result of the initiation of service on the Rover pipeline; increases of 506 BBtu/d and 475 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to increased utilization of higher contracted capacity; an increase of 309 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale; and an increase of 264 BBtu/d on the Transwestern pipeline as a result of favorable market opportunities in the West, midcontinent, and Waha areas from the Permian supply basin.

Segment Adjusted EBITDA. For the three months ended December 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:

  • an increase of $112 million associated with the Rover pipeline with increases of $149 million in revenues, $35 million in net operating expenses and $2 million in selling, general and administrative expenses;
  • an aggregate increase of $29 million in revenues, excluding the incremental revenue related to the Rover pipeline discussed above, primarily due to capacity sold at higher rates on the Transwestern, Panhandle and Trunkline pipelines;
  • an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates primarily related to higher sales of capacity on Citrus; and
  • a decrease of $1 million in selling, general and administrative expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to a reduction in insurance reserves; partially offset by
  • an increase of $5 million in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to system gas expenses and increases in maintenance project costs due to scope and level of activity.
 

Midstream

 
Three Months Ended
December 31,
2018   2017
Gathered volumes (BBtu/d) 12,827 11,525
NGLs produced (MBbls/d) 558 505
Equity NGLs (MBbls/d) 25 27
Revenues $ 1,781 $ 1,926
Cost of products sold 1,172   1,358  
Segment margin 609 568
Unrealized losses on commodity risk management activities 3
Operating expenses, excluding non-cash compensation expense (193 ) (168 )
Selling, general and administrative expenses, excluding non-cash compensation expense (22 ) (18 )
Adjusted EBITDA related to unconsolidated affiliates 8   8  
Segment Adjusted EBITDA $ 402   $ 393  

Gathered volumes and NGL production increased primarily due to increases in the North Texas, Permian and Northeast regions, partially offset by smaller declines in other regions.

Segment Adjusted EBITDA. For the three months ended December 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effects of the following:

  • an increase of $49 million in fee-based margin due to growth in the North Texas, Permian and Northeast regions, offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions; and
  • an increase of $14 million in non-fee-based margin due to increased throughput volume in the North Texas and Permian regions; partially offset by
  • a decrease of $25 million in non-fee-based margin primarily due to lower NGL prices;
  • an increase of $25 million in operating expenses due to an increase of $8 million in materials, $6 million in outside services, $6 million in ad valorem taxes and $5 million in expense projects; and
  • an increase of $4 million in selling, general and administrative expenses due to a change in capitalized overhead.
 

NGL and Refined Products Transportation and Services

 
Three Months Ended
December 31,
2018   2017
NGL transportation volumes (MBbls/d) 1,115 963
Refined products transportation volumes (MBbls/d) 601 618
NGL and refined products terminal volumes (MBbls/d) 898 792
NGL fractionation volumes (MBbls/d) 594 455
Revenues $ 2,946 $ 2,533
Cost of products sold 2,106   1,951  
Segment margin 840 582
Unrealized gains on commodity risk management activities (112 ) (28 )
Operating expenses, excluding non-cash compensation expense (156 ) (120 )
Selling, general and administrative expenses, excluding non-cash compensation expense (22 ) (15 )
Adjusted EBITDA related to unconsolidated affiliates 19   14  
Segment Adjusted EBITDA $ 569   $ 433  

NGL transportation volumes increased primarily due to increased volumes from the Permian region resulting from a ramp up in production from existing customers, higher throughput volumes on Mariner West driven by end user facility constraints in the prior period and higher throughput from Mariner South resulting from increased export volumes. Refined products transportation volumes decreased primarily due to the timing of turnarounds at third-party refineries in the Midwest and Northeast regions.

NGL and refined products terminal volumes increased primarily due to more volumes loaded at our Nederland terminal as export demand increased, as well as higher throughput volumes at our Marcus Hook Industrial Complex.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased primarily due to increased volumes from the Permian region, as well as an increase in fractionation capacity as our fifth fractionator at Mont Belvieu came online in July 2018.

