February 20, 2019 - 4:05 PM EST
Print Email Article Font Down Font Up Charts



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:


November 5, 2019

Source: Reuters


(Reuters) – Chesapeake Energy Corp , once the second-largest U.S. natural gas producer, warned on Tuesday about its ability to continue as a going concern as the debt-laden company struggles with falling prices for the commodity.

Chesapeake Energy raises 'going concern' doubts-oag360

Source: chk.com

Shares of Chesapeake fell 13% to $1.35 in early trading, with the company earlier in the day also having reported a marginally bigger than expected loss and a huge shortfall in production for the third quarter.

Chesapeake has about $10 billion in debt, nearly four times its market valuation. Much of that is a result of big spending when energy prices were high and acquisitions aimed at expanding in the oil-heavy Powder River Basin to combat falling natural gas prices.

The company said its ability to meet debt covenants in the next 12 months will be affected if oil and natural gas prices continue to remain low. (bit.ly/34yczbo)

A continuous rise in U.S. gas production – a byproduct of the shale oil boom – has prices for the fuel heading toward a 25-year low, with output outpacing U.S. consumption.

The company said average realized natural gas price fell 11.5% to $2.38 per thousand cubic feet in the third quarter.

Total production fell nearly 11% to 478,000 barrels of oil equivalent per day (boe/d) from a year earlier and missed analysts’ expectations of 490,664 boe/d.

Adjusted net loss attributable to the company was $188 million, or 11 cents per share, in the third quarter ended Sept. 30 from a loss of $8 million, or 1 cent per share, a year earlier.

Analysts on average had expected the company to report a loss of 10 cents per share.

The Oklahoma-based firm expects capital expenses to range from $1.3 billion to $1.6 billion for 2020, well below $2.11 billion to $2.31 billion set aside for 2019.

The company also plans to cut its 2020 production costs as well as general and administrative expenses by about 10% while expecting flat oil production year over year.

Source: Reuters


HOUSTON (Reuters) – Pioneer Natural Resources Chief Executive Scott Sheffield said on Tuesday that he expects the Permian Basin, the top U.S. shale field, to “slow down significantly over the next several years.”

Top shale CEO says OPEC shouldn't worry about U.S. oil growth-oag360

Source: pxd.com

“I don’t think OPEC has to worry that much more about U.S. shale growth long term,” Sheffield said on Tuesday on a call with analysts.

U.S. shale fields have driven domestic production to all time highs, prompting OPEC to cut production to keep global prices stable. But U.S. producers are under pressure to trim spending and return profits to shareholders through dividends and share buybacks.

Despite new production coming from Norway, Brazil and Guyana in the next year, “there’s not much coming on after” that, Sheffield said, adding that he is “becoming more optimistic that we’re probably at the bottom end of the cycle” in oil prices.

November 1, 2019

Source: Houston Chronicle


Exxon Mobil Corp. profits fell in the third quarter, the company reported Friday.

Exxon Mobil's profits fall in third quarter-oag360

Source: Houston Chronicle

The Irving, Texas-based oil major reported a third-quarter net profit of $3.17 billion, little more than half the profit the company reported in the same quarter last year.

Exxon reported $65.05 billion of revenue in the third quarter, down from $76.61 billion in the same quarter last year.

Still, the energy giant beat Wall Street expectations. Exxon reported earning 75 cents per share; analysts expected earnings of 67 cents a share.

Oil-equivalent production rose 3 percent from the third quarter of 2018, to 3.9 million barrels per day. Liquids production increased 4 percent, driven by Permian Basin growth, and natural gas volumes increased 1 percent.

Production in the Permian Basin increased 7 percent in the third quarter.

“We are making excellent progress on our long-term growth strategy,” said Darren W. Woods, chairman and chief executive officer in a statement.

October 30, 2019

Source: Reuters


(Reuters) – Hess Corp (HES.N) reported a quarterly loss on Wednesday, as lower oil and gas prices limited gains from higher production, sending its shares down nearly 5%.

https://www.reuters.com/article/us-hess-results/hess-posts-loss-as-lower-oil-prices-cap-production-gains-idUSKBN1X91CD-oag360

Source: Reuters/Andrew Cullen

The results come a day after shale player Concho Resources Inc (CXO.N) posted adjusted earnings that more than halved on the back of tumbling prices.

Hess said average prices for crude, including hedging, fell more than 15% in the third quarter, while it dropped 7% for natural gas.

Global oil prices fell in the third quarter on oversupply and demand concerns fueled by the U.S.-China trade war and its impact on the global economy.

The results come a day after shale player Concho Resources Inc (CXO.N) posted adjusted earnings that more than halved on the back of tumbling prices.

Hess said average prices for crude, including hedging, fell more than 15% in the third quarter, while it dropped 7% for natural gas.

Global oil prices fell in the third quarter on oversupply and demand concerns fueled by the U.S.-China trade war and its impact on the global economy.

Oil and gas net production rose to an average of 290,000 barrels of oil equivalent per day (boepd), excluding Libya, from 279,000 boepd a year earlier.

The increased production was driven by a 38% jump in Bakken output that partially offset the hit from hurricane in the Gulf of Mexico.The higher output at Bakken also prompted the company to raise its full-year net production guidance to about 285,000 boepd, from 275,000 boepd to 280,000 boepd it forecast earlier.

Hess also cut its 2019 capital expenditure by $100 million to $2.7 billion.

