EL DORADO, Ark.
Achieved 172% Organic Reserve Replacement
Signed Memorandum of Understanding for King’s Quay Floating Production System
Source: murphyoilcorp.com
Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the fourth quarter ended December 31, 2019, including a net loss attributable to Murphy of $72 million, or $0.46 net loss per diluted share. Adjusted net income, which excludes discontinued operations and other one-off items, was $25 million, or $0.16 per diluted share.
As previously announced, Murphy closed the Malaysia asset divestiture in the third quarter for $2.0 billion in cash proceeds. These assets were reported as “discontinued operations” for all periods presented. Unless otherwise noted, the financial and operating highlights and metrics discussed in this commentary exclude discontinued operations and noncontrolling interest. 1
Highlights for the fourth quarter include:
- Generated adjusted EBITDA of $404 million, or $22.94 per barrel of oil equivalent sold
- Extended debt maturity profile with the issuance of $550 million of 5.875 percent senior notes due 2027, with proceeds used to repurchase an aggregate $521 million of senior notes due 2022
- Achieved first oil from the Nearly Headless Nick well and completed the Chinook #5 well workover, both located in the Gulf of Mexico
Highlights for full year 2019 include:
- Attained 172 percent organic reserve replacement with an average three-year total finding and development cost of $12.95 per barrel of oil equivalent
- Transformed Murphy into an oil-weighted, Western Hemisphere focused company by closing two significant transactions with the Malaysia divestiture and Gulf of Mexico acquisition
- Increased average daily oil production from continuing operations by 66 percent, with total average daily production rising 41 percent from 2018 levels
- Completed the $500 million share repurchase program, resulting in a total share count reduction of 12 percent, or approximately 20.7 million shares, to 152.9 million shares
- Generated $1.5 billion of adjusted EBITDA, or $23.99 per barrel of oil equivalent sold
- Drilled successful exploration wells in Vietnam, Gulf of Mexico and offshore Mexico
- Increased reserve life to 11.8 years
Highlight subsequent to year-end 2019:
- Entered into memorandum of understanding regarding Murphy’s 50 percent ownership in the King’s Quay floating production system
FOURTH QUARTER 2019 RESULTS
The company recorded a net loss, attributable to Murphy, of $72 million, or $0.46 net loss per diluted share, for the fourth quarter 2019. Adjusted net income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, was $25 million, or $0.16 per diluted share for the same period. The adjusted income from continuing operations excludes the following primary after-tax items: a $106 million non-cash mark-to-market loss on crude oil derivatives and a $25 million loss on extinguishment of debt. Details for fourth quarter results can be found in the attached schedules.
Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations attributable to Murphy was $404 million, or $22.94 per barrel of oil equivalent (BOE) sold. Adjusted earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) from continuing operations attributable to Murphy was $424 million, or $24.05 per BOE sold. Details for fourth quarter EBITDA and EBITDAX reconciliations can be found in the attached schedules.
Fourth quarter production averaged 194 thousand barrels of oil equivalent per day (MBOEPD) with 59 percent oil and 67 percent liquids. Production was impacted by total unplanned downtime of 8 MBOEPD for the quarter. Non-operated, unplanned downtime was 1,900 barrels of oil equivalent per day (BOEPD) across various fields in the Gulf of Mexico and 1,000 BOEPD at Terra Nova in offshore Canada.
Operated unplanned downtime of 1,500 BOEPD in the Gulf of Mexico was primarily due to a subsea equipment malfunction at Neidermeyer (Mississippi Canyon 209), causing a five-day impact on the three-well field. One well remains down during equipment repairs, which are expected to be complete by second quarter 2020.
Operated production variances of 3,600 BOEPD in the Eagle Ford Shale were the result of well workover activity on higher rate wells in Catarina, as well as new East Tilden wells outperforming historical Tilden wells but producing below their corporate forecast for the quarter. The majority of the Catarina workovers were complete by the end of fourth quarter 2019 and are currently producing in line with expectations. Details for fourth quarter production can be found in the attached schedules.
FULL YEAR 2019 RESULTS
The company recorded net income, attributable to Murphy, of $1.1 billion, or $6.98 per diluted share, for the full year 2019. The company reported adjusted income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, of $144 million, or $0.87 per diluted share. Details for full year 2019 results can be found in the attached schedules.