Segment Adjusted EBITDA. For the three months ended December 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to net impacts of the following:

  • an increase of $85 million in transportation margin primarily due to a $70 million increase resulting from higher producer volumes from the Permian region on our Texas NGL pipelines, a $9 million increase due to higher throughput volumes on Mariner West driven by end-user facility constraints in the prior period, a $5 million increase due to higher throughput volumes from the Barnett region, a $4 million increase resulting from a reclassification between our transportation and fractionation margins and a $3 million increase due to higher throughput volumes on Mariner South as a result of increased export volumes. These increases were partially offset by a $6 million decrease resulting from the timing of deficiency revenue recognition;
  • an increase of $32 million in fractionation and refinery services margin primarily due to a $43 million increase resulting from the commissioning of our fifth fractionator in July 2018 and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $5 million decrease in blending gains as a result of less favorable market pricing, a $4 million decrease resulting from a reclassification between our transportation and fractionation margins and a $2 million decrease from planned downtime at a customer facility that lowered the supply to our refinery services facility;
  • an increase of $28 million in marketing margin due to a $31 million increase from our butane blending operations and an $12 million increase in NGL sales from our Marcus Hook Industrial Complex. These increases were partially offset by a $15 million decrease from the timing of optimization gains from our Mont Belvieu fractionators; and
  • an increase of $26 million in terminal services margin due to a $13 million increase from higher throughput at our Marcus Hook Industrial Complex, an $11 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses and a $2 million increase at our Nederland terminal due to increased export demand; partially offset by
  • an increase of $36 million in operating expenses primarily due to a $14 million increase in operating costs primarily due to higher throughput on our NGL pipelines and fractionators and the commissioning of our fifth fractionator in July 2018, an $11 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, a $3 million increase in costs relating to an outside storage lease and a $3 million increase in certain allocated overhead costs; and
  • an increase of $7 million in selling, general and administrative expenses due to a $6 million increase in overhead costs allocated to the segment and $1 million increase in legal fees.
 

Crude Oil Transportation and Services

 
Three Months Ended
December 31,
2018   2017
Crude transportation volumes (MBbls/d) 4,330 3,872
Crude terminals volumes (MBbls/d) 2,202 2,059
Revenues $ 4,346 $ 3,938
Cost of products sold 3,407   3,255  
Segment margin 939 683
Unrealized (gains) losses on commodity risk management activities (132 ) 4
Operating expenses, excluding non-cash compensation expense (150 ) (125 )
Selling, general and administrative expenses, excluding non-cash compensation expense (22 ) (20 )
Adjusted EBITDA related to unconsolidated affiliates 1   2  
Segment Adjusted EBITDA $ 636   $ 544  

Crude transportation volumes increased due to placing the Bakken pipeline in service in June 2017 as well as higher throughput on existing pipelines due to increased production in West Texas. Crude terminal volumes benefited from an increase in barrels delivered to our Nederland crude terminal from the Bakken pipeline and from increased West Texas production.

Segment Adjusted EBITDA. For the three months ended December 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

  • an increase of $120 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to the following: a $102 million increase resulting from higher throughput on the Bakken pipeline and a $125 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers. These increases were partially offset by a $107 million decrease to segment margin (excluding a net change of $136 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business; partially offset by
  • an increase of $25 million in operating expenses due to a $23 million increase due to higher throughput related expenses on existing assets and a $2 million increase from the expansion of our Permian Express 3 pipeline in service in the fourth quarter of 2018; and
  • an increase of $2 million in selling, general and administrative expenses primarily due to increases in allocated shared service charges.
 

Investment in Sunoco LP

 
Three Months Ended
December 31,
2018   2017
Revenues $ 3,877 $ 2,959
Cost of products sold 3,694   2,682  
Segment margin 183 277
Unrealized losses on commodity risk management activities 5 2
Operating expenses, excluding non-cash compensation expense (111 ) (113 )
Selling, general and administrative, excluding non-cash compensation expense (36 ) (36 )
Inventory fair value adjustments 135 (16 )
Adjusted EBITDA from discontinued operations 44
Other, net 4    
Segment Adjusted EBITDA $ 180   $ 158  

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the three months ended December 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP increased due to the net impacts of the following:

  • an increase of $60 million in margin (excluding a $154 million change in inventory fair value adjustments and unrealized losses on commodity risk management activities) primarily due to increases in fuel margins and fuel volumes; partially offset by
  • a decrease of $44 million in Adjusted EBITDA from discontinued operations primarily due to Sunoco LP’s retail divestment in January 2018.
 

