February 19, 2019 - 6:00 AM EST
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Enable Midstream Announces Fourth Quarter and Full-Year 2018 Financial and Operating Results

OKLAHOMA CITY

  • Achieved an all-time high for quarterly natural gas gathered, natural gas processed and crude oil and condensate gathered volumes
  • Increased net income attributable to limited partners, Adjusted EBITDA and distributable cash flow (DCF) for fourth quarter and full-year 2018 compared to fourth quarter and full-year 2017
  • Exceeded full-year 2018 outlook for net income attributable to common units, Adjusted EBITDA, DCF and distribution coverage
  • Contracted or extended over 600,000 dekatherms per day (Dth/d) of transportation capacity during the fourth quarter, including recontracting with Oklahoma Gas & Electric Company (OG&E) for over 300,000 Dth/d of firm transportation service

Enable Midstream Partners, LP (NYSE: ENBL) today announced financial and operating results for fourth quarter and full-year 2018.

Net income attributable to limited partners was $174 million for fourth quarter 2018, an increase of $66 million compared to $108 million for fourth quarter 2017. Net income attributable to common units was $165 million for fourth quarter 2018, an increase of $66 million compared to $99 million for fourth quarter 2017. Net cash provided by operating activities was $286 million for fourth quarter 2018, an increase of $8 million compared to $278 million for fourth quarter 2017. Adjusted EBITDA for fourth quarter 2018 was $271 million, an increase of $33 million compared to $238 million for fourth quarter 2017. DCF for fourth quarter 2018 was $173 million, an increase of $27 million compared to $146 million for fourth quarter 2017.

Net income attributable to limited partners was $521 million for full-year 2018, an increase of $85 million compared to $436 million for full-year 2017. Net income attributable to common units was $485 million for full-year 2018, an increase of $85 million compared to $400 million for full-year 2017. Net cash provided by operating activities was $924 million for full-year 2018, an increase of $90 million compared to $834 million for full-year 2017. Adjusted EBITDA for full-year 2018 was $1,074 million, an increase of $150 million compared to $924 million for full-year 2017. DCF for full-year 2018 was $760 million, an increase of $100 million compared to $660 million for full-year 2017.

For fourth quarter 2018, DCF exceeded declared distributions to common unitholders by $35 million, resulting in a distribution coverage ratio of 1.26. For full-year 2018, DCF exceeded declared distributions to common unitholders by $208 million, resulting in a distribution coverage ratio of 1.38.

Enable uses derivatives to manage commodity price risk, and the gain or loss associated with these derivatives is recognized in earnings. Enable’s net income attributable to limited partners and net income attributable to common units for fourth quarter 2018 includes a $49 million gain on derivative activity, compared to a $4 million loss on derivative activity for fourth quarter 2017, resulting in an increase in net income of $53 million. The increase of $53 million is comprised of an increase related to the change in fair value of derivatives of $55 million and an increase in realized loss on derivatives of $2 million. Enable’s net income attributable to limited partners and net income attributable to common units for full-year 2018 includes an $11 million gain on derivative activity, compared to a $19 million gain on derivative activity for full-year 2017, resulting in a decrease in net income of $8 million. The decrease of $8 million is comprised of a decrease related to the change in fair value of derivatives of $2 million and an increase in realized loss on derivatives of $6 million. Additional details on derivative instruments and hedging activities can be found in Enable’s Annual Report on Form 10-K for the year ended Dec. 31, 2018.

For additional information regarding the non-GAAP financial measures Gross margin, Adjusted EBITDA and DCF, please see “Non-GAAP Financial Measures.”

MANAGEMENT PERSPECTIVE

“Enable executed at a high level in 2018, with record natural gas and crude oil gathered volumes and natural gas processed volumes, which drove financial performance that outpaced 2017,” said Rod Sailor, president and CEO. “We expanded our footprint by completing cost-effective, customer-focused expansion projects and strengthened our foundation for the long term with our acquisition of the Velocity system and announcement of the Gulf Run Pipeline project. For 2019, we will remain a disciplined operator, focused on our customers, deploying capital efficiently and building value for unitholders.”

BUSINESS HIGHLIGHTS

During fourth quarter 2018, per-day natural gas gathered volumes grew for the 12th consecutive quarter as a result of strong rig activity across Enable’s footprint. During fourth quarter 2018, Enable also achieved the highest per-day crude oil and condensate gathered volumes since its formation in May 2013. As of Feb. 12, 2019, there were fifty-four rigs across Enable’s footprint that were drilling wells expected to be connected to Enable’s gathering systems. Forty of those rigs were in the Anadarko Basin, nine were in the Ark-La-Tex Basin, two were in the Arkoma Basin and three were in the Williston Basin.

During fourth quarter 2018, Enable contracted or extended 600,000 Dth/d of transportation capacity, bringing total 2018 contracting to over 2,000,000 Dth/d. On the Enable Oklahoma Intrastate Transmission, LLC (EOIT) system, EOIT recontracted with its largest customer, OG&E, for five years of approximately 336,000 Dth/d firm transportation service. With this contract and EOIT's 228,000 Dth/d contract to serve OG&E's Muskogee Power Plant, Enable will provide over 550,000 Dth/d of firm transportation capacity to OG&E. During fourth quarter 2018, Enable placed the Muskogee project in service on time and under budget and, as previously announced, placed the CaSE project into full service.