The company posted an adjusted net loss of $98 million, or 32 cents per share, in the third quarter ended Sept. 30, compared with a profit of $29 million, or 6 cents per share, a year earlier.

Analyst on average expected a loss of 33 cents, according to IBES data from Refinitiv.

Shares of the company were 4.2% lower at $62.96 amid a broader fall in oil prices that dragged the S&P energy index .SPNY down 1.1%.

October 29, 2019

Source: Reuters


(Reuters) – U.S. Silica Holdings shares plunged 33% after the frac sand miner said it expects demand to slow in the fourth quarter and reported a bigger-than-expected quarterly loss on Tuesday, weighed down by lower prices.

Prices for the proppant used to crack the ground and extract oil have dropped in North America as oil producers drill and complete fewer wells under investor pressure to spend less, and as the market struggles with an oversupply in the aftermath of the shale boom.

https://www.reuters.com/article/us-u-s-silica-results/u-s-silica-sees-lower-frac-sand-demand-shares-tumble-idUSKBN1X812J-oag360

Source: ussilica.com

“Energy markets deteriorated further and faster than expected during the quarter as E&P budget exhaustion slowed completion activity, resulting in lower demand and pricing pressure,” Chief Executive Officer Bryan Shinn said on a post-earnings call with analysts.

While sand sales to oil and gas customers fell 1% sequentially, pricing was “significantly lower” with new mines coming online in West Texas and overcrowding the market, the company said.

Volumes in the current quarter are expected to decline at least 10% sequentially, while prices are expected to fall further, it added.

However, Shinn expects to see a rebound in oil field completions by the middle of the first quarter next year, as oil and gas producers reset their budgets.

The company also forecast net sales and profits in its industrial business, which supplies sand to construction companies and glass manufacturers, to stay flat or rise marginally in 2020, hurt by trade tariffs and fears of a global slowdown.

U.S. Silica reported a net loss of $23 million, or 31 cents per share, for the quarter ended Sept. 30, compared with a profit of $6.3 million, or 8 cents per share, a year earlier.

Excluding items, loss of 17 cents per share missed analysts’ average estimate of 3 cents, according to Refinitiv IBES data.

Revenue fell 14.5% to $361.8 million, also missing estimate of $395.5 million.

The company now expects 2019 spending to be less than $125 million it had forecast earlier, and plans to spend between $40 million and $60 million next year.

October 25, 2019

Reuters


Phillips 66 beat analysts’ estimates for quarterly profit on Friday, as the refiner benefited from higher retail fuel margins, sending its shares up 4.4% to their highest in more than a year.

The Houston, Texas-based company, which retails fuel under brand names such as Conoco, 76 and JET, buys refined products from the market and resells them across its about 9,000 outlets spread across the United States and Europe.

https://www.reuters.com/article/us-phillips-66-results/phillips-66-profit-beats-on-higher-fuel-margins-shares-jump-idUSKBN1X41DX-oag360

Source: Reuters/Rick Wilking

The business, marketing & specialties, was helped by an 18% drop in crude prices in the third quarter that reduced the cost of the refined products like gasoline and aviation fuel.

“The beat was driven by stronger-than-expected results across all segments, but marketing & specialties particularly exceeded our expectations,” Morgan Stanley analysts wrote in a note.

Marketing fuel margins of $2.11 per barrel in the United States and $6.37 per barrel internationally was about 30-60% higher than the brokerage’s estimates.

Adjusted earnings in the unit rose nearly 30% to $498 million in the third quarter.

Profit in its midstream segment, which transports and stores crude, natural gas liquids (NGL) and exports liquefied petroleum gas, jumped more than 40% on the back of higher pipeline volumes and hydrocarbon trading.

Houston-based Phillips 66 has been beefing up its midstream assets, expanding its U.S. Gulf Coast NGL market hub, as well as adding storage capacity at Texas-based Clemens Caverns facility and Beaumont Terminal.

However, adjusted earnings at its largest refining segment slumped nearly 34% due to higher turnaround costs and as margins fell 16% to $11.18 per barrel.

The company’s refineries had worldwide crude oil capacity utilization rate of 97% during the quarter, compared with 93% a year earlier.

Net earnings more than halved to $712 million, or $1.58 per share, in the three months to Sept. 30.

Excluding a $690 million impairment related to investments in DCP Midstream LP, the company earned $3.11 per share, beating estimates of $2.59, according to IBES data from Refinitiv.

Smaller rival Valero Energy beat profit estimates on Thursday, thanks to cheap light crude from the prolific U.S. shale oil basins.

“Refining earnings are off to a very strong start with both PSX and VLO beating Street estimates and we expect other refiners especially Marathon Petroleum Corp and HollyFrontier Corp to follow with solid beats,” Credit Suisse analyst Manav Gupta said in a note.

Shares of Phillips 66 were trading up 4% at $115 in early trading. They have gained more than 28% this year to Thursday’s close.

October 18, 2019

Source: Houston Chronicle


The world’s largest oil field service company beat Wall Street expectations on revenue but got stung by pretax charges that resulted in a multibillion loss for stockholders during the third quarter.

Schlumberger posts $11.4 billion loss amid hefty pretax charges - oil and gas 360

Photo: Mayra Beltran

Schlumberger reported a $11.4 billion loss on $8.54 billion of revenue during the third quarter, which translated into a loss per share of $8.22 for common stockholders. The figures were mixed compared to Wall Street expectations of $8.5 billion in revenue and earnings per share of 40 cents.

