February 25, 2019 - 4:14 PM EST
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Magnolia Oil & Gas Corporation Announces Fourth Quarter and 2018 Year-End Results


Magnolia Oil & Gas Corporation (“Magnolia,” “we,” “our,” or the “Company”) (NYSE: MGY) today announced its financial and operational results for the fourth quarter of 2018.

Fourth Quarter and 2018 Highlights:

  • Magnolia reported fourth quarter net income attributable to Class A Common Stock of $32.9 million, or $0.21 per diluted share or $0.22 on an adjusted basis. Total net income (including the non-controlling interest) was $57.8 million.
  • Total Company production averaged 61.9 thousand barrels of oil equivalent per day ("Mboe/d") for the fourth quarter of 2018, or a 5 percent sequential increase compared to the period from July 31, 2018 through September 30, 2018 ("the Q3 Successor Period1").
  • Fourth quarter 2018 production in the Giddings Field increased 22 percent sequentially to 20.6 Mboe/d over the Q3 Successor Period1, largely due to the completion of new wells.
  • Adjusted EBITDAX of $193.0 million during the fourth quarter of 2018 with drilling and completions capital expenditures of $110.8 million during the same period (approximately 57% of Adjusted EBITDAX), and well within our plan.
  • We continue to strengthen our core position in Karnes through bolt-on acquisitions, adding 1,849 net acres to our Karnes County footprint in the fourth quarter of 2018.
  • The average realized oil price was $65.12 per barrel for the fourth quarter of 2018, or 110 percent of the average NYMEX WTI benchmark price during the period.
  • The Company generated pretax operating margins of $13.00 per Boe, or 29 percent on a GAAP basis; and adjusted operating margins of $13.39 per Boe, or 30 percent, each during the fourth quarter of 2018.
  • Magnolia ended 2018 with $135.8 million of cash on the balance sheet compared to $36.7 million at the end of the third quarter of 2018. We had $388.6 million of long-term debt, and an undrawn revolving credit facility with $550.0 million of capacity.

“Although we are still in the early stages as an organization, we exceeded most of our objectives during 2018,” said Magnolia Chairman, President and CEO, Steve Chazen. “The current product price environment is not very different than when we announced our original transaction nearly a year ago, and our core South Texas oil and gas properties that we acquired continue to show very strong performance. We demonstrated our ability to grow our production above our initial plan while spending less than 60 percent of our Adjusted EBITDAX on drilling and completing wells. Additionally, we reinvested a significant portion of our excess cash flow on the completion of asset acquisitions which further strengthened our position in both the Karnes and Giddings areas. We continue to evaluate several small asset acquisition opportunities that fit our business model. Our objective of spending within 60 percent of EBITDAX while generating moderate volume growth with low financial leverage and strong pretax margins remains part of our differentiated strategy. Our business model and ability to adapt is well-suited for the current product price environment, and we look forward to further achievements in 2019.”

Operational Update

Total fourth quarter 2018 net income (including the non-controlling interest) was $57.8 million, or $0.23 per share (assuming the weighted average impact of Class A Common stock issuable upon conversion of Class B Common Stock). Daily production averaged 61.9 Mboe/d and 60.7 Mboe/d during the fourth quarter 2018 and five months of Magnolia ownership for the year ended 2018, respectively. The Karnes County assets and drilling program continued to provide high quality and consistent well results. Production in Karnes averaged 41.3 Mboe/d during the fourth quarter, roughly flat with the third quarter as fewer wells were turned-in-line during the most recent period. Overall company growth was driven by the Giddings assets during the fourth quarter as well completions shifted to this area during the period. Production in Giddings increased nearly 22 percent sequentially to 20.6 Mboe/d in the fourth quarter, primarily due to additional wells turned-in-line as well as a full period of production from the Harvest acquisition.

1 Q3 Successor Period volumes have been adjusted to reflect the adoption of Accounting Standard Update No. 2014-09, Revenue from Contracts with Customers ("ASC 606").

During the fourth quarter of 2018, the Company operated three drilling rigs with two rigs in Karnes County and one rig in the Giddings Field, and utilized one completion crew across our operations. The drilling program is designed to provide flexibility to opportunistically maximize development and completion efficiencies between the fields.