The rate case originally filed by Enable Mississippi River Transmission, LLC (MRT) June 29, 2018, continues to advance at the Federal Energy Regulatory Commission (FERC). As of Jan. 1, 2019, MRT’s proposed rate increase is being billed to customers, subject to refund depending upon the outcome of the case. MRT remains focused on ensuring that the pipeline’s rates appropriately reflect historical investments and current costs.

On Nov. 8, 2018, Southeast Supply Header, LLC (SESH), Enable’s joint venture with Enbridge Inc., filed FERC Form 501-G, a one-time report required by the FERC in response to the reduction in the income tax rate and the Commission’s Revised Policy Statement on Master Limited Partnerships. SESH stated in the 501-G filing that it would submit a limited Natural Gas Act (NGA) section 4 filing to reduce its maximum tariff rates by 3.1 percent. The rate reduction is not expected to impact SESH’s current revenues, and current contract rates are significantly below the new maximum tariff rates. On Dec. 20, 2018, the Commission accepted SESH’s revised tariff records effective Jan. 1, 2019, as proposed, and found that SESH will not be subject to an NGA section 5 investigation for three years from the date the proposed rate reduction became effective, that is, from Jan. 1, 2019, through Jan. 1, 2022.

On Feb. 5, 2019, Enable announced that an affiliate of Golden Pass LNG (Golden Pass) is the cornerstone shipper for the Gulf Run Pipeline project. Enable’s announcement followed an announcement from Golden Pass that it had made a positive final investment decision for the liquefied natural gas (LNG) facility to be served by the Gulf Run Pipeline project. Golden Pass is a joint venture between affiliates of Qatar Petroleum and ExxonMobil. Following the final investment decision from Golden Pass and its 20-year cornerstone shipper commitment, Enable plans to continue advancing the project to meet the anticipated late 2022 in-service date, including filing for the required FERC approval.

On Jan. 29, 2019, Enable announced that it had entered into a $1 billion three-year unsecured term loan agreement. Enable has initially borrowed $200 million under the agreement, and a delayed-draw feature provides Enable the flexibility to make up to $800 million in additional borrowings for up to 180 days from Jan. 29, 2019. Under the term loan agreement, Enable can borrow at an interest rate based on the London Interbank Offered Rate (LIBOR) plus an incremental rate determined by Enable's credit ratings. The incremental rate for LIBOR borrowings is currently 125 basis points, 25 basis points less than the current incremental borrowing rate for LIBOR borrowings under Enable's revolving credit facility. The term loan can be prepaid at any time, in whole or in part, without penalty and includes two, one-year extension options, subject to lender approval. The term loan also contains substantially the same covenants as those contained in Enable's existing revolving credit agreement.

2019 OUTLOOK

Enable reaffirms the 2019 outlook presented in its third quarter 2018 financial results press release dated Nov. 7, 2018.

KEY OPERATING STATISTICS

Natural gas gathered volumes were 4.62 trillion British thermal units per day (TBtu/d) for fourth quarter 2018, an increase of 12 percent compared to 4.11 TBtu/d for fourth quarter 2017. The increase was primarily due to higher gathered volumes in the Anadarko and Ark-La-Tex Basins.

Natural gas processed volumes were 2.57 TBtu/d for fourth quarter 2018, an increase of 19 percent compared to 2.16 TBtu/d for fourth quarter 2017. The increase was primarily due to higher processed volumes in the Anadarko Basin.

NGLs produced were 136.74 thousand barrels per day (MBbl/d) for fourth quarter 2018, an increase of 26 percent compared to 108.18 MBbl/d for fourth quarter 2017. The increase was primarily due to higher natural gas processed volumes and increased recoveries of ethane.

Crude oil and condensate gathered volumes were 76.59 MBbl/d for fourth quarter 2018, an increase of 165 percent compared to 28.86 MBbl/d for fourth quarter 2017. The increase was primarily due to the recent acquisition of Velocity Holdings, LLC's crude oil and condensate gathering system in the Anadarko Basin (the Velocity Acquisition).

Interstate transportation firm contracted capacity was 6.24 Bcf/d for fourth quarter 2018, an increase of 8 percent compared to 5.79 Bcf/d for fourth quarter 2017. The increase was primarily due to new contracted capacity on Enable Gas Transmission, LLC (EGT), including volumes from EGT’s CaSE project.

Intrastate transportation average deliveries were 2.21 TBtu/d for fourth quarter 2018, an increase of 14 percent compared to 1.94 TBtu/d for fourth quarter 2017. The increase was primarily related to increased gathered volumes in the Anadarko Basin.

FOURTH QUARTER FINANCIAL PERFORMANCE

Revenues were $950 million for fourth quarter 2018, an increase of $144 million compared to $806 million for fourth quarter 2017. Revenues are net of $183 million of intercompany eliminations for fourth quarter 2018 and $163 million of intercompany eliminations for fourth quarter 2017.