Production for the full year averaged 173 MBOEPD and consisted of 60 percent oil and 67 percent liquids volumes. Details for 2019 production can be found in the attached tables.
“Over the course of 2019, we executed two noteworthy transactions as we continued to strategically transform our asset base. Our new portfolio generated strong net income in 2019, supported by increased oil production and positive differentials to West Texas Intermediate oil pricing. This growth led to additional cash flow generation which, in addition to proceeds from the sale of Malaysia, allowed us to return more than $660 million to shareholders through share repurchases and a competitive dividend,” stated Roger W. Jenkins, President and Chief Executive Officer.
FINANCIAL POSITION
In the fourth quarter, Murphy issued $550 million of 5.875 percent senior notes due 2027. Proceeds were used to redeem approximately $240 million of the 4.0 percent senior notes due 2022 and $281 million of the 3.7 percent notes due 2022.
The company had $2.8 billion of outstanding long-term, fixed-rate notes at the end of fourth quarter 2019. The fixed-rate notes had a weighted average maturity of 7.7 years and a weighted average coupon of 5.8 percent.
As previously announced, Murphy completed its $500 million share repurchase program. The remaining $94 million under the authorization was used to repurchase 4.3 million shares in the fourth quarter. Over the course of the year, Murphy reduced its outstanding shares by approximately 12 percent, or 20.7 million shares, from 173.6 million shares as of April 30 to 152.9 million shares outstanding at completion of the program on October 4, 2019.
As of December 31, 2019, Murphy had approximately $1.9 billion of liquidity, comprised of a fully undrawn $1.6 billion senior unsecured credit facility and approximately $307 million of cash and cash equivalents.
YEAR-END 2019 PROVED RESERVES
Murphy’s preliminary year-end 2019 proved reserves were 800 million barrels of oil equivalent (MMBOE), consisting of 50 percent oil and 57 percent liquids. Total proved reserves were 2 percent lower than at year-end 2018 as a result of the Malaysia divestiture and 2019 production, which were largely offset by the Gulf of Mexico acquisition, improvements to reserves from revisions and extensions across the business. Excluding Malaysia proved reserves of 129 MMBOE at year-end 2018, Murphy increased its proved reserves by 17 percent in 2019.
The company achieved organic reserve replacement of 172 percent with a three-year total finding and development cost of $12.95 per BOE.
|
2019 Proved Reserves – Preliminary * |
||||||||
|
Category |
Net Oil (MMBBL) |
Net NGLs (MMBBL) |
Net Gas |
Net Equiv. |
||||
|
Proved Developed (PD) |
213 |
27 |
1,272 |
452 |
||||
|
Proved Undeveloped (PUD) |
189 |
28 |
788 |
348 |
||||
|
Total Proved |
402 |
55 |
2,060 |
800 |
||||
|
* |
Reserves are based on preliminary SEC year-end 2019 audited proved reserves and exclude noncontrolling interest |
“With the transition out of Malaysia, increasing our Gulf of Mexico business, and continued investment in our onshore businesses, we have been able to maintain a sizeable asset base – all while maintaining our liquids weighting at 57 percent. I am also pleased with an increase in our proved developed reserves to 57 percent from 50 percent and our competitive three-year total finding and developing cost metric of $12.95 per BOE,” stated Jenkins.
Recent Company Earnings:
April 27, 2021
Editor’s Note: Range Resources gave the keynote lunch address at EnerCom Dallas – The Energy Investment & ESG Conference earlier this month. Dennis Degner, Sr. Vice President, Chief Operating Officer for Range discussed the company’s ESG goals and accomplishments. A replay of the discussion and a download of the presentation can be found on the conference website – Range Resources – EnerCom Dallas.
FORT WORTH, Texas, April 26, 2021 (GLOBE NEWSWIRE) — RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its first quarter 2021 financial results.