Updated Guidance

Looking into 2019, Magnolia continued to operate three rigs for most of the first quarter. Given the recent decline in product prices, and to adjust our capital spending in line with our business model, we currently plan to exit the first quarter operating two rigs - one each in Karnes and Giddings. We will continue to evaluate our drilling program and activity levels as the year progresses and expect our full year 2019 drilling and completions capital to be within 60 percent of our total EBITDAX for the year. Despite the slowing pace of activity into this year, we still expect to generate moderate overall production growth for the full year of 2019. We currently estimate our first quarter production volumes to be equal or better than fourth quarter 2018 levels. Production is expected to accelerate into mid-year due to additional operated wells turned-in-line and higher anticipated non-operated activity. Overall company production is estimated to exit 2019 approximately 6.0 Mboe per day higher than in the fourth quarter of 2018.

2018 Year-End Reserves

Magnolia’s total proved reserves at year-end 2018 were 100.5 MMboe (50% oil and 71% liquids) compared to 75.6 MMboe at the end of 2017 which relates to the one-year development plan of the assets acquired in the transaction with EnerVest, Ltd. and its affiliates. Proved undeveloped reserves represent 24 percent of total proved reserves, the vast majority of which will be developed within one year.

Annual Report on Form 10-K

Magnolia's financial statements and related footnotes will be available in its Annual Report on Form 10-K for the year ended December 31, 2018, which is expected to be filed with the U.S. Securities and Exchange Commission ("SEC") on February 27, 2019.

Upcoming Investor Conference

Magnolia’s senior management is scheduled to participate in the following conference:

The 19th annual Simmons Energy Conference, February 27-28, 2019 in Las Vegas.

The presentation materials used at the conference will be available the morning of the event on Magnolia's website at www.magnoliaoilgas.com under the Investors tab.

Conference Call and Webcast

Magnolia will host an investor conference call on Tuesday, February 26, 2019 at 10:00 a.m. Central (11:00 a.m. Eastern) to discuss these operating and financial results. Interested parties may join the webcast by visiting Magnolia's website at www.magnoliaoilgas.com/events-and-presentations and clicking on the webcast link or by dialing 1-866-807-9684. A replay of the webcast will be posted on Magnolia's website following completion of the call.

About Magnolia Oil & Gas Corporation

Magnolia (MGY) is a publicly traded oil and gas exploration and production company with South Texas operations in the core of the Eagle Ford Shale and Austin Chalk formations. Magnolia will focus on generating value for shareholders through steady production growth, strong pre-tax margins, and free cash flow. For more information, visit www.magnoliaoilgas.com.

Cautionary Note Regarding Forward-Looking Statements

The information in this press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of present or historical fact included in this press release, regarding Magnolia’s strategy, future operations, financial position, estimated revenues, and losses, projected costs, prospects, plans and objectives of management are forward looking statements. When used in this press release, the words could, should, will, may, believe, anticipate, intend, estimate, expect, project, the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Except as otherwise required by applicable law, Magnolia disclaims any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this press release. Magnolia cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the control of Magnolia, incident to the development, production, gathering and sale of oil, natural gas and natural gas liquids. In addition, Magnolia cautions you that the forward looking statements contained in this press release are subject to the following factors: (i) the outcome of any legal proceedings that may be instituted against Magnolia; (ii) Magnolia’s ability to realize the anticipated benefits of its business combination, which may be affected by, among other things, competition and the ability of Magnolia to grow and manage growth profitably; (iii) changes in applicable laws or regulations; and (iv) the possibility that Magnolia may be adversely affected by other economic, business, and/or competitive factors. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, actual results and plans could different materially from those expressed in any forward-looking statements. Additional information concerning these and other factors that may impact the operations and projections discussed herein can be found in Magnolia’s filings with the SEC, including its Annual Report on Form 10-K for the fiscal year ended December 31, 2017, and its Annual Report on Form 10-K for the fiscal year ended December 31, 2018, which is expected to be filed on February 27, 2019. Magnolia’s SEC filings are available publicly on the SEC’s website at www.sec.gov.

