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)

News by QuoteMedia
www.quotemedia.com

Recent Company Earnings:


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.

 

Enterprise Products Partners (stock ticker: EPD, $EPD) has just completed a record-setting tear, based on its 2018 results.

Jim Teague, chief executive officer of Enterprise’s general partner, put it like this:

“Total gross operating margin for 2018 increased 29 percent to a record $7.3 billion compared to $5.7 billion in 2017.”

According to Teague, the partnership established 23 operational and financial records for the year. “All of our business segments reported operational records,” he said in a statement.

Compared to 2017:

  • liquid pipeline volumes increased 9 percent;
  • natural gas pipeline volumes increased 12 percent;
  • marine terminal volumes increased 12 percent;
  • NGL fractionation volumes increased 14 percent; and
  • propylene plant production volumes increased 23 percent.

Enterprise reported record net income attributable to limited partners for 2018 of $4.2 billion, or $1.91 per unit on a fully diluted basis, which represents a 47 percent increase compared to $1.30 per unit on a fully diluted basis for 2017. Net cash flow provided by operating activities (referred to in this press release as “cash flow from operations” or “CFFO”) for 2018 increased 31 percent to a record $6.1 billion. Free cash flow, which is defined as CFFO less net cash used in investing activities plus net cash contributions from noncontrolling interests, for 2018 increased 50 percent to a record $2.0 billion compared to 2017.

Distributable cash flow (“DCF”) increased 33 percent to a record $6.0 billion in 2018 compared to 2017. DCF for 2018 included $183 million of proceeds from asset sales and monetization of interest rate derivatives. Excluding these proceeds, distributable cash flow, provided 1.5 times coverage of the distributions declared with respect to 2018. Distributions declared with respect to 2018 increased 2.5 percent to $1.725 per unit compared to 2017. Enterprise retained $2.2 billion of DCF for 2018, a 155 percent increase from the $867 million of retained DCF for 2017.

“We generated $6.0 billion of distributable cash flow, which allowed us to increase the distributions paid to our partners for the 20th consecutive year while self-funding the equity portion of our growth capital expenditures. We achieved our goal of equity self-funding a year earlier than expected. Today, we announced the authorization of a $2.0 billion multi-year, common unit buyback program that provides us with an alternative means to opportunistically return capital to our limited partners,” said Teague.

“During 2018, Enterprise completed construction and began service on $1.9 billion of organic growth capital projects, including two cryogenic natural gas processing plants in the Delaware Basin and our ninth NGL fractionator at Mont Belvieu. We have another $6.7 billion of growth projects under construction. This includes five major projects scheduled to be completed in 2019, including: the conversion of one of the Seminole NGL pipelines to crude oil service; the Shin Oak NGL pipeline; the third processing train at our Orla complex; our isobutylene dehydrogenation unit at Mont Belvieu; and our ethylene export terminal on the Houston Ship Channel. In addition, our integrated footprint of assets and customer relationships continue to provide new opportunities for growth projects that are currently under development,” said Teague.

Read the full 2018 earnings release here.

August 9, 2018

Heard on The Call: Bonanza Creek Energy

Bonanza Creek Energy is presenting at the EnerCom Conference on Wednesday, August 22nd in Denver.

Bonanza Creek Energy Inc. reported Q2 results today and elaborated on its DJ Basin operations during the company’s Q2 2018 earnings call held August 9. Excerpts from the call are below.

  • Second quarter sales volumes averaged 18.0 MBoe per day including the negative effects of a prior-period adjustment of 0.6 Mboe per day related to non-operated wells
  • Rapidly improving well performance yields over 1,000 economic drilling locations in Wattenberg
  • Well head pressures effectively managed via Rocky Mountain Infrastructure’s (“RMI”) multiple third-party gas processing optionality
  • Second quarter GAAP net income of $4.9 million, or $0.24 per diluted share; Adjusted net income(1)of $24.2 million, or $1.18 per diluted share

Q: My question has to do to a 1,000 locations you guys have talked about and I think this is the first time you actually openly speak about. Firstly, are those net locations? And then secondarily, could you give us a little insight as to what that would translate into if you were to be drilling more extended reach laterals?

Bonanza Creek President and CEO Eric Greager: It is the first time we’ve indicated because we needed to complete the resource assessment that we started when I first came on-board in April. And that resource assessment, if you’ve been through these before, it starts with that fundamental understanding of the resource itself.