Highlights –
- Realizations before index hedges of $3.20 per mcfe, or approximately $0.51 above NYMEX natural gas
- Pre-hedge NGL realization of $26.35 per barrel, highest since late 2018
- NGL differential of $1.52 per barrel above Mont Belvieu, best in Company history
- Natural gas differentials, including basis hedging, averaged $0.14 per mcf below NYMEX
- Production averaged 2,081 Mmcfe per day, approximately 70% natural gas
- All-in first quarter capital spending was $105 million, approximately 25% of the annual budget
- Approximately 45% of pre-hedge revenue from liquids sales
- In March, Range’s $3.0 billion borrowing base and $2.4 billion elected commitment were reaffirmed
- In April, Range redeemed approximately $63.3 million of senior notes and senior subordinated notes due between 2021 and 2023
Commenting on the quarter, Jeff Ventura, the Company’s CEO said, “Range continues to make progress on key near-term objectives: improving margins with a focus on cost structure, generating free cash flow, enhancing liquidity, and operating safely while maintaining peer-leading capital efficiency. There were sizable improvements in pricing quarter-over-quarter leading to Range’s $193 million in cash flow from operations before changes in working capital. The corresponding capital spending of $105 million generated solid free cash flow for the quarter.
Range remains committed to disciplined capital spending and generating sustainable free cash flow. Over time, we believe Range will be differentiated as a result of our low sustaining capital, competitive cost structure, marketing strategies, environmental leadership and importantly, our multi-decade core inventory life, which will be an increasing competitive advantage in the years to come.”
Financial Discussion
Except for generally accepted accounting principles (GAAP) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market adjustment on derivatives, stock-based compensation and other items shown separately on the attached tables. “Unit costs” as used in this release are composed of direct operating, transportation, gathering, processing and compression, production and ad valorem taxes, general and administrative, interest and depletion, depreciation and amortization costs divided by production. See “Non-GAAP Financial Measures” for a definition of each of the non-GAAP financial measures and the tables that reconcile each of the non-GAAP measures to their most directly comparable GAAP financial measure.
First Quarter 2021
GAAP revenues for first quarter 2021 totaled $626 million, GAAP net cash provided from operating activities (including changes in working capital) was $109 million, and GAAP net income was $27 million ($0.11 per diluted share). First quarter earnings results include a $58 million derivative fair value loss due to increases in commodity prices.
Non-GAAP revenues for first quarter 2021 totaled $645 million, and cash flow from operations before changes in working capital, a non-GAAP measure, was $193 million. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $73 million ($0.30 per diluted share) in first quarter 2021.
The following table details Range’s average production and realized pricing for first quarter 2021(a):
| 1Q21 Production & Realized Pricing | ||||||||||||||||
| Natural Gas (Mcf) |
Oil (Bbl) | NGLs (Bbl) |
Natural Gas Equivalent (Mcfe) |
|||||||||||||
| Net Production per day | 1,448,097 | 8,422 | 97,144 | 2,081,493 | ||||||||||||
| Average index price(b) | $ | 2.69 | $ | 58.06 | $ | 24.83 | ||||||||||
| Differential | (0.11 | ) | (9.06 | ) | 1.52 | |||||||||||
| Basis hedging | (0.03 | ) | – | – | ||||||||||||
| Realized prices before index hedges | $ | 2.55 | $ | 49.00 | $ | 26.35 | $ | 3.20 | ||||||||
| Settled index hedges | 0.02 | (9.40 | ) | (3.54 | ) | (0.19 | ) | |||||||||
| Average realized prices after hedges | $ | 2.57 | $ | 39.59 | $ | 22.82 | $ | 3.01 | ||||||||
| (a) May not add due to rounding | ||||||||||||||||
| (b) Indexes include NYMEX-Henry Hub, NYMEX-WTI and OPIS-Mont Belvieu for natural gas, oil and NGLs, respectively | ||||||||||||||||
Total production for first quarter 2021 averaged approximately 2,081 net Mmcfe per day. By area, southwest Marcellus production averaged 2.0 Bcfe per day while the northeast Marcellus assets averaged 77 net Mmcf per day during the quarter.
First quarter 2021 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $3.01 per mcfe.
- The average natural gas price, including the impact of basis hedging, was $2.55 per mcf, or a ($0.14) per mcf differential to NYMEX. The first quarter natural gas differential includes the benefit of improved regional basis and positive impact of higher daily prices in February. The Company’s average 2021 natural gas differential to NYMEX remains within an expected range of ($0.30) to ($0.40) per mcf.