Investment in USAC

 
Three Months Ended
December 31,
2018   2017
Revenues $ 172 $
Cost of products sold 23  
Segment margin 149
Operating expenses, excluding non-cash compensation expense (30 )
Selling, general and administrative, excluding non-cash compensation expense (16 )
Other, net 1  
Segment Adjusted EBITDA $ 104   $

Amounts reflected above for the three months ended December 31, 2018 represents the consolidated results of operations for USAC. Changes between periods are due to the consolidation of USAC beginning April 2, 2018.

 

All Other

 
Three Months Ended
December 31,
2018   2017
Revenues $ 630 $ 652
Cost of products sold 585   550  
Segment margin 45 102
Unrealized (gains) losses on commodity risk management activities (11 ) 3
Operating expenses, excluding non-cash compensation expense (6 ) (31 )
Selling, general and administrative expenses, excluding non-cash compensation expense (41 ) (28 )
Adjusted EBITDA related to unconsolidated affiliates 12
Other and eliminations 6   3  
Segment Adjusted EBITDA $ (7 ) $ 61  

Segment Adjusted EBITDA. For the three months ended December 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:

  • a decrease of $35 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;
  • a decrease of $29 million due to merger and acquisition expenses related to the Merger in 2018;
  • a decrease of $13 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES primarily due to our lower ownership in PES subsequent to its reorganization, which resulted in PES no longer being reflected as an affiliate beginning in the third quarter of 2018; and
  • a decrease of $6 million due to a decrease in power trading gains; partially offset by
  • an increase of $5 million in joint venture management fees; and
  • an increase of $4 million from transport fees and gains from storage and park and loan activity.
     

ENERGY TRANSFER LP AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON LIQUIDITY

(In millions)
(unaudited)
 
The following table is a summary of ETO’s revolving credit facilities which incurred certain changes in connection with the Merger. We also have consolidated subsidiaries with revolving credit facilities which are not included.
 
Facility Size

Funds Available at
December 31, 2018

Maturity Date
ETO Five-Year Revolving Credit Facility $ 5,000 $ 1,243 December 1, 2023
ETO 364-Day Revolving Credit Facility 1,000   1,000   November 30, 2019
$ 6,000   $ 2,243  
 
 

ENERGY TRANSFER LP AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES

(In millions)
(unaudited)
 

The table below provides information on an aggregated basis for our unconsolidated affiliates, which are accounted for as equity method investments in the Partnership’s financial statements for the periods presented.

 
Three Months Ended
December 31,
2018   2017
Equity in earnings (losses) of unconsolidated affiliates:
Citrus $ 39 $ 58
FEP 14 14
MEP 7 9
HPC (1)(2) (185 )
Other 26   20  
Total equity in earnings (losses) of unconsolidated affiliates $ 86   $ (84 )
 
Adjusted EBITDA related to unconsolidated affiliates:
Citrus $ 81 $ 74
FEP 18 19
MEP 19 22
HPC (2) 6
Other 34   41  
Total Adjusted EBITDA related to unconsolidated affiliates $ 152   $ 162  
 
Distributions received from unconsolidated affiliates:
Citrus $ 46 $ 43
FEP 18 19
MEP 8 8
HPC (2) 13
Other 35   22  
Total distributions received from unconsolidated affiliates $ 107   $ 105  

(1) For the three months ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.

(2) The partnership previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, we acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in our financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in our financial statements.

 

ENERGY TRANSFER LP AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON NON-WHOLLY-OWNED JOINT VENTURE SUBSIDIARIES

(In millions)
(unaudited)
 

The table below provides information on an aggregated basis for our non-wholly-owned joint venture subsidiaries, which are reflected on a consolidated basis in our financial statements. The table below excludes Sunoco LP and USAC, which are non-wholly-owned subsidiaries that are publicly traded.