As you work your way through the resource across the acreage position, combine it with what you understand about spacing, stacking, stimulation design, and the latest application of well performance initiatives, you roll all of that together and that has yielded the 1,000-plus locations. They are – and I want to point out, we’ve stated in our press release and elsewhere, these are SRL equivalents. That’s our measure to keep things clear on that.

And the other point of clarification, I think, I need to make is that they are gross locations and that provides some opportunity for us as we continue to develop the resource and continue to drive and apply more cutting-edge subsurface engineering and development. There’s an opportunity to continue to grow this, but I wanted to qualify, A, they’re gross; and B, they are SRL equivalents.

Q: What is the net equivalent?

President and CEO Eric Greager: Because these are SRL equivalents, I don’t know that we have released the net working interest on all of those leases, Irene. We’re going to take a little bit more time and continue working on that. But it’s – our working interest is large on much of our contiguous acreage and all of these wells are sticked in our contiguous acreage, meaning we didn’t stick up scattered acreage that kind of sat at all by itself.

So, there is upside potential with additional acreage that will be sticked up. We wanted to stick with the more contiguous acreage position, one, because we better understand the continuous resource potential; and two, because we wanted to get this information out as quickly as possible.

Q: Of these locations, how many are Niobraras? And do you have some Codells in there and maybe a little bit on spacing and EURs?

President and CEO Eric Greager: Yeah. It’s – I think EURs are kind of in the same space as net working interest although we’ll be able to guide on net working interest relatively quickly. EURs is something that evolves over time, and that’s something that you can expect to get periodic guidance on. I think what we intend to do going forward here is when we finish our assessment throughout 2018 for the well performance and we move into our budget season for 2019, we’ll begin to lean in and start providing our type curves to help model the business and the programs for 2019. And then each year, you can expect to get new type curves that indicate our best guess. But the thing about given EURs and type curve performance for the longer run is it – it fails really to recognize the upside potential that we continue to drive into the business. And I think there’s a significant amount of upside potential yet to come in terms of how we intend to develop our resource over time.

Q:  And also the split between Niobrara and Codell?

President and CEO Eric Greager: Yeah. I think you can look at the Niobrara and Codell. You can look back on our current distribution between Niobrara and Codell and that’s going to represent itself largely proportionately going forward. So, if it turns out to be a typical 6-well pad for example has 1 Codell and 5 Niobrara and perhaps 2 benches, then I think you can expect that same distribution over time. But the thing that you got to keep in mind is, we’re going to continue to optimize every pad going forward with the very best information we have in terms of spacing, stacking and stimulation design, and the interdependencies of those. And I think what you’ll see in the well performance that we’re releasing this quarter is even in a period as short as a quarter, you can create some substantial uplift in well performance, and we certainly don’t anticipate that growth slowing down over time.

The Oil and Gas Conference®

Bonanza Creek Energy Inc. is presenting at EnerCom’s The Oil & Gas Conference® at the Denver Downtown Westin Hotel, Denver, Colo. Aug. 19-22, 2018. EnerCom expects to have more than 80 presenting oil and gas companies and more than 2000 financial professionals attending this year’s conference.

To learn more about the conference and presenter schedule please visit the conference website here.

August 7, 2018

Carrizo Oil & Gas Inc. (NASDAQ: CRZO) elaborates on current operations and Q2 earnings. The Excerpts from the Q2 Call are below.

Q: Eagle Ford continues to look like you’re having really nice success there. Can you just talk about space in a little bit more there? I know you’ve been able to down space a bit with the Brown Trust and others, but just any comments you could have around how you view the rest of your space and field?

President and Chief Executive Officer S.P. “Chip” Johnson: I think generally we’re sticking with 330-foot spacing in bulk of the acreage. There’s still a couple of places we think 500 feet might be better on the Brown Trust. We did have some of the wells in 250 feet. And so far we haven’t seen any interference or better or worse performance, but we’re still in the early six-month period where everything is on restricted chokes and constrained rate. So it’s hard to tell. I think we’d rather just say 330-foot is the easy answer and we’ll keep trying to figure out ways to tighten that up.

Q: Secondly, Chip, there seemed to be a little confusion or maybe just talk a little bit about the Brown Trust accelerated payout. Is that sort of typical of what you’re seeing on a lot of your plays? And again, I mean, frankly I was glad to see it, but I just – if you could talk maybe a bit more about that?