The company’s third quarter figures were mixed compared to the $659 million of net income, $8 billion of revenue and earnings per share of 47 cents during the third quarter of 2018.

Schlumberger attributed the third quarter loss to $12.7 billion of pretax charges for the impairment of goodwill, intangible assets and fixed assets. Out of those figures, $8.8 billion were attributed to company-wide goodwill charges while another $1.6 billion was specifically attributed to the company’s North American hydraulic fracturing business.

Without those charges, the company made earnings per share of 43 cents — beating Wall Street expectations of 40 cents per share. In a statement, Schlumberger CEO Olivier Le Peuch focused on the year-over-year revenue growth but acknowledged challenges in the North American market.

“Sustained international activity drove overall growth despite mixed results in North America,” Le Peuch said. “The North America business saw strong offshore sales with minimal growth on land due to slowing activity and further pricing weakness.”

Headquartered in Paris with its principal offices in Houston, Schlumberger is the largest oilfield service company in the world with more than 100,000 employees in 85 nations.

The company posted a $2.2 billion profit on $32.8 billion of revenue in 2018.

July 18, 2019

By Aaron Vandeford, Managing Director, EnerCom


EnerCom, Inc. has compiled Second quarter earnings per share, revenue, EBITDA and cash flow per share analyst consensus estimates on 95 E&P and 73 Oilfield Service companies in the EnerCom database.

Download EnerCom’s full chart of estimates.

Listen to Q2 earnings calls.

The median E&P company earnings estimate for the quarter ending June 30, 2019, is $0.12 per share compared to actual earnings per share of ($0.03) and $0.33 for Q1’19 and Q4’18, respectively.

The median OilServices company earnings estimate for the quarter ending June 30, 2019, is ($0.03) per share compared to a loss per share of ($0.01) and ($0.11), for Q1’19 and Q4’18, respectively.

 

Energy Commodities

Crude Oil

U.S. crude oil production and lease condensate reached another milestone in April 2019, totaling 12.2 MMBOPD. April 2019 marks the first time that monthly U.S. crude oil production levels surpassed 12 MMBOPD, and this milestone comes less than a year after U.S. crude oil production surpassed 11 MMBOPD August 2018.

At a July 1, 2019 press conference following OPEC’s annual meeting in Vienna, Saudi Arabia’s Minister of Energy, Industry and Mineral Resources Khalid Al-Falih, also the chairman of the Joint Ministerial Monitoring Committee of OPEC+ (OPEC plus non-OPEC countries), said the OPEC+ group had agreed to continue production curtailments for up to nine more months (click here to read more).

Bam! - It’s Earnings Season Again - Oil & Gas 360

Click the above picture to view EnerCom’s interactive dashboard

The average spot price for WTI in Q2 2019 was $59.92 per barrel, up 9.3% from the prior quarter and down 11.6% from the same quarter last year. The five-year strip at July 16, 2019 was $55.50 per barrel.

The median analyst estimate in mid-July for 2019 NYMEX oil was $60.50 per barrel with a high of $69.82 and a low of $55.50 per barrel.

Bam! - It’s Earnings Season Again - Oil & Gas 360

Source: EnerCom Analytics

 

Natural Gas

For April 2019, total natural gas consumption was 72.8 Bcf/d, down 6.6% from the same month last year. Total natural gas production in April 2019 was 109.9 Bcf/d, up 11.4% from the same month last year.

Net injections to working gas totaled 81 Bcf for the week ending July 5. Working natural gas stocks are 2,471 Bcf, which is 13% more than the year-ago level and 5% lower than the five-year average for this week.

Bam! - It’s Earnings Season Again - Oil & Gas 360

Click the above image to view EnerCom’s interactive inventories dashboards

As production of American natural gas has increased, so has exports, leading to the U.S. becoming a net exporter of natural gas in 2017. In 2018, that trend continued, with the U.S. exporting a record of approximately 4 Tcf, while only importing 3 Tcf, the lowest figure since 2015 (click here to read more).

The average spot price for Henry Hub in Q2 2019 was $2.52 per MMBtu, 12.2% lower than the previous quarter and 9.3% higher than the same quarter last year. The five-year strip at July 16, 2019 was $2.65 per MMBtu.

The median analyst estimate in mid-July for 2019 NYMEX Henry Hub was $2.83 per MMBtu with a high of $3.40 and a low of $2.50 per MMBtu.

Bam! - It’s Earnings Season Again - Oil & Gas 360

Source: EnerCom Analytics

 

Rig Count – U.S. Rig Count

The U.S. rig count stood at 958 for the week ended July 12, 2019, down five from the week before and down 96 from the same week last year.

For the week ended July 12, 2019, there were 831 horizontal rigs active in the United States, a decrease of 99 from the same week a year ago. By play and as compared to the same week last year, rig count changes for the week ended July 12, 2019, include Haynesville (+3 rigs), Woodford Shale (-23 rigs), Marcellus (+6 rigs), Williston Basin (-2 rigs), Eagle Ford Shale (-15 rigs), DJ Niobrara (+2 rigs) and Permian Basin (-39 rigs).

Bam! - It’s Earnings Season Again - Oil & Gas 360

Click the above image to access EnerCom’s interactive rig count dashboard

 

 

Expected Themes for Conference Calls

Below are some themes and thoughts we expect to take prominence on the 2019 Q2 conference calls.