 
Three Months Ended
December 31,
2018   2017
Adjusted EBITDA of non-wholly-owned subsidiaries (100%) (a) $ 669 $ 381
Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries (b) 351 212
 
Distributable Cash Flow of non-wholly-owned subsidiaries (100%) (c) $ 626 $ 346
Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries (d) 332 194

Below is our ownership percentage of certain non-wholly-owned subsidiaries:

Non-wholly-owned subsidiary:   ET Percentage Ownership (e)  
Bakken Pipeline 36.4 %
Bayou Bridge 60.0 %
Ohio River System 75.0 %
Permian Express Partners 87.7 %
Rover 32.6 %
Others various

(a) Adjusted EBITDA of non-wholly-owned subsidiaries reflects the total Adjusted EBITDA of our non-wholly-owned subsidiaries on an aggregated basis. This is the amount of EBITDA included in our consolidated non-GAAP measure of Adjusted EBITDA.

(b) Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries reflects the amount of Adjusted EBITDA of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest.

(c) Distributable Cash Flow of non-wholly-owned subsidiaries reflects the total Distributable Cash Flow of our non-wholly-owned subsidiaries on an aggregated basis.

(d) Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries reflects the amount of Distributable Cash Flow of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest. This is the amount of Distributable Cash Flow included in our consolidated non-GAAP measure of Distributable Cash Flow attributable to the partners of ET.

(e) Our ownership reflects the total economic interest held by us and our subsidiaries. In some cases, this percentage comprises ownership interests held in (or by) multiple entities.

Energy Transfer

Investor Relations:
Bill Baerg, Brent Ratliff, Lyndsay Hannah, 214-981-0795
or
Media Relations:
Vicki Granado, 214-840-5820


Source: Business Wire (February 20, 2019 - 4:05 PM EST)

News by QuoteMedia
www.quotemedia.com

Recent Company Earnings:


February 20, 2020

Houston Chronicle


Houston oilfield service company Halliburton plans to pay down its long-term debt by issuing $1 billion in lower-interest notes.

Halliburton to pay down debt by issuing $1 billion of lower-interest notes- oil and gas 360

Source: Houston Chronicle

Halliburton on Wednesday said it plans to issue a type of debt known as senior notes. Due in March 2030, the notes will pay 2.92 percent interest.

The company said it will use proceeds from the sales to buy back previously issued senior notes and reduce other forms of debt.

Halliburton closed 2019 with about $10.3 billion of debt, almost one-third less than the $15.4 billion in debt it had at the end of 2015, according to a Securities and Exchange Commission filing.

With the price of crude hovering just above $50 per barrel, most oil companies are reducing drilling and fracking activity, resulting in recent losses for oilfield service companies. Halliburton lost $1.1 billion in 2019.

Shell Midstream Partners, L.P. (NYSE: SHLX) reported net income attributable to the Partnership of $140 million for the fourth quarter of 2019, which equated to $0.37 per common limited partner unit. Shell Midstream Partners also generated adjusted earnings before interest, income taxes, depreciation and amortization attributable to the Partnership of $187 million.

February 19, 2020

HOUSTON, Feb. 19, 2020 (GLOBE NEWSWIRE) — Hi-Crush Inc. (NYSE: HCR) (the “Company”), a fully-integrated provider of proppant logistics solutions, today reported fourth quarter and full year 2019 results. Revenues during the fourth quarter of 2019 totaled $125.5 million compared to $173.0 million during the third quarter of 2019.

DENVERFeb. 19, 2020 /PRNewswire/ —

  • Fourth quarter oil production averaged 92.0 MBbls per day
    • Full year oil production averaged 86.2 MBbls per day
  • 2019 capital investment (including midstream) totaled $1.32 billion; below guidance range
    • Lower D&C costs drove the beat
  • Generated $1.34 billion of net cash from operating activities
    • $141 million of free cash flow1 in 2019; $59 million after dividend

February 14, 2020

Enbridge Files 2019 Year End Disclosure Documents

February 13, 2020

Houston Chronicle


Houston exploration and production company Marathon Oil has cut its drilling budget by about 10 percent amid an ongoing shale slump that caused revenue and profits to decline in 2019.