President and Chief Executive Officer S.P. “Chip” Johnson: Well, I don’t think we have back-ins after payout anywhere else in our inventory. We used to – we bought out some of those partners three or four years ago. But this was an arrangement we got into with a major where we had at least half the minerals, they own the other half, and we made a deal with them eight years ago where we could drill and they could either participate or they could back-in after payout. And sometimes they participate, sometimes they back in.

This time, they’re going to back in. And this had been in the fourth quarter. We probably would have had to draw attention to it. But if it had just been in the middle of the year, it wouldn’t have made much difference. But they have 1,000 barrel a day drop in production in the fourth quarter. We felt like we needed to point that out. Otherwise, we thought this would have happened in the first or second quarter of next year.

Q: When that just balances, I guess that’s just sort of a onetime item then, correct?

President and Chief Executive Officer S.P. “Chip” Johnson: On those wells. Next year when we bring on more wells in the Brown Trust, if that company has not participated, then it’ll start another back-in after payout on those wells.

The good thing was we made that much more EBITDA this year than we expected to, because of the raise in the oil prices. So, we felt like it was a good thing.

Q: Just wanted to follow up a little bit on what you’d said there on the Permian and, clearly, you guys were talking about lower activity as you work later this year. But I guess just from a high level, should we expect Permian to continue to grow in the third quarter and then also in the fourth quarter or do you start to see Permian flatten out or even decline a little late this year in terms of the production there? And then into the first half of 2019, just a similar question, does Permian grow? Does it flatten? Does it decline? How do you see that playing out with the activity shift?

Vice President of Investor Relations Jeff P. Hayden: So, if you think about it, you just kind of add on a little bit in some of those questions about activity. What you probably see just given the drilling activity in Eagle Ford this year, and then in fact we’re keeping four rigs there for the first half of next year, I think it’s safe to assume that you probably see the completion activity weighted to the Eagle Ford in the first half of the year. And then it’ll probably be weighted a little more towards Permian in the back half of the year. Given that, what you’re probably going to looking at in the Permian is kind of a flattening. I don’t know if you’ll necessarily see a decline, but maybe a flattening of production over the next several quarters. And then as you get kind of later next year, you probably see the Permian start to incline a lot more as we start increasing the completion activity out there.

In the meantime, I think, between now and then you’re going to see a lot of production growth likely in the Eagle Ford Shale as we kind of shift our activity over there.

Q: I guess is it safe to assume that the changes you guys have made, a shift in capital to Permian that basically all your Permian acreage as you’re looking to protect will get held over the next year here?

President and Chief Executive Officer S.P. “Chip” Johnson: We’ve got a drilling schedule in the Permian that takes care of our acreage. That’s still something – that’s the most critical thing we have to do at this point.

Q: Okay. Now that makes sense for sure. And I guess just lastly on the asset sale that you guys had just mentioned here. Just trying to get a sense in terms of magnitude, if you guys could let us know what the proceeds are and is this a one-off deal or might you guys monetize other little bits and pieces of the Permian going forward?

President and Chief Executive Officer S.P. “Chip” Johnson: Well, I guess in the past we’ve actually sold some little bits and pieces. This one, especially because it was non-op and the new owner, the new operator of these assets was pretty aggressive about capital spending. We felt like this could reduce our non-op CapEx budget significantly over the next two years and we felt like we got a good price for it. Part of our CapEx increase this year has been non-op. We have some other non-op partners who ramped up their activity in different parts of the core of the Delaware Basin and so we’ve had to increase our CapEx for that. But we felt like this was a good chance to maybe get out of some non-op at a good price and reduce that exposure to somebody else’s capital footprint.

August 2, 2018

Nabors Industries (NYSE: NBR) held its Q2 conference call today; excerpts from the Q & A are below:

Q: Tony, you mentioned that your latest survey has another 30 to 40 rigs being added to the rest of this year. And I would tell you, consensus from most investors that I’ve spoken with, is that we’re going to see a meaningful fall off in the Permian, maybe as much as 75 rigs. And so, overall, U.S. rig count is going to suffer modestly. So, this is a very different opinion. Obviously, I assume you’re closer to the customer than most of my – investors I’ve talked to. Give us more color on these rigs. Or are we going to see a decline in the Permian, or does the Permian stay flat and you add in the Eagle Ford and other areas? Just help us understand where that’s going.