- Pre-hedge NGL realizations were $26.35 per barrel, an improvement of $8.33 per barrel versus the fourth quarter of 2020 driven by an improving market for propane and heavier products. At a $1.52 premium over Mont Belvieu equivalent, the first quarter premium was the best in Company history. Range continues to see strong NGL export premiums at Marcus Hook because of the Company’s access to international markets and diversified portfolio of sales agreements. As a result of these improvements, the Company expects to average a pre-hedge premium differential to Mont Belvieu equivalent of $0.50 – $2.00 per barrel for 2021.
- Crude oil and condensate price realizations, before realized hedges, averaged $49.00 per barrel, or $9.06 below WTI (West Texas Intermediate). Range expects an improving condensate differential to WTI during 2021, between $7-$9 below NYMEX, as regional production continues to decline and demand for transportation fuels recovers.
The following table details Range’s unit costs per mcfe(a):
| Expenses | 1Q 2021 ($/Mcfe) |
1Q 2020 ($/Mcfe) |
Increase (Decrease) |
|||||
| Direct operating(a) | $ | 0.09 | $ | 0.15 | (40%) | |||
| Transportation, gathering, processing and compression | 1.46 | 1.36 | 7% | |||||
| Production and ad valorem taxes | 0.02 | 0.04 | (50%) | |||||
| General and administrative(a) | 0.15 | 0.16 | (6%) | |||||
| Interest expense(a) | 0.29 | 0.22 | 32% | |||||
| Total cash unit costs(b) | 2.02 | 1.93 | 5% | |||||
| Depletion, depreciation and amortization (DD&A) | 0.47 | 0.49 | (4%) | |||||
| Total unit costs plus DD&A(b) | $ | 2.50 | $ | 2.43 | 3% | |||
| (a) Excludes stock-based compensation, legal settlements and amortization of deferred financing costs. | ||||||||
| (b) May not add due to rounding. | ||||||||
Capital Expenditures
First quarter 2021 drilling and completion expenditures were $97.1 million. In addition, during the quarter, $6.4 million was invested on acreage leasehold and $1.9 million on gathering systems and other. First quarter investments represent approximately 25% of Range’s total capital budget of $425 million in 2021.
Financial Position
In January 2021, Range issued $600.0 million aggregate principal amount of 8.25% senior notes due 2029 and used net proceeds to repay borrowings under its bank credit facility. In April 2021, Range redeemed outstanding principal amounts of senior notes due in 2021 and 2022 totaling approximately $26.0 million and senior subordinated notes due in 2021, 2022 and 2023 totaling approximately $37.3 million. Proforma the April redemptions, Range has approximately $218 million in notes that mature through 2022, which are expected to be redeemed via free cash flow at current strip pricing.
Range’s $3.0 billion borrowing base and $2.4 billion commitment amount were reaffirmed during first quarter 2021 with no changes to financial covenants. The credit facility matures on April 13, 2023 and is subject to semi-annual redeterminations. As of March 31, 2021, Range had total debt outstanding of $3.1 billion, consisting of $124 million in bank debt, $3.0 billion in senior notes and $37 million in senior subordinated notes. The Company had over $1.9 billion of borrowing capacity under the current commitment amount at the end of the first quarter.
Operational Activity
The table below summarizes estimated activity for 2021 regarding the number of wells to sales for each area.
| Wells TIL 1Q 2021 |
Calendar 2021 Planned TIL |
Remaining 2021 |
|||||
| SW PA Super-Rich | 6 | 17 | 11 | ||||
| SW PA Wet | 3 | 18 | 15 | ||||
| SW PA Dry | 7 | 24 | 17 | ||||
| Total Wells | 16 | 59 | 43 |
NGL Marketing and Transportation
Range’s liquids marketing continued to expand premiums relative to Mont Belvieu pricing, with first quarter NGL realizations averaging a $1.52 premium per barrel, a best in Company history. The portfolio of domestic and international ethane contracts performed very well during the quarter and generated a significant uplift relative to Mont Belvieu while propane and butane markets benefited from an increase in Marcus Hook export premiums and a supportive macro environment.
