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

HOUSTON

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
   
Successor

For the Quarter Ended
December 31, 2018

July 31, 2018 through

December 31, 2018

Production:
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)
 
Successor

For the Quarter Ended
December 31, 2018

  July 31, 2018 through
December 31, 2018
REVENUES:
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
 
OPERATING EXPENSES
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
 
OTHER INCOME (EXPENSE):
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 BEFORE INCOME TAXES 65,726 93,903
Income tax expense 7,918   11,455  
NET INCOME 57,808 82,448
LESS: Net income attributable to noncontrolling interest 24,887   43,353  
NET INCOME ATTRIBUTABLE TO CLASS A COMMON STOCK $ 32,921   $ 39,095  
 
NET INCOME PER COMMON SHARE
Basic $ 0.21 $ 0.25
Diluted $ 0.21 $ 0.25
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic 156,273 154,527
Diluted 158,998 158,232
WEIGHTED AVERAGE NUMBER OF CLASS B SHARES OUTSTANDING 93,189 90,949

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

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

 

Predecessor
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:

  Successor
(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.

Successor
(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 %
 
Adjustments
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 %

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

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


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

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Recent Company Earnings:


May 1, 2019

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

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

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

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

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

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

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

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

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

These projects include:

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

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

Read the full Q1 Earnings Release here.

April 25, 2019

EQT Reports First Quarter 2019 Results

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

QEP Reports First Quarter 2019 Financial and Operating Results

March 25, 2019

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

March 14, 2019

2018 Earnings season gets ready for a wrap

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

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

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

Mid-Con Energy Partners

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

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

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

Recent Events and 2018 Summary

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

Earthstone Energy

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

Fourth Quarter 2018 Highlights

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

Full Year 2018 Highlights

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

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

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

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


Abraxas Petroleum

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

Financial Highlights for the Three Months Ended December 31, 2018

The three months ended December 31, 2018 resulted in:

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

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

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

Williston Basin, North Dakota

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

Delaware Basin, West Texas

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

Year End 2018 Reserves

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


Midstates Petroleum

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

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

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

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

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

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

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

Operational Update

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

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

Production and Pricing

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


Oryx Petroleum

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

2018 Financial Highlights:

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

2018 Operations Highlights:

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

2019 Operations Update:

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

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

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


Chaparral Energy

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

2018 Highlights

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

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

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

Operational Update – STACK Production Soars in 2018

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


Smart Sand

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

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

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

Full Year 2018 Highlights

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

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

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

 

 

February 26, 2019

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

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

February 22, 2019

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

February 20, 2019

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

February 19, 2019

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

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

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

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

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

Highlights from the company’s 2019 plan include:

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

 

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

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

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

U.S. Onshore

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

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

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

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

International Offshore

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

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

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

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

First Quarter 2019 Guidance

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

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

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

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

Noble  announces 2018 results

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

Full year 2018 Highlights

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

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

February 7, 2019

PANHANDLE OIL AND GAS INC. Reports First Quarter 2019 Results

February 1, 2019

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

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

Shell earns $21.4 billion profit for the year

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

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

Shell upstream

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

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

Read Shell’s full press release here.


Exxon tallies $20.8 billion profit

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

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

Exxon Q4 upstream

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

Read Exxon’s full press release here.


Chevron captures $14.8 billion profit for 2018

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

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

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

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

Chevron U.S. upstream

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

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

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

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

Read Chevron’s full press release here.

On a side note…

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

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

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

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

Read about Conoco’s good year here.

 


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