Chairman, President and Chief Executive Officer Anthony G. Petrello: Sure. I hate to be the guy in the outlier here. So that’s the reason why we did these surveys because this information doesn’t come from me, it comes from the customers and that’s what the customers told us. Now, I know it runs a little counter to the major concern regarding the differentials in West Texas. So, that led us to go back and we just did this past 48 hours.

We went back to the top 20 operators in the Permian, and we asked them specifically about their limitation for pipeline access. And while our information may not be perfect, it suggested that only 2 of

During the Q2 conference calls this week, some enlightening comments were made by oil and gas company CEOs.

Chesapeake Energy (NYSE:CHK) CEO Doug Lawler examines 2019 goals

Q: Can you talk about 2019 and what the broad parameters of how that is going to look. It sounds like you guys are planning to stop the outspending versus cash flow and now spend within cash flow. And is that the right read on 2019? And what’s the kind of commodity price at which we should think about that being a valid read? And how are you – I know it’s early, but how are you projecting oil volumes to grow and your overall volumes to grow?

Chesapeake Energy CEO Robert Douglas Lawler: Sure, We’re happy to provide a little more clarity with that. And as we’ve stated, we anticipate our 2019 oil volumes to grow by 10% and this recognition of our ability with the remaining assets post Utica divestiture of being able to replace that EBITDA within a year speaks to the capital efficiency and the cash flow generating capability of our assets.

As we look forward to 2019, the reduction in our interest expense, it will help us as we pay down some of our debt. But we anticipate that that free cash flow neutrality is – as a primary target will be something that we have to continue to look at. And as noted, in 2019, we aren’t forecasting any major asset sales. But through our own operations from our existing assets, we expect that production growth will help us in reducing any outspend.

Nick’s point on the sustainable free cash flow at this point and you look to 2019, we will accomplish that principally through our organic production growth, but we will also have and continue to look at smaller asset sales and other opportunities for us to generate cash.

What we’re excited about is that, as I noted, each of the assets are free cash flow positive today, with the exception of the Powder, and the oil’s growth, strength there, we clearly will achieve that in 2020, but targeting with the team to try to achieve that in 2019.

So, our objective to be free cash flow positive is very strong. And from an operating cash flow basis, we’re there. When you look at all the other corporate liabilities that we have, we’re making excellent progress on that and expect to share good results with you as we progress.

Anadarko Petroleum (NYSE: APC) – Delware goal is $8 million per well, DJ is $3 million

Q: What are your current well costs in each basin for the second quarter? What was your AFE or spending in Delaware and DJ?

Executive Vice President of U.S. Onshore Operations Daniel E. Brown: So, from a Delaware standpoint, we’ve communicated previously we’ve got around $8 million is what we expect per copy once we’re in the development mode. We’re higher than that now, as we’ve communicated. It’s closer to $10 million. As we think about DJ, it’s I’d say sort of tilted to $3 million but it depends on the lateral length. And so, the longer wells obviously cost you more, the shorter wells are a little bit less. But think of it as around $3 million.

Q: As you go into 2019, does the Gulf of Mexico pick up a little bit more relative capital versus the onshore business?

Chairman, President and Chief Executive Officer Robert A. Walker: I’d say it’s more of a steady state, but if the options are such that we feel like we want to change that, we can, picking up a spot rig is not particularly difficult. So, I wouldn’t read too much into the implied rig schedule suggesting activity. But I think for us, Gulf of Mexico is two things, it’s more of a steady-state environment that throws off a lot of free cash flow, and that’s real attractive. And if you’re right, we see a tremendous price differential between WTI, LLS, and Brent, where the waterborne has a tremendous advantage, it’s just going to throw off more free cash flow. And I think that’s really the state that we see ourselves in.

Q: At least on our numbers, we’re pretty much in line with strip for the next three or four years, I guess. We still see substantial free cash if you maintain, which I expect you will, your capital discipline. Also, the $1 billion increase in the buyback is terrific. But how do you think about that going forward? It seems to me that you could reload that for a pretty much an extended period. And I’ll leave it there. Thanks.