Marathon Oil cuts drilling budget amid 56 percent drop in profit- oil and gas 360

Source: Houston Chronicle

In a Wednesday afternoon statement, Marathon said the company is cutting capital expenditures by 10 percent, to $2.4 billion from $2.6 billion in 2019.

The company plans to spend $2.2 billion of its capital expenditure budget on drilling, hydraulic fracturing and other activities in the field while the remain $200 million will go to secure new oil leases and exploratory work looking for new geological formations with oil and natural gas.

Marathon remains in the black, but like other companies in the exploration and production sector, more than a year of crude oil prices in the $50 range is taking its toll on profit and drilling activity.

Active in the Eagle Ford Shale, Permian Basin, Oklahoma and Bakken Shale, Marathon reported a $20 million loss during the fourth quarter of 2019 compared with a $165 million profit a year earlier and revenue fell to $1.2 billion from $1.3 billion.

For the year, the company reported a $480 million profit, a 56 percent drop from the $1.1 billion profit in 2018; revenue of $5.2 billion was 21 percent off the $6.6 billion in 2018.

“We’ll continue to be guided by our unwavering commitment to capital discipline and sustainability,” Marathon Oil CEO Lee Tillman said in a statement.

 

Precision Drilling Corporation Announces 2019 Fourth Quarter and Year End Unaudited Financial Results

February 7, 2020

Houston Chronicle


Houston oilfield service company National Oilwell Varco finished up a year of losses $6.1 billion in the red.

NOV finishes year of losses $6.1 billion in the red- oil and gas 360

Source: Houston Chronicle

In a statement released on Thursday evening, the company reported closing 2019 with a $6.1 billion loss, a dramatic drop from the $31 million end-of-year loss in 2018. The company’s annual revenue remained flat at $8.5 billion.

Most of the company’s end-of-year loss came from writing down the value of $5.4 billion of assets during the second quarter. Crude oil prices stuck in the $50 per barrel range for most of past year have dramatically cut demand for drilling and hydraulic fracturing services in the United States. The shale slump has created eye-popping losses for oilfield services companies, which have written down billions of dollars of assets in response.

“The fourth quarter saw continued improvements in international and offshore markets, partially offset by another sequential decline in spending by our customers in North America,” National Oilwell Varco CEO Clay Williams said in a statement.

Looking at the company’s fourth quarter performance, NOV posted a $385 million loss, which was a dramatic swing from the $15 million profit during the fourth quarter of 2018.

The company’s fourth quarter revenue also slipped by 5 percent year-over-year. NOV reported making $2.3 billion during the fourth quarter, compared to $2.4 billion during the fourth quarter one year earlier.

With historical roots going back to 1862, NOV is headquartered in Houston and has more than 35,000 employees in 65 nations.

The company has not made an annual profit since 2014.

 

February 6, 2020

Reuters


ABERDEEN, Scotland – Total (TOTF.PA) beat forecasts on Thursday by keeping net adjusted fourth-quarter profit steady at $3.2 billion despite low oil prices and fulfilled a pledge to boost dividends, lifting the French energy firm’s shares.

Total beats quarterly forecasts despite low oil price, raises payout- oil and gas 360

Source: Reuters

The stock rose about 3% before easing off its highs as the company bucked a trend in the industry which has seen profits tumble in the last three months of 2019. Analysts had expected Total’s net profit to slip to $2.7 billion.

“This performance is better than that of our rivals in terms of resisting low oil prices,” CEO Patrick Pouyanne told journalists, adding Total was rewarding investors with a 6% increase in the final dividend for 2019 to 0.68 euros per share.

“Taking into account the strong visibility on cash flow, the group will continue to increase the dividend with the guidance of 5% to 6% per year,” the company said in its statement.

Total bought back $1.75 billion in shares in 2019 and plans to buy back $2 billion more in 2020.

Pouyanne said the group had reported solid results including debt-adjusted cash flow (DACF) of $7.4 billion, up more than 20% from a year earlier.