Starting April 2021, Range will have an additional 5,000 barrels per day of Mariner East capacity, which is expected to be fully utilized with existing production. In addition, Range has secured new and diverse LPG export-related contracts. These contracts add flexibility, reduce costs, and further enhance realized propane and butane prices, and continue the momentum of achieving strong export premiums. Range expects near-term and long-term benefits of NGL exports out of the Northeast as international demand for NGL products continues to grow. NGL exports out of Marcus Hook provide Range a unique supply option for that demand. In 2021, Range expects to export over 80% of its propane and butane, the highest percentage of propane and butane exported by any U.S. independent, leading to strong year-over-year improvements in NGL pricing and margins. Higher realized NGL prices for Range in 2021 will lead to a slight increase in processing costs as Range’s processing costs are based on the NGL revenue received, providing a partial hedge against NGL price fluctuations.
Including the impact of basis hedging, Range had a natural gas differential of ($0.14) per mcf during the first quarter. The Company’s transportation portfolio provides access to natural gas markets in the Gulf Coast, Midwest, and Northeast, with each region benefiting from strong daily sales prices in February. This revenue uplift was partially offset by higher natural gas fuel cost during the quarter which is reflected in transportation, gathering, processing and compression expense. Range remains on track with its natural gas differential to NYMEX guidance of ($0.30) – ($0.40) for the year.
Guidance – 2021
Capital & Production Guidance
Range’s 2021 all-in capital budget is $425 million. Production for full-year 2021 is expected to average approximately 2.15 Bcfe per day, with ~30% attributed to liquids production.
Full Year 2021 Expense Guidance
| Direct operating expense: | $0.09 – $0.11 per mcfe |
| Transportation, gathering, processing and compression expense: | $1.35 – $1.40 per mcfe |
| Production tax expense: | $0.02 – $0.04 per mcfe |
| Exploration expense: | $20.0 – $28.0 million |
| G&A expense: | $0.15 – $0.16 per mcfe |
| Interest expense: | $0.26 – $0.28 per mcfe |
| DD&A expense: | $0.47 – $0.50 per mcfe |
| Net brokered gas marketing expense: | $2.0 – $10.0 million |
Full Year 2021 Price Guidance
Based on current market indications, Range expects to average the following price differentials for its production in 2021.
| Natural Gas:(1) | NYMEX minus $0.30 to $0.40 |
| Natural Gas Liquids (including ethane):(2) | Mont Belvieu plus $0.50 to $2.00 per barrel |
| Oil/Condensate: | WTI minus $7.00 to $9.00 |
(1) Including basis hedging
(2) Weighting based on 53% ethane, 27% propane, 7% normal butane, 4% iso-butane and 9% natural gasoline.
Hedging Status
Range hedges portions of its expected future production volumes to increase the predictability of cash flow and to help maintain a strong, flexible financial position. As of April 16, 2021, Range had approximately 70% of its remaining expected 2021 natural gas production hedged at an average ceiling price of $2.79 per Mmbtu and an average floor price of $2.60 per Mmbtu. Similarly, Range hedged approximately 70% of its remaining estimated 2021 crude oil production at an average floor price of $52.00 per barrel and approximately 20% of its remaining expected 2021 NGL revenue. Please see the detailed hedging schedule posted on the Range website under Investor Relations – Financial Information.
Range has also hedged Marcellus and other basis for natural gas and NGL exports to limit volatility between benchmarks and regional prices. The combined fair value of the natural gas basis, NGL freight and spread hedges as of March 31, 2021 was a net gain of $10 million.
Conference Call Information
A conference call to review the financial results is scheduled on Tuesday, April 27 at 9:00 a.m. ET. To participate in the call, please dial (877) 928-8777 and provide conference code 3782655 about 10 minutes prior to the scheduled start time.
A simultaneous webcast of the call may be accessed at www.rangeresources.com. The webcast will be archived for replay on the Company’s website until May 27.
February 18, 2021
TC Energy Corp reported a 13.4% rise in fourth-quarter comparable profit on Thursday, partly helped by lower operating costs for its U.S. natural gas pipelines.
Source: Reuters
The company behind the Keystone XL oil pipeline, work on which was halted after U.S. President Joe Biden revoked the permit, had said it expects to record a large non-cash charge in its first-quarter earnings, but did not provide the size of it.
TC Energy said it continues to expect its Coastal Gaslink pipeline in British Columbia to be in service by 2023.
Its construction has faced opposition from environmentalists and was disrupted due to restriction imposed by the provincial government to fight the spread of COVID-19 infections after the Christmas holiday break.
The company said due to this project costs for the pipeline will increase significantly and the schedule will be delayed further.