Chairman, President and Chief Executive Officer Robert A. Walker: Yeah, I think you’re seeing it consistent with the way we see it and hopefully we’re both right. But we definitely believe the approach we’re taking today has tremendous durability. So, we don’t see it as something that’s just very temporary. Obviously, if oil backs up to $40, we’re going to be in a situation like many where we’re going to rethink what we want to do with our capital investments. But in a $50-plus environment and we’re throwing off a lot of free cash flow, there’s tremendous durability to buying back stock, retiring debt, and periodically looking at increasing our dividend which we think, coupled with the attractive growth that we can throw off at $50 as the steady state, is a pretty good business model.

Q: In the Delaware, can you take us through the next year in terms of how you expect your productivity and efficiency to evolve? Specifically, what your expectations are for the percent of your overall rig fleet drilling the multi-well pads, where you think lateral length can go, any shifts in completion methodology? And then you highlighted the goal of $8 million well costs from $10 million. When do you expect to achieve that?

Executive Vice President of U.S. Onshore Operations Daniel E. Brown: Thanks for the question. I’ll try to address them and if I miss one along the way, just remind me afterwards. Obviously, from a – since you’re talking about over the course of the next year or so, clearly our capital plans for 2019 we’ll be talking about in more detail in the fourth quarter. So, I won’t go into too much detail there. But from a general standpoint, we have been, we’ve been working our gen two completions which are, essentially, like some others in the industry, higher water content, higher proppant, closer spacing. We’ve been pleased with the performance we see there. I anticipate that that will be our completion style as we move through certainly the foreseeable future. Our pad development has been, I would say, hovering around 50% currently for 2018. But I’ll say the pads we’ve been able to do aren’t – that’s more than one well. And so, some of these pads are only two-well pads which gets us some efficiency, but not the significant efficiency increases we would expect to see as we get to really substantial multi-well pads which is what we’re looking forward to doing. So, four or five wells per pad is obviously going to be much more efficient for us as we go to two.

So, as we look forward from here, we should see the amount of wells that we’re drilling on pad increase, and the actual wells per pad to increase, both of which will then drive increasing efficiency through the system. So, that’s what I’d say on that. Hopefully I got everything.

Q – Yeah. All but maybe the one, which is that $8 million well cost goal. When would you expect to achieve that?

Executive Vice President of U.S. Onshore Operations Daniel E. Brown: Yeah. So, we’re currently thinking over the course of – as we get to our multi-well pad developments where we’re doing four to five wells per pad, that’s what we’re anticipating. We think over the course of the next, say, two or three years we should be transitioning over where substantially all of our development is sort of in that kind of place. And so that’s how we’d expect that to work over time. So, once we’re doing four to five wells per pad, that’s the type of well costs you should see and we think that transition is going to take place over the next few years.

April 20, 2018

  • Orders of $5.2 billion for the quarter, down 8% sequentially and up 9% year-over-year on a combined business basis*
  • Revenue of $5.4 billion for the quarter, down 7% sequentially and up 1% year-over-year on a combined business basis
  • GAAP operating loss of $41 million for the quarter, decreased 63% sequentially and increased unfavorably year-over-year on a combined business basis
  • Adjusted operating income (a non-GAAP measure) of $228 million for the quarter, down 20% sequentially and down 19% year-over-year on a combined business basis
  • GAAP diluted earnings per share of $0.17 for the quarter which included $(0.08) per share of adjusting items. Adjusted diluted earnings per share (a non-GAAP measure) were $0.09.
  • Cash flows generated from operating activities were $294 million for the quarter. Free cash flow (a non-GAAP measure) for the quarter was $226 million. Included in free cash flow is a cash usage of $100 million relating to restructuring and merger-related payments.

Baker Hughes, a GE company (ticker: BHGE), announced Q1 results today.

The company reported delivering $5.2 billion in orders and receiving $5.4 billion in revenue. “As expected, we saw growth in our shorter-cycle businesses and declines in our longer-cycle businesses versus the previous year.  Adjusted operating income* in the quarter was $228 million. Free cash flow* was $226 million,” the company reported.

“The gas market continues to grow, and strong LNG demand supports the view that new capacity will be required in the early to mid-part of the next decade,” said Lorenzo Simonelli, BHGE chairman and chief executive officer.

“In our Oilfield Services (OFS) segment, we continue to focus on growing share in key markets, including North America and the Middle East, through leading technology and services and flawless execution for customers. This quarter, we secured several critical commercial wins, and our synergy efforts led to improved margin rates.”

 


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