“While some peers buckled last week to a synchronized slowdown in their commodity prices and margins, Total has bucked that trend with flat year-on-year net income,” Bernstein analysts wrote, adding that net income and net operating income were both ahead of forecasts.

The analysts, which rate the stock “outperform”, said liquefied natural gas (LNG) margins “also beat our expectations as the company proved immune to low spot gas prices despite market concerns”.

LNG prices have been under pressure as new projects have kept the market well supplied, while oil prices LCOc1 have tumbled to around $55 per barrel from last year’s peak in April of almost $75.

Rivals have seen fourth-quarter profits slide on lower prices. BP (BP.L) reported a 26% drop on Tuesday while Royal Dutch Shell (RDSa.L) last month said its profits had halved.

(Graphic: Majors cashflow Total, here)

Reuters Graphic

LNG OUTPUT

Total’s oil and gas production grew by 9% in 2019 thanks to project start-ups and ramp-ups, while its LNG business doubled, boosting cash flow.

“One of the reasons our results resisted the low oil environment was because of the strong LNG output which grew 50%,” Pouyanne said.

He said exceptional production growth was unlikely to continue in the years to come and output growth for 2020 was seen at 2% to 4%, a more typical level in the industry.

The chief executive said Total was expanding in the low carbon energy business and was on track to meet its goal of producing 25 gigawatts (GW) of renewable electricity by 2025, helped by solar projects in Qatar and India.

Total, which kept its capital expenditure target steady for 2020 at $18 billion, said it was on track to achieve its target of $5 billion in divestments during 2019 and 2020.

Total said it had sold its 27.5% interest in Fosmax LNG, which operates France’s Fos Cavaou LNG terminal, to Engie (ENGIE.PA) unit Elengy for about $260 million.

Total is on track to achieve its divestment target with transactions worth $3 billion so far, Jefferies analysts said.

(Graphic: Total Results, here)

Reuters Graphic

Houston Chronicle


Black Stone Minerals said it will cut its quarterly payouts to investors by almost 20 percent because of falling oil and gas prices.

Black Stone Minerals cuts investor payouts by almost 20%- oil and gas 360

Source: Houston Chronicle

In another sign of the weakening energy sector, the Houston oil and gas royalties firm will reduce its distributions to 30 cents per unit from 37 cents. This is the first time Black Stone has reduced its payout since going public in 2015.

Even during the lean years of the last oil bust in 2015 and 2016, Black Stone steadily hiked investor payments from an initial 16.2 cents per unit in 2015.

“We are taking a proactive approach to strengthen our balance sheet and enhance our financial flexibility with the expectation that 2020 may be a challenging year in terms of commodity prices and overall drilling activity,” said Black Stone CEO Thomas Carter Jr.

“Given the current environment, the board believes that reducing the distribution benefits unitholders by providing additional cash flow for, first, the repayment of debt, and for other such uses as unit repurchases and acquisitions.,” Carter added.

February 4, 2020

CNBC


Energy giant BP reported better-than-expected full-year net profit on Tuesday, outperforming analyst expectations despite lower oil and gas prices.

BP full-year net profit falls 21% on weak oil and gas prices- oil and gas 360

Source: Reuters

The U.K.-based oil and gas company posted full-year underlying replacement cost profit, used as a proxy for net profit, of $10 billion in 2019. That compared with $12.7 billion full-year net profit in 2018, reflecting a year-on-year fall of 21%.

Analysts had expected full-year net profit to come in at $9.7 billion in 2019, according to data from Refinitiv.

Shares of BP were up more than 4%.

“BP is performing well, with safe and reliable operations, continued strategic progress and strong cash delivery,” Bob Dudley, CEO of BP, said in a statement.

“After almost ten years, this is now my last quarter as CEO. In that time, we have achieved a huge amount together and I am proud to be handing over a safer and stronger BP to Bernard and his team.”

“I am confident that under their leadership, BP will continue to successfully navigate the rapidly-changing energy landscape,” Dudley said.

Bernard Looney, who has run BP’s upstream business since April 2016 and has been a member of the firm’s executive management team since November 2010, is now set to take the reins from the outgoing chief executive.