Magnolia Oil & Gas Corporation
Operating Highlights

For the Quarter Ended
December 31, 2018

July 31, 2018 through

December 31, 2018

Oil (MBbls) 3,054 5,078
Natural gas (MMcf) 8,795 14,136
NGLs (MBbls) 1,179   1,857  
Total (MBoe) 5,699 9,291
Revenues (in thousands):
Oil sales $ 198,891 $ 342,093
Natural gas sales 29,565 42,979
NGL sales 26,599   48,146  
Total Revenues $ 255,055 $ 433,218
Average sales price:
Oil (per Bbl) $ 65.12 $ 67.37
Natural gas (per Mcf) 3.36 3.04
NGL (per Bbl) 22.56   25.93  
Total (per Boe) $ 44.75 $ 46.63
NYMEX WTI ($/Bbl) $ 59.08 $ 63.10
NYMEX Henry Hub ($/Mcf) $ 3.64 $ 3.33
Realization to benchmark:
Oil (per Bbl) 110 % 107 %
Natural Gas (per Mcf) 92 % 91 %
Operating Expenses (in thousands):
Lease operating expenses $ 19,737 $ 30,753
Taxes other than income 13,819 23,170
Gathering, transportation and processing 9,092 14,445
Depreciation, depletion and amortization 111,989 177,890
Operating costs per Boe:
Lease operating expenses $ 3.46 $ 3.31
Taxes other than income 2.42 2.49
Gathering, transportation and processing 1.60 1.55
Depreciation, depletion and amortization 19.65 19.15
Magnolia Oil & Gas Corporation
Consolidated and Combined Statements of Operations
(in thousands, except per share data)

For the Quarter Ended
December 31, 2018

  July 31, 2018 through
December 31, 2018
Oil revenues $ 198,891 $ 342,093
Natural gas revenues 29,565 42,979
Natural gas liquids revenues 26,599   48,146  
Total revenues 255,055 433,218
Lease operating expenses 19,737 30,753
Gathering, transportation and processing 9,092 14,445
Taxes other than income 13,819 23,170
Exploration expense 661 11,882
Asset retirement obligation accretion 1,276 1,668
Depreciation, depletion and amortization 111,989 177,890
Amortization of intangible assets 3,626 6,044
General & administrative expenses 18,504 28,801
Transaction related costs 2,241   24,607  
Total operating costs and expenses 180,945 319,260
OPERATING INCOME 74,110 113,958
Income (loss) from equity method investee 465 773
Interest expense (7,494 ) (12,454 )
Other income (expense), net (1,355 ) (8,374 )
Total other income (expense) (8,384 ) (20,055 )
Income tax expense 7,918   11,455  
NET INCOME 57,808 82,448
LESS: Net income attributable to noncontrolling interest 24,887   43,353  
Basic $ 0.21 $ 0.25
Diluted $ 0.21 $ 0.25
Basic 156,273 154,527
Diluted 158,998 158,232

(1) Diluted shares outstanding include the effect of warrants using the treasury stock method.

Magnolia Oil & Gas Corporation
Summary Balance Sheet Data
(in thousands)


December 31, 2018 December 31, 2017
Cash $ 135,758 $
Other current assets 156,601 114,536
Property, plant and equipment, net 3,073,204 1,565,537
Other assets 67,960   8,901
Total assets $ 3,433,523 $ 1,688,974
Current liabilities $ 197,361 $ 81,300
Long-term debt, net 388,635
Other long-term liabilities 139,572 9,836
Stockholders' equity
Noncontrolling interests 1,031,186
Common stock 25
Additional paid in capital 1,641,237
Retained earnings 35,507
Parents' net investment   1,597,838
Total liabilities and equity $ 3,433,523   $ 1,688,974

Magnolia Oil & Gas Corporation
Non-GAAP Financial Measures

Reconciliation of net income attributable to Class A Common Stock to Adjusted EBITDAX

In this press release, we refer to Adjusted EBITDAX, a supplemental non-GAAP financial measure that is used by management and external users of our consolidated and combined financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization and accretion of asset retirement obligations and exploration costs. Adjusted EBITDAX is not a measure of net income as determined by GAAP.

Our management believes that Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We also believe that securities analysts, investors and other interested parties may use Adjusted EBITDAX in the evaluation of our Company. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDAX to net income attributable to Class A Common Stock, our most directly comparable financial measure calculated and presented in accordance with GAAP:

(in thousands)

For the Quarter Ended
December 31, 2018


July 31, 2018 through

December 31, 2018

Adjusted EBITDAX reconciliation to net income:
Net income attributable to common stock $ 32,921 $ 39,095
Net income attributable to Noncontrolling Interest 24,887 43,353
Income tax (benefit) expense 7,918 11,455
Interest expense 7,494 12,454
Depreciation, depletion and amortization 111,989 177,890
Amortization of intangible assets 3,626 6,044
Exploration Expense 661 11,882
Accretion expense 1,276   1,668
EBITDAX 190,772 303,841
Transaction related costs(1) 2,241   24,607
Adjusted EBITDAX $ 193,013 $ 328,448
(1) Transaction related costs incurred related to the execution of our business combination with EnerVest, Ltd. and its affiliates and the Harvest acquisition, including legal fees, advisory fees, consulting fees, accounting fees, employee placement fees, and other transaction and facilitation costs.