E&P Companies:

  • Free cash flow – When can you get there and what will you do with it
  • Potential for M&A activity
  • Well spacing and parent-child issues
  • Oil, gas takeaway capacity
  • Breakevens
  • Differentials
  • Full cycle returns
  • Liquidity, capital market funding and debt maturities
  • Hedge positions
  • Operating efficiencies

 

OilService companies:

  • Margin trends
  • Pricing trends
  • Service cost inflation
  • Infrastructure buildout and bottlenecks (particularly water and sand)
  • Oilfield service equipment utilization rates and the potential for added capacity
  • Global economic outlook
  • S. vs international activity
  • Potential impacts of sanctions and changing trade relationships
  • Maintenance needs

May 1, 2019

More capacity coming: another $3.5 billion of projects now under construction will go into service in 2019

Houston’s Enterprise Products Partners L.P. (stock ticker: EPD, $EPD) reported record net income attributable to limited partners of $1.3 billion, or $0.57 per unit on a fully diluted basis for Q1 2019.

2018’s Q1 net income came in at $901 million, or $0.41 per unit on a fully diluted basis, for comparison. The company said cash flow from operations was $1.2 billion for both the first quarters of 2019 and 2018. Both Adjusted EBITDA and DCF, which exclude the effects of non-cash, mark-to-market earnings, increased 18% to $2.0 billion and $1.6 billion, respectively, the company said.

Jim Teague, CEO of Enterprise’s general partner said his team made it possible for the company to set eleven operational and financial records during the quarter.

Teague said the business saw a benefit from production increases in the Permian and Haynesville shale regions.

All of the Permian’s projected 700,000 BOPD 2019 production volume increase will be exported overseas – Teague

“Our crude oil marine terminals reported record volumes of nearly 900,000 barrels per day in the first quarter of 2019 despite the temporary closure of the Houston Ship Channel. With Permian crude oil volumes forecasted to increase by approximately 700,000 barrels per day in 2019, we believe substantially all of this increase in volumes will be destined for international markets.”

He said that Enterprise expects 300,000 barrels per day of new ethane demand from ethylene facilities on the U.S. Gulf Coast forecasted to begin operations during the remainder of 2019.

“Through April 2019, we placed $1.9 billion of growth capital projects into service. We have another $5.0 billion of major growth assets under construction of which we expect to put $3.5 billion of these projects into service between now and the end of the year.”

These projects include:

  • a third train at the Orla natural gas processing complex in the Permian,
  • a tenth NGL fractionator and an isobutane dehydrogenation (iBDH) plant at our Mont Belvieu complex.
  • crude oil, natural gas, NGL and petrochemical pipelines,
  • natural gas processing plants in the Permian,
  • a second PDH facility, and
  • the Texas deep water crude oil port.

“With the flexibility to self-fund our equity needs and strong balance sheet, we believe these new projects will enable us to increase cash flow per unit and the equity value of our partnership,” Teague said.

Read the full Q1 Earnings Release here.

April 25, 2019

EQT Reports First Quarter 2019 Results

Lilis Energy Achieves First Quarter 2019 Production Guidance and Provides Operational Update

QEP Reports First Quarter 2019 Financial and Operating Results

March 25, 2019

Sinopec’s Net Profit Up Over 20% to RMB 61.6 Billion in 2018

March 14, 2019

2018 Earnings season gets ready for a wrap

As oil and gas earnings are getting ready for the wrap party, a group of middle market producers and a proppant company announced earnings in the past few days, with key points summarized in brief below.

Earnings in Brief: Six E&Ps and a Sand Supplier Announce 2018 Wins, Losses - Oil & Gas 360

Earnings in Brief: Six E&;Ps and a Sand Supplier Announce 2018 Wins, Losses – Oil & Gas 360

Mid-Con Energy Partners

Mid-Con Energy Partners, LP (NASDAQ: MCEP) announced operating and financial results for the fourth quarter and full year ended December 31, 2018.

“2018 was a transformative year for the Partnership,” commented President and CEO, Jeff Olmstead. “We significantly improved our financial position by extending the maturity of our Revolving Credit Facility, increasing the borrowing base amount, reducing total outstanding debt, and reducing our total leverage as calculated by our banks. We closed approximately $23 million in acquisitions, including several properties in our new core area of Wyoming, and expanded our footprint in Oklahoma. This all resulted in production increasing approximately 30% from the first quarter of 2018 compared to the fourth quarter of 2018.

In February 2019, we announced the execution of two agreements to sell substantially all of our Texas assets and to acquire assets in Oklahoma. The net effect of this transaction will be to significantly reduce outstanding debt and to add long-lived, low-decline assets with potential for margin enhancements through operational efficiency to our portfolio. This continues our track record from 2018 of entering into transactions that help strengthen our financial position and lower our base PDP decline rate. The lower PDP decline rate provides us a more stable reserve base, which allows for more operational and financial control, to grow from. Lower decline properties require less capital investment to maintain production and reserves, and provide the flexibility to invest additional free cash flow into development of new reserves and/or into new acquisitions.