  • Gathering and processing segment revenues were $808 million for fourth quarter 2018, an increase of $151 million compared to $657 million for fourth quarter 2017. The increase in gathering and processing segment revenues was primarily due to an increase in revenues from changes in the fair value of natural gas, condensate and NGL derivatives, an increase in revenues from natural gas sales due to higher sales volumes inclusive of an increase due to the implementation of Accounting Standards Codification 606 (Revenue From Contracts With Customers) (ASC 606), an increase in processing service revenues resulting from higher processed volumes primarily under fixed processing arrangements in the Anadarko Basin, inclusive of an increase due to the implementation of ASC 606, an increase in revenues from NGL sales resulting from higher processed volumes and increased recoveries of ethane in the Anadarko Basin, inclusive of a decrease due to the implementation of ASC 606, partially offset by lower average NGL prices, an increase in natural gas gathering revenues due to higher fees and gathered volumes in the Anadarko and Ark-La-Tex Basins, inclusive of a decrease due to the implementation of ASC 606, and an increase in crude oil and condensate gathering revenues due to the Velocity Acquisition. These increases were partially offset by a decrease in revenues due to an intercompany management fee.
  • Transportation and storage segment revenues were $325 million for fourth quarter 2018, an increase of $13 million compared to $312 million for fourth quarter 2017. The increase in transportation and storage segment revenues was primarily due to an increase in revenues from firm transportation and storage services due to new interstate and intrastate transportation contracts, an increase in volume-dependent transportation revenues driven by an increase in commodity fees from new contracts, an increase in off-system transportation due to increases in volumes at higher rates and from natural gas sales primarily due to higher sales prices. These increases were partially offset by a decrease in revenues from natural gas sales primarily due to the implementation of ASC 606.

Gross margin was $466 million for fourth quarter 2018, an increase of $105 million compared to $361 million for fourth quarter 2017. Gross margin is net of $2 million of intercompany eliminations for fourth quarter 2018 and $3 million for fourth quarter 2017.

  • Gathering and processing segment gross margin was $329 million for fourth quarter 2018, an increase of $94 million compared to $235 million for fourth quarter 2017. The increase in gathering and processing segment gross margin was primarily due to an increase in gross margin from changes in the fair value of natural gas, condensate and NGL derivatives, an increase in processing service fees due to higher processed volumes primarily under fixed processing arrangements in the Anadarko Basin, inclusive of an increase due to the implementation of ASC 606, an increase in natural gas gathering fees due to higher fees and gathered volumes in the Anadarko Basin, inclusive of a decrease due to the implementation of ASC 606, an increase in revenues from NGL sales less the cost of NGLs primarily driven by higher processed volumes in the Anadarko and Ark-La-Tex Basins, partially offset by lower average NGL prices, inclusive of a decrease due to the implementation of ASC 606, and an increase in crude oil and condensate gathering revenues due to the Velocity Acquisition. These increases were partially offset by a decrease in revenues from natural gas sales less the cost of natural gas primarily due to an increase in fuel costs due to higher gathered volumes, inclusive of an increase due to the implementation of ASC 606.
  • Transportation and storage segment gross margin was $135 million for fourth quarter 2018, an increase of $6 million compared to $129 million for fourth quarter 2017. The increase in transportation and storage segment gross margin was primarily due to an increase in firm transportation and storage services due to new interstate and intrastate transportation contracts and an increase in gross margin from volume-dependent transportation primarily due to an increase in commodity fees from new contracts and an increase in off-system transportation due to increases in volumes at higher rates. These increases were partially offset by a decrease in system management activities.

Operation and maintenance and general and administrative expenses were $131 million for fourth quarter 2018, an increase of $15 million compared to $116 million for fourth quarter 2017. Operation and maintenance and general and administrative expenses are net of $1 million of intercompany eliminations in fourth quarter 2018 and net of $2 million of intercompany eliminations in fourth quarter 2017. The increase in operation and maintenance and general and administrative expenses was primarily due to an increase in expenses related to maintenance on treating plants as a result of increased Ark-La-Tex Basin activity, an increase in compressor rental expenses due to increased rental units, an increase in materials and supplies and contract services costs as a result of additional assets in service and an increase acquisition-related costs. These increases were partially offset by a decrease in payroll-related costs.

Depreciation and amortization expense was $106 million for fourth quarter 2018, an increase of $7 million compared to $99 million for fourth quarter 2017. The increase in depreciation and amortization expense was primarily due to the Velocity Acquisition in fourth quarter 2018 and additional assets placed in service.

Taxes other than income tax were $17 million for fourth quarter 2018 and 2017.

Interest expense was $43 million for fourth quarter 2018, an increase of $12 million compared to $31 million for fourth quarter 2017. The increase was primarily due to an increase in the amount of debt outstanding and higher interest rates on outstanding debt as a result of a long-term debt issuance in May 2018, the proceeds of which were used for the repayment of the remaining amount outstanding under Enable’s 2015 term loan agreement and additional amounts outstanding under its commercial paper program.

Capital expenditures were $620 million for fourth quarter 2018, compared to $464 million for fourth quarter 2017. Expansion capital expenditures were $576 million for fourth quarter 2018, compared to $416 million for fourth quarter 2017. Maintenance capital expenditures were $44 million for fourth quarter 2018 and $48 million for fourth quarter 2017.

QUARTERLY DISTRIBUTIONS

As previously announced, on Feb. 8, 2019, the board of directors of Enable’s general partner declared a quarterly cash distribution of $0.318 per unit on all outstanding common units for the quarter ended Dec. 31, 2018. The distribution is unchanged from the previous quarter. The quarterly cash distribution of $0.318 per unit on all outstanding common units will be paid Feb. 26, 2019, to unitholders of record at the close of business Feb. 19, 2019.

Also, as previously announced, the board declared a quarterly cash distribution of $0.625 per unit on all Series A Preferred Units for the quarter ended Dec. 31, 2018. The quarterly cash distribution of $0.625 per unit on all Series A Preferred Units outstanding was paid Feb. 14, 2019, to unitholders of record at the close of business Feb. 8, 2019.