In October, Dudley announced he would step down as CEO on Feb. 4., having held the position for almost a decade. The 64-year-old plans to retire on March 31, thus bringing an end to his 40-year career with BP.

Here are the key highlights:

  • Underlying replacement cost profit for the fourth quarter and full-year 2019 was $2.6 billion and $10.0 billion respectively, compared to $3.5 billion and $12.7 billion for the same periods a year earlier.
  • Gulf of Mexico oil spill payments for the year totaled $2.4 billion on a post-tax basis, and are expected to be less than $1 billion in 2020.
  • A dividend of 10.5 cents per share was announced for the quarter, an increase of 2.4% on a year earlier.

The energy giant’s full-year results follow disappointing earnings from oil and gas companies on both sides of the Atlantic.

Anglo-Dutch energy giant Royal Dutch Shell reported a sharp fall in full-year net profit late last week, while U.S. rivals Chevron and Exxon Mobil both missed analyst expectations on Friday.

France’s Total is scheduled to report its latest quarterly earnings on Feb. 6.

All roads lead to OPEC decision

International benchmark Brent crude traded at $54.74 Tuesday lunchtime, up more than 0.5%, while U.S. West Texas Intermediate (WTI) stood at $50.75, around 1.2% higher.

Both crude benchmarks have each fallen around 20% since climbing to a peak in early January, dragged lower by concern over demand in China after the coronavirus outbreak.

Brian Gilvary, chief financial officer at BP, told CNBC’s “Squawk Box Europe” on Tuesday that the coronavirus outbreak could wipe out as much as 300,000 to 500,000 barrels per day (bpd) of oil demand in 2020.

The International Energy Agency (IEA) has previously said it expects oil demand to grow by 1.2 million bpd this year, so a reduction of up to 500,000 bpd would leave demand growth “healthy” at 700,000 to 800,000 bpd, Gilvary said.

“I think, in terms of price direction, all roads will then lead to what OPEC will do in terms of trying to rebalance the system to get back to something around $60 to $65 a barrel,” he added.

OPEC and its allies are considering cutting their oil output by a further 500,000 bpd this year, two OPEC sources and a third industry source familiar with discussions told Reuters on Monday.

A ministerial meeting currently scheduled for early March could be brought forward to mid-February, one of the OPEC sources said, with February 14-15 touted as possible dates.

Houston Chronicle


ConocoPhillips’ fourth-quarter profit declined by more than 60 percent, to $720 million from $1.9 billion in the same period last year, amid weaker oil prices and production outputs.

ConocoPhillips' fourth-quarter profit plunges by 60%-oil and gas 360

Source: Houston Chronicle

Revenue during the quarter dropped by more than 20 percent to $8.1 billion.

For the full year, net earnings jumped 15 percent to $7.2 billion compared with $6.3 billion in 2018.

The Houston oil and gas producer still won over many on Wall Street late last year by hiking dividend payments to shareholders and with the release of a 10-year outlook that would rein in spending throughout the new decade.

“Strong 2019 performance capped off a highly successful three-year period in which we transformed our business model and significantly improved our underlying performance drivers across the company,” said Ryan Lance, chairman and chief executive officer. “We’ve positioned ConocoPhillips to deliver sustained value through price cycles due to our strong balance sheet, focus on free cash flow generation, compelling returns of and returns on capital and our commitment to environmental, social and governance leadership.”

Essentially, ConocoPhillips is focused on bringing in stronger profits and paying out more to investors while operating with flatter spending and smaller overall scale.

The company’s production output is expected to dip a little in 2020 because of some recent asset sales.

Last year, ConocoPhillips’ oil and gas production volumes grew by 5 percent despite a small decline in the fourth quarter.

The company’s shale production jumped by 22 percent last year. Shale volumes account for 30 percent of the company’s global production, led by South Texas’ Eagle Ford Shale. ConocoPhillips’ rising outputs in West Texas’ Permian Basin are on track to soon surpass its volumes in North Dakota’s Bakken shale.

Still, ConocoPhillips’ Asian, Australian, North Sea and Alaskan business units are more profitable than its U.S. shale output.