Recent Events and 2018 Summary

  • Completed $15.0 million private offering (the “Offering”) of Class B Convertible Preferred Units (“Class B Preferred Units”) on January 31, 2018, to investors led by John Goff. The Partnership used a portion of net proceeds from this Offering to acquire assets in the Powder River Basin(“PRB Acquisitions”) and the remaining approximately $7.2 million to pay down debt.
  • Closed approximately $23 million, after post-close adjustments, in acquisitions during 2018. The acquisitions included entering into a new core area consisting of two basins, the Powder River Basin and the Big Horn Basin, as well as increasing our footprint in Oklahoma. These properties consist of approximately 9,271 MBoe of net total proved reserves as of December 31, 2018 at the standardized measure for pricing approved by the SEC (“SEC pricing”).
  • In February 2019, we executed definitive agreements to sell substantially all of our Eastern Shelf assets in Texas for $60.0 million, and to acquire Oklahoma properties in Osage, Caddo, and Grady counties for $27.5 million, both subject to customary purchase price adjustments. The properties include 10 mature waterflood units and consist of low decline (average PDP decline of less than 5%), long-lived assets with opportunities to both grow production and decrease current operating expenses through operational efficiencies. Net proved developed producing reserves of these Oklahoma properties as of January 1, 2019 were 6.2 MMBoe (96% oil) based on SEC pricing as of January 1, 2019.
  • On December 19, 2018, the Partnership’s borrowing base was increased to $135.0 million as part of the regularly scheduled semi-annual redetermination.
  • We reduced total debt outstanding at December 31, 2018 by $6.0 million, or 6.1%, from December 31, 2017 and in January 2018 the revolving credit facility maturity was extended by two years to November 2020. Compliance Total Leverage, as calculated per our credit agreement, was approximately 3.17x as of December 31, 2018 compared to 3.54x as of December 31, 2017.
  • Fourth quarter 2018 average daily production of 3,663 Boe/d, an increase of 30.8% from first quarter 2018.
  • Lease operating expenses (“LOE”) of approximately $22.5 million, an increase of 8.3% year-over-year.
  • Realized revenues, inclusive of cash settlements from matured derivatives and net premiums, were $59.0 million, an increase of 8.2% year-over-year.
  • Full year net loss of $18.3 million in 2018 compared to a net loss of $27.3 million in 2017.
  • Adjusted EBITDA, a non-GAAP measure, was $25.2 million at December 31, 2018, an increase of 5.7% year-over-year, primarily due to higher oil and gas revenue from an increase in commodity prices.

Earthstone Energy

Earthstone Energy, Inc. (NYSE: ESTE) announced financial and operating results for the fourth quarter and year ended December 31, 2018.

Fourth Quarter 2018 Highlights

  • Revenues of $41.2 million
    • Increased 16% over fourth quarter 2017
  • Average daily production of 10,454 Boepd(1)
    • Increased 15% over fourth quarter 2017 while the oil component increased 27% over fourth quarter 2017
  • Net income of $81.0 million
    • Compared to $5.5 million in fourth quarter 2017
  • Net income attributable to Earthstone Energy, Inc. of $36.1 million, or $1.26 per diluted share
    • Compared to $2.3 million, or $0.09 per diluted share in fourth quarter 2017
  • Adjusted EBITDAX(2)of $23.9 million
    • Increased 8% over fourth quarter 2017

Full Year 2018 Highlights

  • Revenues of $165.4 million
    • Increased by 53% over 2017
  • Average daily production of 9,937 Boepd(1)
    • Increased by 26% over 2017 while the oil component increased 30% over 2017
  • Net income of $95.2 million
    • Compared to a net loss of $44.7 million in 2017
  • Net income attributable to Earthstone Energy, Inc. of $42.3 million, or $1.50 per diluted share
    • Compared to a net loss of $12.5 million, or a $0.53 loss per share in 2017
  • Adjusted EBITDAX(2)(3)of $96.2 million
    • Increased by 59% over 2017

Robert J. Anderson, President of Earthstone, said, “2018 was a very successful year for Earthstone as we keenly focused on operating efficiencies and thereby generated low-cost reserve additions and strong cash margins. We realized significant improvement in every metric including production, revenues and operating expenses, thus driving a 59% increase in Adjusted EBITDAX to $96.2 million for the year. We also increased our proved reserves by 24% with a finding and development cost of only $9.49 per Boe for extensions and discoveries. Considering that we have only been operating in the Midland Basin for less than two years, we are pleased with our accomplishments and the contributions of all of our employees.

“For 2019, we have set high expectations for Earthstone as we build on these successes. Our strong balance sheet, substantial hedge position averaging over $65 per barrel of oil and positive operating margins give us the confidence to increase our capital budget by approximately 25%, allowing us the flexibility to continue to demonstrate the quality of our acreage position through the drill bit.

“We are executing a successful one-rig development program in the Midland Basin and expect to continue our multi-year growth in production, although our 2019 production profile is projected to remain lumpy with a majority of the completions scheduled in the second half of the year. We presently estimate that we will achieve free cash flow in 2020 assuming we maintain our existing pace of development and current commodity prices continue through such time.”


Abraxas Petroleum

Abraxas Petroleum Corporation (NASDAQ:AXAS) reported financial and operating results for the three and twelve months ended December 31, 2018.