Earnings from the companies U.S. and Canadian natural gas pipelines rose more than 9% each in the quarter.
Comparable earnings rose to C$1.1 billion ($867.30 million), or C$1.15 per share, in the quarter ended Dec. 31, from C$970 million, or C$1.03 per share, a year earlier.
($1 = 1.2683 Canadian dollars)
February 12, 2021
January 22, 2021
Schlumberger NV on Friday joined rivals in predicting a steady recovery in the oil industry this year after the world’s top oilfield services provider’s fourth-quarter results beat estimates, aided partly by growing demand for drilling.
Source: Reuters
Easing of COVID-19 related restrictions has propelled oil demand and prices, which remain stable since a late-2020 rebound from historic lows. Brent crude, which averaged at $45 per barrel in the last quarter of 2020, hovered around $55 on Friday.
Schlumberger Chief Executive Officer Olivier Le Peuch said he was optimistic about demand recovery through this year, as rivals Halliburton Co and Baker Hughes Co have noted, giving investors hope the oil downturn was nearing an end.
However, Le Peuch’s timeline for a full recovery to 2019 level no later than 2023 was behind Halliburton’s view of a rebalancing next year. Baker Hughes also sees strong investment growth in 2022.
Still, Le Peuch said the reset could happen sooner, as some analysts have noted in recent weeks, with international recovery accelerating from second quarter this year and North America activity continuing to build upwards after a strong start to the year.
“Our hypothesis going forward is that the market supply share will rebalance slightly, will favor international and will, as a consequence, pull international activity to 100% or more in the next 2 or 3 years,” he told analysts on a post earnings call.
Schlumberger’s shares were down 1.4% at $24.86in early trading, outperforming rivals and other energy stocks that fell more on latest COVID-19 related restrictions in China. [O/R]
Total revenue of $5.53 billion in the fourth quarter beat analysts’ estimates of $5.25 billion. It’s the first quarter-over-quarter increase in revenue for Schlumberger since the third quarter of 2019.
Since taking over in July 2019, Le Peuch has focused on reshaping Schlumberger through thousands of job cuts, other steep cost cuts and divesting unprofitable businesses, actions that have been received well by Wall Street.
“Schlumberger ripped the cover off the ball with these results,” Tudor, Pickering, Holt and Co analysts wrote in a note on Friday, saying the strong performance wasn’t a big surprise due to the yeoman’s work around cost cuts and improving margins and incremental fee cash flow.
Aided by cost cuts, Schlumberger’s net income excluding charges and credits came in at 22 cents per share in the quarter ended Dec. 31, which also beat estimates of 17 cents, according to Refinitiv IBES data.
In light of the anticipated demand recovery, Schlumberger forecast capital investments this year of between $1.5 billion and $1.7 billion, a slight improvement at the midpoint of the range from last year’s $1.5 billion.
January 21, 2021
Oilfield equipment and services provider Baker Hughes Co on Thursday joined larger rival Halliburton Co in saying the energy industry’s worst downturn in decades would turn a corner this year.
Source: Reuters
Oil and gas producers have been forced to cut budgets, restructure operations and reduce employees, to tackle the COVID-19 pandemic-led fallout in energy demand and prices.
“We expect spending and activity levels to gain momentum through the year as the macro environment improves, likely setting up the industry for stronger growth in 2022,” Baker Hughes Chief Executive Officer Lorenzo Simonelli said.
Halliburton on Tuesday predicted a recovery in the global oil and gas industry from the second quarter of this year.
Demand for oilfield equipment and services recovered in the last three months of 2020, with producers completing more wells and drilling some, as crude prices averaged around $45 a barrel in the quarter. Global crude prices hovered around $56 per barrel on Thursday.
Baker Hughes’ adjusted operating profit nearly doubled to $462 million in the fourth quarter ended Dec. 31, compared with the third.
The company has cut its budget, restructured operations, reduced the number of employees, closed facilities and accelerated the exit of non-core products to save cash and cushion the blow from the fallout in demand due to the pandemic.
Total revenue for the reported quarter rose nearly 9% to $5.5 billion, compared with the third, and also beat estimates of $5.42 billion, according to Refinitiv IBES data.
The total revenue was down 13.4% and adjusted operating profit 15.4% lower from a year earlier, as drilling activity was well below last year’s levels.