EARNINGS CONFERENCE CALL AND WEBCAST

A conference call discussing fourth quarter results is scheduled today at 10 a.m. EST (9 a.m. CST). The toll-free dial-in number to access the conference call is 833-535-2200, and the international dial-in number is 412-902-6730. The conference call ID is Enable Midstream Partners. Investors may also listen to the call via Enable’s website at http://investors.enablemidstream.com. Replays of the conference call will be available on Enable’s website.

ANNUAL REPORT

Enable today filed its annual report on the Form 10-K with the U.S. Securities and Exchange Commission.

The Form 10-K is available to view, print or download from the SEC filings page under the Investor Relations section on the Enable Midstream website at http://investors.enablemidstream.com.

Unitholders may order a printed copy of the Form 10-K by contacting Enable Midstream Investor Relations at 405-558-4600 or [email protected].

AVAILABLE INFORMATION

Enable files annual, quarterly and other reports and other information with the U.S. Securities and Exchange Commission (SEC). Enable’s SEC filings are also available at the SEC’s website at http://www.sec.gov which contains information regarding issuers that file electronically with the SEC. Information about Enable may also be obtained at the offices of the NYSE, 20 Broad Street, New York, New York 10005, or on Enable’s website at https://www.enablemidstream.com. On the investor relations tab of Enable’s website, https://investors.enablemidstream.com, Enable makes available free of charge a variety of information to investors. Enable’s goal is to maintain the investor relations tab of its website as a portal through which investors can easily find or navigate to pertinent information about Enable, including but not limited to:

  • Enable’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after Enable electronically files that material with or furnishes it to the SEC;
  • press releases on quarterly distributions, quarterly earnings and other developments;
  • governance information, including Enable’s governance guidelines, committee charters and code of ethics and business conduct;
  • information on events and presentations, including an archive of available calls, webcasts and presentations;
  • news and other announcements that Enable may post from time to time that investors may find useful or interesting; and
  • opportunities to sign up for email alerts and RSS feeds to have information pushed in real time.

ABOUT ENABLE MIDSTREAM PARTNERS

Enable owns, operates and develops strategically located natural gas and crude oil infrastructure assets. Enable’s assets include approximately 13,900 miles of natural gas, crude oil, condensate and produced water gathering pipelines, approximately 2.6 Bcf/d of processing capacity, approximately 7,800 miles of interstate pipelines (including Southeast Supply Header, LLC of which Enable owns 50 percent), approximately 2,300 miles of intrastate pipelines and eight storage facilities comprising 84.5 billion cubic feet of storage capacity. For more information, visit http://www.enablemidstream.com.

NON-GAAP FINANCIAL MEASURES

Enable has included the non-GAAP financial measures Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and distribution coverage ratio in this press release based on information in its consolidated financial statements.

Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and distribution coverage ratio are supplemental financial measures that management and external users of Enable’s financial statements, such as industry analysts, investors, lenders and rating agencies may use, to assess:

  • Enable’s operating performance as compared to those of other publicly traded partnerships in the midstream energy industry, without regard to capital structure or historical cost basis;
  • The ability of Enable’s assets to generate sufficient cash flow to make distributions to its partners;
  • Enable’s ability to incur and service debt and fund capital expenditures; and
  • The viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

This press release includes a reconciliation of Gross margin to total revenues, Adjusted EBITDA and DCF to net income attributable to limited partners, Adjusted EBITDA to net cash provided by operating activities and Adjusted interest expense to interest expense, the most directly comparable GAAP financial measures as applicable, for each of the periods indicated. Distribution coverage ratio is a financial performance measure used by management to reflect the relationship between Enable’s financial operating performance and cash distributions. Enable believes that the presentation of Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and distribution coverage ratio provides information useful to investors in assessing its financial condition and results of operations. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and distribution coverage ratio should not be considered as alternatives to net income, operating income, total revenue, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and distribution coverage ratio have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP measures. Additionally, because Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and distribution coverage ratio may be defined differently by other companies in Enable’s industry, its definitions of these measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

FORWARD-LOOKING STATEMENTS

Some of the information in this press release may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “could,” “will,” “should,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this press release and in our Annual Report on Form 10-K for the year ended Dec. 31, 2018 (“Annual Report”). Those risk factors and other factors noted throughout this press release and in our Annual Report could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements.

Any forward-looking statements speak only as of the date on which such statement is made and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information or otherwise, except as required by applicable law.

       

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 
Three Months Ended December 31, Year Ended December 31,
2018     2017

2018

    2017
(In millions, except per unit data)
Revenues (including revenues from affiliates):
Product sales $ 609 $ 517 $ 2,106 $ 1,653
Service revenue 341   289   1,325   1,150  
Total Revenues 950   806   3,431   2,803  
Cost and Expenses (including expenses from affiliates):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 484 445 1,819 1,381
Operation and maintenance 99 92 388 369
General and administrative 32 24 113 95
Depreciation and amortization 106 99 398 366
Taxes other than income tax 17   17   65   64  
Total Cost and Expenses 738   677   2,783   2,275  
Operating Income 212   129   648   528  
Other Income (Expense):
Interest expense (43 ) (31 ) (152 ) (120 )
Equity in earnings of equity method affiliate 6 7 26 28
Other, net (1 )      
Total Other Expense (38 ) (24 ) (126 ) (92 )
Income Before Income Tax 174 105 522 436
Income tax expense (1 ) (3 ) (1 ) (1 )
Net Income $ 175 $ 108 $ 523 $ 437
Less: Net income attributable to noncontrolling interest 1     2   1  
Net Income Attributable to Limited Partners $ 174 $ 108 $ 521 $ 436
Less: Series A Preferred Unit distributions 9   9   36   36  
Net Income Attributable to Common and Subordinated Units (1) $ 165   $ 99   $ 485   $ 400  
 
Basic earnings per unit
Common units $ 0.38 $ 0.23 $ 1.12 $ 0.92
Subordinated units (1) $ $ $ $ 0.93
Diluted earnings per unit
Common units $ 0.38 $ 0.23 $ 1.11 $ 0.92
Subordinated units (1) $ $ $ $ 0.93

___________________

        (1)   All outstanding subordinated units converted into common units on a one-for-one basis on August 30, 2017.
 