Financial Highlights for the Three Months Ended December 31, 2018

The three months ended December 31, 2018 resulted in:

  • Production of 965 MBoe (10,493 Boepd)
  • Revenue of $36.0 million
  • Net income of $55.8 million, or $ 0.34 per share
  • Adjusted net income(a) (excluding certain non-cash items) of $4.1 million, or $ 0.02 per share
  • EBITDA(a)of $20.1 million
  • Adjusted EBITDA per bank loan covenants of $20.1 million(a)

The twelve months ended December 31, 2018 resulted in:Financial Highlights for the Twelve Months Ended December 31, 2018

  • Production of 3.6 MMBoe (9,809 Boepd)
  • Revenue of $149.2 million
  • Net income of $57.8 million, or $ 0.35 per share
  • Adjusted net income(a) (excluding certain non-cash items) of $30.7 million, or $ 0.19 per share
  • EBITDA(a)of $83.9 million
  • Adjusted EBITDA per bank loan covenants of $84.2 million(a)

Williston Basin, North Dakota

Western North Dakota has experienced one of the coldest winters on record. Abraxas has experienced several days when all surface work was shut down due to temperatures and wind chill that put personnel safety and equipment reliability in jeopardy. The Ravin NE Pad is still under production restriction due to a natural gas pipeline installation delay requiring the flaring of all gas production from this pad. The pipeline is scheduled to be in service within the next two weeks at which point we are expecting normal production operations to be resumed. The Abraxas Raven Rig#1 is scheduled to be started up within the next several months to begin drilling operations on the six well Jore Extension Pad.

Delaware Basin, West Texas

In the Delaware Basin of West Texas, the Company has successfully drilled, completed and started flowback on the two well Creosote Pad in Ward County, where Abraxas now owns an approximate 95% working interest. The Wolfcamp A-1 and A-2 were targeted with a 26 stage fracture treatment (frac) in 5,000’ laterals. The one well Hackberry pad has been successfully drilled and a 26 stage fracture treatment in the Wolfcamp A-1 is scheduled to start next Monday. Abraxas owns an approximate 75% working interest in this 5,000’ lateral well located in Winkler County. The Company is currently drilling a two well pad, Woodberry, in which we own a 100% working interest. The Woodberry Pad adjoins our Caprito block in Ward County.

Year End 2018 Reserves

The Company’s total proved reserves at December 31, 2018 were 67.2 million barrels of oil equivalent (MMBOE), an increase of 2.8% over year end 2017 after production of 3.6 MMBOE and property divestitures of 3.8 MMBOE. The SEC PV10 (a non-GAAP measure) was approximately $689 million. SEC pricing was $65.56 per barrel for oil and $3.03 per mcf for gas. Proved developed reserves were 24.6 MMBOE, or 37% of the total. Oil represented 63% of total proved reserves, natural gas 22%, and natural gas liquids 15%.


Midstates Petroleum

Midstates Petroleum Company, Inc. (NYSE: MPO) announced fourth quarter and full year 2018 results.

Fourth Quarter and Full-Year 2018 Highlights and Recent Key Items

  • Reported net income of $49.8 million, or $1.91 per share, for the full year 2018 and net income of $35.8 million, or $1.38 per share, in the fourth quarter 2018
  • Announced year-end 2018 SEC proved reserves of 72.4 million barrels of oil equivalent (MMBoe) with a net present value discounted at 10% (PV-10) of approximately $580 million
    • Year-end 2018 SEC proved developed producing (PDP) reserves of 46.5 MMBoe with a PV-10 of approximately $425 million
  • Achieved Mississippian Lime production of 16,747 barrels of oil equivalent per day (Boepd) for the full year 2018
  • Generated Adjusted EBITDA of $27.8 million in the fourth quarter of 2018, outpacing quarterly operational capital expenditures by approximately $24.2 million; full-year 2018 Adjusted EBITDA totaled $116.4 million, approximately $19.9 million higher than full-year operational capital expenditures
  • Initiated a process pursuing all strategic and opportunistic transactions that create significant shareholder value
  • Completed workforce reduction in January 2019 to better align general and administrative costs (G&A) with current activity levels; reduced Adjusted Cash G&A expense by $4 million to $5 million annually (excluding one-time severance costs)
  • Successfully executed $50 million tender offer for outstanding capital stock in February 2019, returning capital to shareholders

For the fourth quarter of 2018, Midstates reported net income of $35.8 million, or $1.38 per share, which included the impact of a $25.4 million gain related to the Company’s commodity derivative contracts. In the same period in 2017, the Company reported a net loss of $121.0 million, or ($4.78) per share, including the impact of a $5.1 million commodity derivative charge, and in the third quarter of 2018 reported net income of $11.5 million, or $0.44 per share, including the impact of a $6.6 million commodity derivative charge. For the full year 2018, Midstates reported net income of $49.8 million, or $1.91 per share, which included the impact of a $3.6 million gain related to the Company’s commodity derivative contracts, compared to a net loss of $85.1 million, or ($3.39) per share, including the impact of a $3.7 million gain related to the Company’s commodity derivative contracts, in 2017.

In the fourth quarter of 2018, Midstates generated Adjusted EBITDA of $27.8 million, excluding advisory fees and costs incurred for strategic reviews. This compares to $33.9 million for the same quarter in 2017 and $31.9 million for the third quarter of 2018. For the full year 2018, Midstates generated Adjusted EBITDA of $116.4 million, excluding advisory fees and costs incurred for strategic reviews, compared to $128.2 million, in 2017.

David Sambrooks, President and Chief Executive Officer, commented, “In 2018 we continued our strong operational results and strengthened Midstates financially through several notable accomplishments. Operationally, we optimized base production through a substantial workover program and have taken actions to drive down lease operating and overhead expenses to help maximize margins and grow value. Midstates generated $116.4 million in Adjusted EBITDA, outpacing our operational capex by $20 million and we monetized a portion of our portfolio by selling our non-core Anadarko asset, using the proceeds and free cash flow to pay down $105 million in debt during 2018.