Halliburton also posted a better-than-expected profit on Tuesday, while top oilfield service provider Schlumberger NV is expected to report results on Friday.
Baker Hughes’s shares were up 3.7% at $23.75 in premarket trading.
November 13, 2020
MOSCOW – Fallout from the pandemic and a weaker rouble sent Russian energy giant Rosneft ROSN.MM to a third-quarter net loss of 64 billion roubles ($827 million) from net income of 43 billion roubles in the previous quarter, the company said on Friday.
Source: Reuters
However, plans to extend a share buyback programme until the end of 2021, announced later during a conference call with investors, helped its shares reverse earlier losses.
Rosneft, the world’s second-largest oil producer by output behind Saudi Aramco 2222.SE, was forced to reduce oil production in line with the OPEC+ supply pact aimed at stabilising global markets.
The company’s oil and gas condensate output for the July to September period was down 3.2% from the previous quarter at 3.91 million barrels per day.
It also had to contend with the coronavirus crisis. Its headquarters was placed on a 30-hour working week and pandemic-related costs for the first nine months of the year amounted to 5 billion roubles ($65 million).
Rosneft’s shares were 0.2% higher by 1350 GMT.
The company proposed a $2 billion share buyback in May 2018 to reduce debt and boost investor returns. It eventually started making open market repurchases in March 2020, and had initially planned to complete the programme by year-end.
The company’s earnings before interest, tax, depreciation and amortisation in the third quarter more than doubled from the previous three months to 366 billion roubles.
Run by one of President Vladimir Putin’s closest allies, Igor Sechin, Rosneft had long opposed output production cuts in tandem with OPEC but has been overruled by the president, who is keen to deepen political cooperation with the Middle East.
The company, in which BP BP.L owns a 19.75% stake, said it still planned capital expenditure of 1 trillion roubles in 2021, but the eventual amount depends on how the OPEC+ deal evolves.
The company has had to buy oil from third parties to meet its obligations amid the production curbs.
Rosneft said it bought 27.4 million barrels on global markets in the third quarter, up 35% from the second quarter.
November 6, 2020
Cheniere Energy Inc LNG.A reported earnings on Friday that missed analysts estimates and said it expects to complete the third train at its Corpus Christi liquefied natural gas (LNG) export plant in Texas in the first quarter of 2021.
Source: Reuters
Previously, Cheniere, the biggest U.S. LNG company, said it expected to complete Corpus 3 in the first half of 2021.
In what has been a tough year for the LNG industry due to coronavirus demand destruction, Cheniere said its earnings per share were minus $1.84 in the third quarter.
That fell short of the minus 33 cents analysts estimated and compared with minus $1.25 in the third quarter last year.
Cheniere said that revenue was $1.46 billion in the quarter, which fell short of the $1.96 billion analysts estimated and compared with $2.17 billion in the same quarter last year.
Cheniere also said it still plans the “substantial completion” of the sixth train at its Sabine Pass LNG export plant in Louisiana in the second half of 2022.
Cheniere said Corpus 3 was 96.7% complete and Sabine 6 was 70.9% complete. Each train will be capable of producing about 5 million tonnes per annum (MTPA) of LNG, equivalent to around 0.66 billion cubic feet per day (bcfd) of natural gas.
As of Sept. 30, Cheniere said it has spent about $1.8 billion of the roughly $2.5 billion contract price to build Sabine 6 and about $2.3 billion of the roughly $2.4 billion contract price to build Corpus 3.
Bechtel Corp, which has a history of building liquefaction trains for Cheniere under budget and ahead of schedule, is also working on the new trains.
In addition, Cheniere said the final investment decision (FID) for the Corpus Stage 3 expansion will be subject to entering a construction contract, obtaining additional commercial support and securing financing.
July 22, 2020
May 11, 2020
HOUSTON, May 11, 2020 /PRNewswire/ — Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three months ended March 31, 2020.
Presentation slides accompanying this earnings release are available on the Company’s website at www.callon.com located on the “Presentations” page within the Investors section of the site.
May 4, 2020
April 28, 2020
Energy giant BP reported a significant fall in first-quarter net profit on Tuesday, as oil prices continue to dive amid intensifying concerns about the coronavirus crisis and dwindling storage capacity.