       

ENABLE MIDSTREAM PARTNERS, LP

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

 
Three Months Ended December 31, Year Ended December 31,
2018     2017 2018     2017
(In millions)
Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales $ 609 $ 517 $ 2,106 $ 1,653
Service revenue 341   289   1,325   1,150
Total Revenues 950 806 3,431 2,803
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 484   445   1,819   1,381
Gross margin $ 466   $ 361   $ 1,612   $ 1,422
 
Reportable Segments
Gathering and Processing
Product sales $ 605 $ 494 $ 2,016 $ 1,538
Service revenue 203   163   802     632

Total Revenues

808 657 2,818 2,170
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 479   422   1,741   1,285
Gross margin $ 329   $ 235   $ 1,077   $ 885
 
Transportation and Storage
Product sales $ 183 $ 182 $ 625 $ 621
Service revenue 142   130   537   525
Total Revenues 325 312 1,162 1,146
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 190   183   628   604
Gross margin $ 135   $ 129   $ 534   $ 542
 
       
Three Months Ended December 31, Year Ended December 31,
2018     2017 2018     2017
(In millions, except Distribution coverage ratio)
Reconciliation of Adjusted EBITDA and DCF to net income attributable to limited partners and calculation of Distribution coverage ratio:
Net income attributable to limited partners $ 174 $ 108 $ 521 $ 436
Depreciation and amortization expense 106 99 398 366
Interest expense, net of interest income 43 31 152 120
Income tax expense (1 ) (3 ) (1 ) (1 )
Distributions received from equity method affiliate in excess of equity earnings (4 ) (4 ) 7 5
Non-cash equity-based compensation 4 3 16 15
Change in fair value of derivatives (54 ) 1 (26 ) (28 )
Other non-cash losses (1) 3   3   7   11  
Adjusted EBITDA $ 271 $ 238 $ 1,074 $ 924
Series A Preferred Unit distributions (2) (9 ) (9 ) (36 ) (36 )
Distributions for phantom and performance units (3) (5 ) (2 )
Adjusted interest expense (4) (45 ) (33 ) (159 ) (123 )
Maintenance capital expenditures (44 ) (48 ) (114 ) (101 )
Current income taxes   (2 )   (2 )
DCF $ 173   $ 146   $ 760   $ 660  
 
Distributions related to common and subordinated unitholders (5) $ 138   $ 138   $ 552   $ 551  
 
Distribution coverage ratio 1.26   1.06   1.38   1.20  

___________________

        (1)   Other non-cash losses includes loss on sale of assets and write-downs of materials and supplies.
(2) This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the years-ended December 31, 2018 and 2017. In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available cash with respect to the quarter immediately preceding the quarter in which the distribution is made.
(3) Distributions for phantom and performance units represent distribution equivalent rights paid in cash. Phantom unit distribution equivalent rights are paid during the vesting period and performance unit distribution equivalent rights are paid at vesting.
(4) See below for a reconciliation of Adjusted interest expense to Interest expense.
(5) Represents cash distributions declared for common and subordinated units outstanding as of each respective period. Amounts for 2018 reflect estimated cash distributions for common units outstanding for the quarter ended December 31, 2018.
 
       
Three Months Ended December 31, Year Ended December 31,
2018     2017 2018     2017
(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities $ 286 $ 278 $ 924 $ 834
Interest expense, net of interest income 43 31 152 120
Net income attributable to noncontrolling interest (1 ) (2 ) (1 )
Current income taxes 2 2
Other non-cash items(1) 3 2 7 4
Proceeds from insurance 1 2 2 2
Changes in operating working capital which (provided) used cash:
Accounts receivable (47 ) (44 ) 11 28
Accounts payable (25 ) (70 ) (6 ) (54 )
Other, including changes in noncurrent assets and liabilities 69 40 5 12
Return of investment in equity method affiliate (4 ) (4 ) 7 5
Change in fair value of derivatives (54 ) 1   (26 ) (28 )
Adjusted EBITDA $ 271   $ 238   $ 1,074   $ 924  

____________________

        (1)   Other non-cash items include amortization of debt expense, discount and premium on long-term debt and write-downs of materials and supplies.
 