“We are forecasting significant free cash flow generation in 2019, which allowed us to successfully execute a $50 million tender offer earlier this year and affords us the opportunity to consider multiple options moving forward, including returning a substantial portion of our excess cash to our shareholders. As we look to the future, we remain committed to optimizing our production, minimizing costs and operating efficiently, as well as actively pursuing all opportunities that enhance us financially and operationally.”

Operational Update

Midstates ceased drilling at the end of the third quarter of 2018 in order to further study the production results of its recent extended lateral wells. With the erosion of commodity prices in the fourth quarter of 2018, the Company elected to continue the pause in drilling through mid-year 2019 to maximize free cash flow generation from its producing properties and will evaluate future development plans as the Company moves forward.

The Company did not bring online any new saltwater disposal injection wells during the fourth quarter of 2018. Midstates is currently operating 11 non-Arbuckle injection wells in Woods and Alfalfa Counties, Oklahoma, with permitted injection capacity of approximately 240,000 barrels of water per day. The Company’s total permitted injection capacity in all formations in Woods and Alfalfa Counties, Oklahoma, which may differ from actual injection capacity due to operational constraints, is approximately 372,000 barrels of water per day. The Company’s current disposal rate into all formations is approximately 135,000 barrels of water per day. Approximately 45% of the Company’s water injection is currently being injected into non-Arbuckle formations.

Production and Pricing

Production during the fourth quarter of 2018 totaled 16,351 Boepd, compared with 17,996 Boepd during the third quarter of 2018. Oil volumes comprised 27% of total production, natural gas liquids (NGLs) 26%, and natural gas 47% during the fourth quarter of 2018. Production for the full year 2018 totaled 20,326 Boepd, compared with 22,148 Boepd for the full year 2017. Production from the Company’s Mississippian Lime properties contributed approximately 82%, or 16,747 Boepd, and the Anadarko Basin properties contributed approximately 18%, or 3,579 Boepd. Midstates divested its Anadarko Basin properties in the second quarter of 2018. For the total Company, oil volumes comprised 29% of total production, natural gas liquids (NGLs) 25%, and natural gas 46% for the full year 2018.


Oryx Petroleum

Oryx Petroleum Corporation Limited announced its financial and operational results for the year ended December 31, 2018. All dollar amounts set forth in this news release are in United States dollars, except where otherwise indicated.

2018 Financial Highlights:

  • Total revenues of $97.6 million on working interest sales of 1,542,300 barrels of oil (“bbl”) and an average realised sales price of $57.00/bbl for 2018
    • 160% annual increase in revenues versus 2017
    • Q4 2018 revenues increased 24% versus Q3 2018
    • The Corporation has received full payment in accordance with production sharing contract entitlements for all oil sale deliveries into the Kurdistan Region Export Pipeline through November 2018
  • Operating expenses of $19.2 million ($12.48/bbl) and an Oryx Petroleum Netback1of $21.68/bbl
    • 37% decrease in operating expenses per barrel versus 2017
  • Profit of $43.8 million ($0.09 per common share) in 2018 versus loss of $39.1 million in 2017 ($0.11 per common share)
    • Improvement primarily attributable to higher netback and impairment reversal
  • Net cash generated by operating activities was $8.1 million versus net cash used in operating activities of $9.7 million in 2017 comprised of Operating Funds Flow2of $23.2 million partially offset by a $15.1 millionincrease in non-cash working capital
  • Net cash used in investing activities during 2018 was $32.8 million including payments related to drilling and facilities work in the Hawler license area, seismic processing and interpretation costs in the AGC Central license area, and partially offset by a decrease in non-cash working capital
  • $14.4 million of cash and cash equivalents as of December 31, 2018

2018 Operations Highlights:

  • Average gross (100%) oil production of 6,500 bbl/d (working interest 4,200 bbl/d) for the year ended December 31, 2018 vs 3,300 bbl/d (working interest 2,100 bbl/d) for the year ended December 31, 2017
    • 97% increase in gross (100%) oil production in 2018 versus 2017; 46% increase in gross (100%) oil production in Q4 2018 versus Q3 2018
    • Successful completion of six producing wells during the year
    • Commencement of production from the Tertiary and Cretaceous reservoirs at the Banan field
  • Gross (working interest) proved plus probable oil reserves of 127 million barrels as at December 31, 2018
    • 4% increase versus 2017
  • Processing and interpretation of 3D seismic data covering the AGC Central license area completed with prospects remapped and ranked
    • Best estimate unrisked gross (working interest) prospective oil resources of 2.2 billion barrels as at December 31, 2018

2019 Operations Update:

  • Average gross (100%) oil production of 11,400 bbl/d (working interest 7,400 bbl/d) and 9,800 bbl/d (working interest 6,300 bbl/d) in January and February 2019, respectively. Production in February was curtailed for a number of days due to a temporary shut-down of the Kurdistan Region Export Pipeline.
  • The Banan-6 appraisal well targeting the Cretaceous reservoir is expected to be spudded in the coming days. The well is expected to be drilled to a measured depth of 1,840 metres and completed as a producing well.
  • Final prospect ranking has been completed in the AGC Central license area with an environmental impact assessment planned for 2019 with preparation for drilling in 2020 to follow

 Oryx Petroleum’s Chief Executive Officer, Vance Querio, said, “2018 was a good year for Oryx Petroleum. During the year we substantially increased production from the Hawler license area thanks to the successful completion of six new producing wells, increasing production from the Zey Gawra Cretaceous reservoir and commencing production from both the Cretaceous and Tertiary reservoirs in the Banan field.