Source: CNBC
The U.K.-based oil and gas company posted first-quarter underlying replacement cost profit, used as a proxy for net profit, of $800 million. That compared with $2.4 billion in the first quarter of 2019, reflecting a fall of 67%.
Analysts had expected first-quarter underlying replacement cost profit to come in at $987 million, according to data compiled by Refinitiv.
“A good quarter but, undoubtedly, a very brutal environment,” BP CEO Bernard Looney told CNBC’s “Squawk Box Europe” on Tuesday.
BP’s results come shortly after a historic plunge in oil prices. The May contract of U.S. West Texas Intermediate plunged below zero to trade in negative territory for the first time in history last week. Trading volume was thin given it was the day before the contract’s expiration date, but the move lower was unprecedented nonetheless.
WTI futures had fetched more than $60 a barrel at the start of the year. A dramatic fall-off in demand as a result of the coronavirus outbreak has sent oil prices tumbling.
On Tuesday, the June contract of WTI traded at $11.36 per barrel, more than 11% lower for the session, while international benchmark stood at $20.22, up around 1%.
“The real situation that we have here is a fundamental situation of supply and demand,” Looney said. “Demand in the second quarter, we think, will be down around 16 million barrels per day worldwide this year. And that’s about five times the previous demand destruction which we saw in the global financial crisis in 2008 to 2009.”
Shares of BP, which edged into positive territory during mid-morning deals, have fallen approximately 35% since the start of the year.
Dividend confirmed
BP’s debt rose to $51.4 billion at the end of the first quarter, $6 billion higher than the quarter before. And the firm’s debt-to-capital ratio, or gearing, jumped to 36% through the first three months of the year.
The company also announced a dividend of 10.5 cents per share was announced for the quarter.
“The board of BP reviewed the dividend in the first quarter as usual and reviewed it in full and the decision was made to pay that dividend based on the underlying performance of the business in the first quarter and based on the actions we are taking,” Looney told CNBC on Tuesday.
Last week, Norway’s Equinor became the first oil major to cut its dividend this earnings season which had raised concerns that other oil majors may follow suit.
“There will be a sigh of relief from many retail investors that BP has committed to paying a dividend,” Stuart Lamont, investment manager at Brewin Dolphin, told CNBC via email.
“There had been a great deal of debate about what the failure to do so would mean for income investors, who will now have a close eye on Royal Dutch Shell’s results later this week,” Lamont said.
Net-zero by 2050
On February 12, BP’s Looney published a statement entitled “Reimagining energy, reinventing BP.” It outlined the energy firm’s long-term goal of becoming a net-zero company by 2050 “or sooner.”
When asked whether the ongoing impact of the coronavirus crisis had altered his outlook for the business, Looney said there were three reasons to explain why he was now “even more” committed to pursuing this goal.
“Number one, I don’t think this pandemic does anything but add to the challenge for oil outlooks in the future,” Looney said.
“The second is I think it has reminded people in society of the frailty of our ecosystem … People are looking at clear skies and the beauty of that and I think, while we have got different priorities right now, I think people will be very focused on that in the medium term,” he continued.
“Finally, we talked about negative WTI prices last week, Lightsource BP, where we are a 50% shareholder … is letting contracts for 400 megawatts of solar power in the United States. So, there is something about that sector that I think is providing a real attractive proposition for investors and is very resilient at times like this,” Looney added.
April 1, 2020
March 3, 2020
At its annual Security Analyst Meeting today, Chevron Corporation (NYSE: CVX) announced expectations to deliver leading shareholder returns through disciplined capital spending, improved cost efficiency, and continued cash flow growth over the next five years.
February 24, 2020
Superior Drilling Products, Inc. (NYSE American: SDPI) (“SDP” or the “Company”), a designer and manufacturer of drilling tool technologies, today announced unaudited preliminary revenue for the year ended December 31, 2019, was $19.0 million, up 4% from the prior year. Fourth quarter 2019 preliminary revenue included approximately $600 thousand from the rental of the Company’s well bore conditioning tool, the Drill-N-Ream® (DNR) in the Middle East, or almost half of SDP’s total Middle East revenue for the year. For the year, international revenue nearly quadrupled to $1.3 million compared with $360 thousand in 2018. At the end of 2019, SDP had $1.2 million in cash. Preliminary results are subject to change pending review by the Company’s independent accountants.