       
Three Months Ended December 31, Year Ended December 31,
2018     2017 2018     2017
(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest Expense $ 43 $ 31 $ 152 $ 120
Amortization of premium on long-term debt 2 2 6 6
Capitalized interest on expansion capital 2 6
Amortization of debt expense and discount (2 )   (5 ) (3 )
Adjusted interest expense $ 45   $ 33   $ 159   $ 123  
 
       

ENABLE MIDSTREAM PARTNERS, LP

OPERATING DATA

 
Three Months Ended December 31, Year Ended December 31,
2018   2017 2018   2017
Operating Data:
Gathered volumes—TBtu 425 378 1,637 1,300
Gathered volumes—TBtu/d 4.62 4.11 4.48 3.56
Natural gas processed volumes—TBtu (1) 236 199 877 715
Natural gas processed volumes—TBtu/d (1) 2.57 2.16 2.40 1.96
NGLs produced—MBbl/d (1)(2) 136.74 108.18 129.98 90.11
NGLs sold—MBbl/d (1)(2)(3) 145.37 116.27 132.06 92.21
Condensate sold—MBbl/d 5.68 4.91 5.90 4.79
Crude oil and condensate gathered volumes—MBbl/d 76.59 28.86 41.07 25.56
Transported volumes—TBtu 526 455 2,028 1,838
Transported volumes—TBtu/d 5.72 4.95 5.56 5.04
Interstate firm contracted capacity—Bcf/d 6.24 5.79 5.94 6.21
Intrastate average deliveries—TBtu/d 2.21 1.94 2.08 1.88

____________________

        (1)   Includes volumes under third party processing arrangements.
(2) Excludes condensate.
(3) NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.
 
       
Three Months Ended December 31, Year Ended December 31,
2018     2017 2018     2017
Anadarko
Gathered volumes—TBtu/d 2.38 1.99 2.21 1.81
Natural gas processed volumes—TBtu/d (1) 2.14 1.75 1.99 1.61
NGLs produced—MBbl/d (1)(2) 119.92 92.36 113.63 76.37
Crude oil and condensate gathered volumes—MBbl/d 48.17 12.14
Arkoma
Gathered volumes—TBtu/d 0.53 0.54 0.55 0.55
Natural gas processed volumes—TBtu/d (1) 0.10 0.09 0.10 0.09
NGLs produced—MBbl/d (1)(2) 6.56 4.84 6.55 4.79
Ark-La-Tex
Gathered volumes—TBtu/d 1.71 1.58 1.72 1.20
Natural gas processed volumes—TBtu/d 0.33 0.32 0.31 0.26
NGLs produced—MBbl/d (2) 10.26 10.98 9.80 8.95
Williston
Crude oil gathered volumes—MBbl/d 28.42 28.86 28.93 25.56

__________________

        (1)   Includes volumes under third party processing arrangements.
(2) Excludes condensate.
 

Media
David Klaassen
(405) 553-6431

Investor
Matt Beasley
(405) 558-4600


Source: Business Wire (February 19, 2019 - 6:00 AM EST)

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Recent Company Earnings:


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.

 

 

February 26, 2019

Magnolia Oil & Gas Corporation Announces Fourth Quarter and 2018 Year-End Results

Ring Energy Releases Fourth Quarter and Twelve Month 2018 Financial and Operational Results

February 22, 2019

Cabot Oil & Gas Corporation Establishes Several New Full-Year Records, Returns $1.0 Billion to Shareholders, Repays $304 Million of Debt

February 20, 2019

Energy Transfer Reports Fourth Quarter 2018 Results with Record Performance and Continued Growth

February 19, 2019

Noble Energy, Inc. (NYSE:NBL) Chairman and CEO David Stover said today that the oil and gas industry needs to prioritize capital discipline and corporate returns over top-line production growth.

“Our 2019 capital program and early 2020 outlook aligns capital investment with the environment and sets the stage for Noble Energy to generate sustainable organic free cash flow in 2020 and beyond,” Stover said.

Stover said Noble’s U.S. onshore business is anticipated to be self-funding by the end of 2019 and will underpin the company’s production growth of five to ten percent per year, before the additional impact of major projects.

“We will be completing spend for Leviathan, offshore Israel, this year and commencing production and cash flow from the project by the end of the year,” Stover said in a statement.

“Our early 2020 outlook provides over $500 million in free cash flow(1) at strip pricing, which we plan to return to shareholders through the dividend and share repurchase program.”

Highlights from the company’s 2019 plan include:

  • Organic capital expenditures funded by Noble Energy are planned at a range of $2.4 to $2.6 billion, 17 percent lower at the midpoint compared to 2018.
  • Total company volumes are anticipated in the range of 345-365 MBoe/d, an increase of 5 percent(3)at the midpoint as compared to 2018.
  • The Company’s U.S. onshore business is anticipated to deliver asset-level free cash flow(2)by the end of 2019, while delivering total volume growth of approximately 10 percent(3) and oil production growth of 13 percent(3) from 2018 levels.
  • First gas sales from Leviathan are expected by the end of 2019, delivering substantial production and cash flow growth in 2020.

 

Noble’s plans for organic capital expenditures by area (in $MM) are estimated to be:

United States Onshore 1,600 – 1,700
NBL-funded Midstream 100 – 125
Eastern Mediterranean 550 – 600
West Africa 100 – 125
Other 50
Total 2,400 – 2,600

Sixty percent of the Company’s total organic capital for 2019 is expected to be spent in the first half of the year due to the timing of Leviathan spend and U.S. onshore activity. Excluded from the amounts above is an estimated $195 million of Noble Midstream Partners’ (NYSE: NBLX) capital, which will be consolidated into Noble Energy. Third-party customer activity represents 65 percent of the NBLX capital.