The company’s 2020 capital spending budget is projected to be $6.5 billion to $6.7 billion, on par with the $6.6 billion in 2019. However, that 2019 capital spending budget increased throughout the year from an initial budget of $6.1 billion, a revised midyear budget at $6.3 billion, and final spending for the year of $6.6 billion.

 

January 31, 2020

Houston Chronicle


Houston refining and pipeline company Phillips 66 on Friday reported a $689 million fourth-quarter profit, 51 percent less than the same period in 2018.

Imperial Oil's quarterly profit beats estimates on higher crude prices- oil and gas 360

Source: Houston Chronicle

The fourth quarter performance resulted in Phillips 66 closing 2019 with a nearly $3.7 billion profit, a 35 percent drop from the previous year when favorable margins in the refining of domestic crude oil swelled profits. The

West Texas Intermediate crude oil prices fell by 40 percent during the fourth quarter of 2018 and entered the $40 per barrel range, creating losses for exploration and production companies and services companies but windfalls for refining companies that were able to process domestic crude.

Crude oil prices have since settled in the $50 per range, which are still beneficial to refining companies but not as profitable.

Phillips 66’s pipeline business took a $900 million hit during the third quarter for impairments related to writing down the value of DCP Midstream, a gathering and processing plant joint venture with Canadian pipeline operator Enbridge.

In a statement, Phillips 66 Greg Garland focused on future growth. The company placed its Gray Oak Pipeline into service in November. When in full service early this year it will move 900,000 barrels of crude oil per day from Texas’ Permian Basin and Eagle Ford Shale to the company’s refinery in Brazoria County and the Port of Corpus Christi.

“As we begin 2020, we are focused on operating excellence, executing our growth projects, enhancing returns on existing assets and exercising disciplined capital allocation,” Garland said.

 

CNBC


Chevron on Friday posted a $6.6 billion loss in the fourth quarter due to $10.4 billion worth of write-offs related to shale gas production in Appalachia and deep-water projects in the Gulf of Mexico. In December, the company warned that this charge would be $10 billion to $11 billion.

Chevron posts $6.6 billion loss in the fourth quarter-oil and gas 360

Source: CNBC

Shares slid 3.4% on Friday after the company reported $36.35 billion in revenue for the period, which missed analyst expectations and was down 14% year over year, hurt by weakness in the company’s upstream division.

Chevron said it earned $1.49 per share excluding items, down from $1.95 per share a year earlier.

Here’s how the energy giant’s results fared on an adjusted basis relative to Wall Street expectations:
  • Adjusted earnings: $1.49 cents per share vs. $1.45 expected by a Refinitiv survey of analysts
  • Revenue: $36.35 billion vs. $38.639 billion expected by Refinitiv

A year earlier, the company earned $3.7 billion. Total earnings for 2019 slid 80%, to $2.924 billion, compared with $14.824 billion in 2018.

Oil-equivalent production at 3.08 million barrels per day was unchanged year over year, although the company said its annual daily production exceeded 3 million barrels per day for the first time.

The company’s upstream operations in the U.S. lost $7.5 billion in the quarter, down from earnings of $964 million a year earlier. That was primarily due to $8.2 billion in write-offs related to Appalachia and Gulf of Mexico operations, as well as lower crude and natural gas prices.

Chevron said the average sale price per barrel of oil and natural gas liquids was $47, a 16% decrease from 2018.

“Cash flow from operations remained strong in 2019, allowing the company to deliver on all our financial priorities,“
Chairman and CEO Michael Wirth said in a statement. “We paid $9 billion in dividends, repurchased $4 billion of shares, funded our capital program and successfully captured several inorganic investment opportunities, all while reducing debt by more than $7 billion. Earlier this week, we announced a quarterly dividend increase of $0.10 per share, reinforcing our commitment to growing shareholder returns.”

In the same quarter a year earlier the company reported EPS of $1.95 and revenue of $42.35 billion. Last quarter, the company earned $1.36 per share, and brought in $36.12 billion in revenue.

U.S. West Texas Intermediate crude prices are down more than 15% this month, while international benchmark Brent crude has shed roughly 12%.


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