Magnolia Oil & Gas Corporation
Non-GAAP Financial Measures

Reconciliation of net income attributable to Class A Common Stock to adjusted earnings

Our presentation of adjusted earnings and adjusted earnings per share are non-GAAP measures because they exclude the effect of certain items included in Income Attributable to Class A Common Stock. Management uses adjusted earnings and adjusted earnings per share to evaluate our operating and financial performance because it eliminates the impact of certain items that management does not consider to be representative of the Company’s on-going business operations. As a performance measure, adjusted earnings may be useful to investors in facilitating comparisons to others in the Company’s industry because certain items can vary substantially in the oil and gas industry from company to company depending upon accounting methods, book value of assets, and capital structure, among other factors. Management believes excluding these items facilitates investors and analysts in evaluating and comparing the underlying operating and financial performance of our business from period to period by eliminating differences caused by the existence and timing of certain expense and income items that would not otherwise be apparent on a GAAP basis. However, our presentation of adjusted earnings and adjusted earnings per share may not be comparable to similar measures of other companies in our industry.


For the Quarter
Ended December 31, 2018


Per Share
Diluted EPS


July 31, 2018 through
December 31, 2018


Per Share
Diluted EPS

(in thousands, except per share data)
Net income attributable to Class A Common Stock $ 32,921 $ 0.21 $ 39,095 $ 0.25
Adjustments for certain items affecting comparability(1):
Loss on Giddings earnout (2) 6,700 0.04
Transaction costs 2,241 0.01 24,607 0.16
Seismic purchase 11,000 0.07
Noncontrolling interest impact (6,439 ) (0.04 )
Change in estimated income tax (471 )       (7,532 )   (0.05 )
Adjusted earnings $ 34,691     $ 0.22     $ 67,431     $ 0.43  
(1) Includes amounts attributable to Class A Common Stock.
(2) Loss related to lump sum payment of $26 million to the Giddings Sellers to fully settle an earnout payment.

Magnolia Oil & Gas Corporation
Non-GAAP Financial Measures

Reconciliation of operating margin to adjusted operating margin

In this press release, we refer to adjusted operating margin per Boe, a supplemental non-GAAP financial measure that is used by management. We define adjusted operating margin per Boe as total revenues per Boe less operating expenses per Boe adjusted for certain unusual or non-recurring items per Boe that management does not consider to be representative of the Company's on-going business operations. Management believes that adjusted operating margin per Boe provides relevant and useful information, which is used by our management in assessing the Company’s profitability and comparability of results to our peers.

As a performance measure, adjusted operating margin may be useful to investors in facilitating comparisons to others in the Company’s industry because certain items can vary substantially in the oil and gas industry from company to company depending upon accounting methods, book value of assets, and capital structure, among other factors. Management believes excluding these items facilitates investors and analysts in evaluating and comparing the underlying operating and financial performance of our business from period to period by eliminating differences caused by the existence and timing of certain expense and income items that would not otherwise be apparent on a GAAP basis. However, our presentation of adjusted operating margin and adjusted operating margin per Boe may not be comparable to similar measures of other companies in our industry.

(in $/Boe)

For the Quarter Ended
December 31, 2018


July 31, 2018 through
December 31, 2018

Revenue $ 44.75 $ 46.63
Direct operating expenses
Less: Lease Operating Expenses (3.46 ) (3.31 )
Less: Gathering, Transportation, and Processing (1.60 ) (1.55 )
Less: Taxes Other Than Income (2.42 ) (2.49 )
Less: Exploration Expense (0.12 ) (1.28 )
Less: General & Administrative expense (3.25 ) (3.10 )
Less: Transaction Related expense (0.39 )   (2.65 )
Cash Operating Margin 33.51 32.25
Margin (%) 75 % 69 %
Non-cash expenses
Less: Depreciation, Depletion, and Amortization (19.65 ) (19.15 )
Less: Amortization on Intangible Assets (0.64 ) (0.65 )
Less: Asset retirement obligations accretion (0.22 )   (0.18 )
Operating margin 13.00 12.27
Margin (%) 29 % 26 %
Add: Exploration Expense related to seismic license continuation 1.18
Add: Transaction Related expense 0.39     2.65  
Adjusted operating margin 13.39 16.10
Margin (%) 30 % 35 %

Brian Corales
(713) 842-9036
[email protected]

Art Pike
(713) 842-9057
[email protected]

Source: Business Wire (February 25, 2019 - 4:14 PM EST)

News by QuoteMedia

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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