U.S. Onshore

Approximately 90 percent of Noble Energy’s U.S. onshore capital will be focused in the DJ and Delaware Basins. Activity in the DJ Basin includes progressing the second row of development in Mustang, which benefits from the Company’s approved Comprehensive Drilling Plan and access to multiple gas processing providers. In addition, Noble Energy expects to bring online a number of pads within Wells Ranch and East Pony. In the Delaware, operated activity is focused on row development primarily in the Wolfcamp A and Third Bone Spring zones. The Company will continue to optimize base production and cash flows from the Eagle Ford.

Noble Energy expects to commence production in 2019 on between 165-175 wells across the U.S. onshore, including 95-100 in the DJ Basin, 50-55 in the Delaware Basin and approximately 20 in the Eagle Ford. The second and third quarter are planned to have a higher count of wells commencing production as compared to the first and fourth quarters of the year.

The Company anticipates full-year 2019 average U.S. onshore sales volumes of between 262 and 278 thousand barrels of oil equivalent per day (MBoe/d). Combined, production from the DJ and Delaware Basins is expected to increase throughout 2019, up 15 to 20 percent(3) on a full year basis. Sales volumes in the Eagle Ford are anticipated to be lower on a full year basis, with volumes growing from the first half to the second half of the year.

Compared to the second half of 2018, Noble Energy expects capital costs per well in 2019 to be lower by 10 to 15 percent. The majority of these costs savings have been realized through operational efficiencies and lower service costs.

International Offshore

Offshore, the Company is focused on maintaining its strong base production and cash flow in Israel and Equatorial Guinea (E.G.), while progressing the Leviathan project offshore Israel for first gas sales by the end of the year. In addition, Noble Energy expects to sanction the Alen gas monetization project in E.G. in the first half of 2019, with first gas sales estimated for the first half of 2021.

In Israel, gross natural gas sales volumes are anticipated to be flat to up slightly from 2018, reflecting the nearly fully utilized capacity of the Tamar field on an annual basis. Organic capital expenditures in the Eastern Mediterranean primarily comprise spending to complete the Leviathan project. Excluded from the Company’s organic capital expenditures guidance are costs related to an acquisition of interest in the EMG pipeline, which provides a connection point for the export of natural gas from Israel to Egypt.

In E.G., sales volumes are expected to be lower than 2018 due to natural field declines through the year and anticipated downtime for the third-party LNG facility turnaround in the first quarter. The Company’s 2019 capital expenditure guidance includes initial costs for the Alen gas monetization project as well an additional development well at the Aseng oil field to help mitigate field decline. First production from the Aseng development well is anticipated in the third quarter of 2019.

The Company’s new guidance for 2019 replaces its prior 2019 and multi-year outlook, it said in a press release.

First Quarter 2019 Guidance

The Company anticipates sales volumes in the first quarter in the range of 321 to 336 MBoe/d. In E.G., sales volumes are anticipated to be lower than the fourth quarter 2018 by approximately 15 MBoe/d as a result of the timing of oil liftings (production is anticipated to be greater than sales) and the turnaround maintenance at the third-party LNG facility. The variance from the fourth quarter 2018 is estimated to be 40 percent from oil volumes and 60 percent from natural gas volumes, which will also result in equity method investment income being lower than prior quarters.

U.S. onshore sales volumes in the first quarter 2019 are also anticipated to be slightly lower than the fourth quarter 2018 as a result of the timing of well activities in late 2018 and early 2019. The first quarter is planned to be the low quarter for wells commencing production in 2019. Natural decline in the Eagle Ford will also impact the first quarter 2019. Second half U.S. onshore production is anticipated to be approximately 15 percent higher than the first half of the year.

The Company’s planned first quarter organic capital expenditures of between $725 and $800 million are anticipated to be the highest quarter of 2019, driven by the timing of drilling and completion activities in the U.S. onshore business as well as Leviathan spend.

Additional full-year and first quarter 2019 guidance details are available in the latest presentation deck provided on the ‘Investors’ page of the Company’s website, www.nblenergy.com.

Noble  announces 2018 results

Noble also announced full-year 2018 financial and operating results.

Full year 2018 Highlights

  • Returned more than $500 million to shareholders, including $295 million through the Company’s share repurchase program and $208 million through Noble Energy’s quarterly dividend.
  • Strengthened the Company’s balance sheet by paying down $609 million in Noble Energy debt.
  • Enhanced the portfolio to focus on high-return U.S. onshore liquids and international gas by divesting the Company’s Gulf of Mexico assets and midstream ownership in Appalachia.
  • Sales volumes totaled 353 MBoe/d, up 11 percent(1)as compared to 2017, on organic capital expenditures funded by Noble Energy of less than $3 billion.
  • Implemented row development in the DJ and Delaware Basins and grew U.S. onshore oil production 26 percent(1)as compared to 2017.
  • Received approval for the first large-scale Comprehensive Drilling Plan across the Company’s Mustang area in the DJ Basin.
  • Progressed the Leviathan project, offshore Israel, to approximately 75 percent complete.
  • Executed gas sales agreements for up to 700 MMcf/d of natural gas, gross, to customers in Egypt from the Tamar and Leviathan fields.
  • Negotiated Heads of Agreement to progress monetization of natural gas from the Alen field in Equatorial Guinea.

Enable Midstream Announces Fourth Quarter and Full-Year 2018 Financial and Operating Results

February 7, 2019

PANHANDLE OIL AND GAS INC. Reports First Quarter 2019 Results

February 1, 2019

Sizeable profits: ExxonMobil adds $20.8 billion, Chevron $14.8 billion, Shell $21.4 billion

Royal Dutch Shell (stock ticker: RDSA, $RDSA), ExxonMobil (stock ticker: XOM, $XOM) and Chevron (stock ticker: CVX, $CVX) have all reported 2018 earnings during the previous 24 hours.