“We continued to refine our prospect inventory in the AGC Central license area with the remapping of 23 prospects in six structures. We have also identified and ranked a series of wells that will allow us to start exploring the license that has best estimate unrisked gross (working interest) prospective oil resources of 2.2 billion barrels.”


Chaparral Energy

Chaparral Energy, Inc. (NYSE: CHAP) announced its fourth quarter and full year 2018 financial and operational results with the filing of its form 10-K. The company will hold its financial and operating results call this morning, March 14 at 9 a.m. Central.

2018 Highlights

  • Recorded 2018 full year STACK production of 14.5 thousand barrels of oil equivalent per day (MBoe/d), representing a 52% year-over-year increase
  • Achieved 2018 full year total company production of 20.5 MBoe/d
  • Reported full year 2018 net income of $33.4 million, or 73 cents per diluted share
  • Achieved full year 2018 adjusted EBITDA, as defined below, of $125 million
  • Grew 2018 total proved reserves to 94.8 million barrels of oil equivalent (MMBoe), which adjusted for 2018 divestitures marks a 35% year-over-year increase, and represents a PV-10 value of $686 million
  • Increased STACK proved reserves by 50% year-over-year to 74.1 MMBoe, while replacing 519% of STACK production
  • Invested $194.7 million in STACK drilling and completion (D&C) activities in 2018
  • Reduced total company lease operating expense per barrel of oil equivalent (LOE/Boe) almost $4 from $10.96 in 2017 to $7.24 in 2018
  • Strengthened the balance sheet by issuing $300 million of unsecured senior notes and increasing the borrowing base to $325 million in 2018

“Our team is extremely proud of all we accomplished in 2018,” said Chief Executive Officer Earl Reynolds. “From strategically adding to our STACK acreage position to uplisting to the New York Stock Exchange to successfully completing a $300 million senior notes offering and increasing our borrowing base, we were able to increase the value of our assets while also strengthening our balance sheet. In addition, our outstanding operational and drilling results allowed us to significantly grow production and reserves in 2018.”

“While we continue to monitor market conditions and plan to be flexible with our capital expenditures, our current plan for 2019 is to invest $275 to $300 million in capital, more than 80% of which is dedicated to low-cost, high-return STACK/Merge D&C activity. “

Operational Update – STACK Production Soars in 2018

Chaparral increased its STACK production to 16.6 MBoe/d during the fourth quarter, which is up 6% as compared to the previous quarter. Full year STACK production grew by 52% to 14.5 MBoe/d compared to the previous year. Total company production was 21.7 MBoe/d during the fourth quarter, which is a 2% quarter-over-quarter increase. Total company production for the full year was 20.5 MBoe/d, which represents an 11% decrease from the previous year. Excluding production from divested EOR assets in 2017, total company production increased by 13% on a year-over-year basis. Total company production for 2018 was 36% oil, 25% natural gas liquids (NGLs) and 39% natural gas.


Smart Sand

  • 4Q and full year 2018 revenue of $52.2 million and $212.5 million, respectively.
  • 4Q and full year 2018 total tons sold of approximately 610,000 and 2,995,000, respectively.
  • 4Q and full year 2018 net (loss) income of $(4.4) million and $18.7 million, respectively.
  • 4Q and full year 2018 Adjusted EBITDA of $18.7 million and $66.0 million, respectively.

Smart Sand, Inc. (NASDAQ: SND), a producer of high quality Northern White raw frac sand and provider of proppant logistics solutions through both our in-basin transloading terminal and wellsite storage solutions, announced results for the fourth quarter and full year ended December 31, 2018.

Charles Young, Smart Sand’s Chief Executive Officer, stated, “Smart Sand had a good quarter and we’ve responded well to the challenging conditions in the fourth quarter. We recently contracted two sets of last mile storage solutions and have two additional sets ready to be deployed. Our investment in the Van Hook terminal in the Bakken is a strong contributor to our operating performance. We remained focused on our long-term objectives and we’ve proven that we’re profitable through all operating cycles with consistent results of operations. Looking forward, we plan to stay the course in continuing to execute on our already-profitable plan to provide long-term value to the Company, our employees, our customers, and our shareholders.”

Full Year 2018 Highlights

Revenues of $212.5 million for the full year 2018 were the highest in the history of the Company representing a 55% increase over full year 2017 revenue of $137.2 million.  The increase in revenues was primarily due to higher sales volumes resulting from increased exploration and production activity, higher average selling prices of proppant due to increased in-basin sales generated from our Van Hook terminal in the Bakken and favorable price adjustments under certain take-or-pay contracts based on the Average Cushing Oklahoma WTI Spot prices.

Overall tons sold were approximately 2,995,000 in the full year 2018, compared to full year 2017 volume of 2,449,000 tons. Tons sold increased by 22.3% due to increased exploration and production activity in the oil and natural gas industry in 2018 compared to 2017.

Net income was $18.7 million, or $0.46 per basic share and $0.46 per diluted share, for the full year 2018, compared with net income of $21.5 million, or $0.54 per basic share and $0.53 per diluted share, for the full year 2017, a decrease of 13% year over year.

 

 


Legal Notice