Shell earns $21.4 billion profit for the year

Royal Dutch Shell started things off, reporting unaudited results yesterday, including full year earnings of $21.4 billion for 2018, which reflected higher realized oil, gas and LNG prices, partly offset by movements in deferred tax positions.

Cash flow from operating activities for the fourth quarter 2018 was $22.0 billion, which included positive working capital movements of $9.1 billion, mainly as a result of a fall in crude oil price and lower inventory levels. Excluding working capital movements, cash flow from operations of $12.9 billion mainly reflected increased earnings, compared with the fourth quarter 2017, Shell said.

Shell upstream

During the quarter, Shell completed the sale of its Upstream interests in Ireland, as well as the disposal of its interests in the Draugen and Gjøa fields in Norway.

In December, Shell and its partners renewed a number of onshore oil mining leases in the Niger Delta for 20 years (Shell interest 30%).

Read Shell’s full press release here.


Exxon tallies $20.8 billion profit

Exxon reported 2018 earnings of $20.8 billion, or $4.88 per share assuming dilution, compared with $19.7 billion a year earlier. Excluding U.S. tax reform and asset impairments, earnings were $21 billion, compared with $15.3 billion in 2017. Cash flow from operations and asset sales was $40.1 billion, including proceeds associated with asset sales of $4.1 billion. Capital and exploration expenditures were $25.9 billion, including incremental spend to accelerate value capture.

Exxon said its fourth quarter 2018 earnings were $6 billion, or $1.41 per share assuming dilution, compared with $8.4 billion in the prior-year quarter. Earnings excluding U.S. tax reform and impairments were $6.4 billion, compared with $3.7 billion in the prior-year quarter.

Exxon Q4 upstream

  • Crude prices weakened in the fourth quarter, while natural gas prices strengthened with higher LNG prices and increased seasonal demand.
  • Natural gas volumes were supported by stronger seasonal gas demand in Europe.
  • Permian unconventional production continued to ramp up in the fourth quarter, with production up more than 90 percent from the same period last year.

Read Exxon’s full press release here.


Chevron captures $14.8 billion profit for 2018

  • Record annual net oil-equivalent production of 2.93 million barrels per day, 7 percent higher than a year earlier; 4 to 7 percent growth targeted for 2019
  • Reserves replacement of 136 percent
  • Dividend increase of $0.07 per share
  • Share repurchases of $1.0 billion in fourth quarter

Chevron ticked off earnings of $3.7 billion ($1.95 per share – diluted) for fourth quarter 2018, compared with $3.1 billion ($1.64 per share – diluted) in the fourth quarter of 2017, which included $2.02 billion in tax benefits related to U.S. tax reform. Included in the current quarter was an asset write-off totaling $270 million. Foreign currency effects increased earnings in the 2018 fourth quarter by $268 million.

Full-year 2018 earnings were $14.8 billion ($7.74 per share – diluted), the company said, compared with $9.2 billion ($4.85 per share – diluted) in 2017. Included in 2018 were impairments and other charges of $1.59 billion and a gain on an asset sale of $350 million. Foreign currency effects increased earnings in 2018 by $611 million.

Chevron said its sales and other operating revenues in Q4 were $40 billion, compared to $36 billion in the year-ago period.

Chevron U.S. upstream

Chevron’s U.S. upstream operations earned $964 million in fourth quarter 2018, compared with $3.69 billion a year earlier. The decrease was primarily due to the absence of the prior year benefit of $3.33 billion from U.S. tax reform, partially offset by higher crude oil production and realizations, Chevron said in a statement.

The company’s average sales price per barrel of crude oil and natural gas liquids was $56 in fourth quarter 2018, up from $50 a year earlier. The average sales price of natural gas was $2.01 per thousand cubic feet in fourth quarter 2018, up from $1.86 in last year’s fourth quarter.

Net oil-equivalent production of 858,000 barrels per day in fourth quarter 2018 was up 187,000 barrels per day from a year earlier.

Production increases from shale and tight properties in the Permian Basin in Texas and New Mexico and base business in the Gulf of Mexico were partially offset by normal field declines and the impact of asset sales of 17,000 barrels per day. The net liquids component of oil-equivalent production in fourth quarter 2018 increased 30 percent to 674,000 barrels per day, while net natural gas production increased 20 percent to 1.10 billion cubic feet per day.

Read Chevron’s full press release here.

On a side note…

The U.S.’s largest independent exploration and production company announced its fourth quarter results yesterday. ConocoPhillips (stock ticker: COP) ($COP) showed earnings of $1.9 billion, or $1.61 per share for the quarter.

For the year, ConocoPhillips earned $6.3 billion in 2018, or $5.32 per share. [Editor’s note: COP’s earnings were not included in the profit tally above; that was strictly generated by the three integrated international oils.]

Conoco has been firing on all cylinders since mid-2017, and has reported six straight quarters of profits, the first time the company has achieved this since Q3 2014. 2018 also represents the first yearly profit Conoco reported since 2014, as its 2017 results were hampered by a major impairment.

Conoco reported it now holds 5.3 billion BOE of reserves, up from 5.0 billion BOE last year. The company replaced 147% of production, with oil accounting for over 90% of new reserves.

Read about Conoco’s good year here.

 


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