Tag: OIL

After a 2.3 percent increase the previous session, US West Texas Intermediate (WTI) futures were down 0.1 percent at $71.86.
After OPEC and allied nations signed a tentative deal to raise oil output, oil futures fell roughly 7% on Monday, owing to fears about the spread of the COVId-19 delta variant and concerns about oversupply.
The Energy Information Administration (EIA) reported earlier this week that gasoline stockpiles fell by 100,000 barrels last week, while distillate stockpiles fell by 1.3 million barrels.
The EIA report also showed a drop in crude stockpiles at the storage hub in Cushing, Oklahoma, to the lowest level in about seven months.

(Source: RTT News)
General Advice Warning
Any advice/ information provided is general in nature only and does not take into account the personal financial situation, objectives or needs of any particular person.

August West Texas Intermediate Crude oil futures closed at $72.94 a barrel, up $0.74 or nearly 1%.

Brent crude futures were trading at $74.19 a barrel, up $0.76 or 1.03 percent.

Crude stocks in the United States declined by 6.866 million barrels last week, significantly more than the predicted reduction of 4.03 million barrels, according to data issued by the US Energy Information Administration (EIA) this morning.

Distillate stockpiles surged by 1.616 million barrels last week, much exceeding the 171,000 barrels projected gain, while gasoline inventories fell by over 6 million barrels, about three times the predicted reduction.

According to a report released late Wednesday by the American Petroleum Institute (API), oil stocks in the United States decreased by 8.0 million barrels last week.

Since demand fell during the corona virus outbreak, OPEC+ has been limiting supply for more than a year. Investors are now concerned that the lack of a new supply agreement will force big oil producers to ramp up output much more quickly.

(Source: Rtt News)

General Advice Warning

Any advice/ information provided is general in nature only and does not take into account the personal financial situation, objectives or needs of any particular person.

Meanwhile, vaccination rates continue to rise in much of the developed world, where a nearly normal summer seems to be in the works. As such, our forecast for a full recovery in demand in 2022 looks safe.

At the same time, supply remains constrained. OPEC has reiterated its plan to bring back volumes in a measured way, which should allow for a resumption of Iranian volumes if a deal is reached to do so. In the United States, public companies have not shown a willingness to increase spending, meaning volume growth will remain tepid. The combined effect is a continued drawdown in inventories over the next 18 months. The market seems to agree, having pushed Brent prices back to $70/barrel. As supply typically lags demand, prices could be headed higher.

• We have slightly lowered our 2021 demand forecast to account for India, but 2022 demand remains unchanged and above 2019 levels. In 2023, we expect record-high global oil demand of 101.7 million barrels a day.
• At its June 1 meeting, OPEC+ reaffirmed planned supply additions of 350 thousand b/d in May, 350 mb/d in June, and 450 mb/d in July as it remains cautiously optimistic for a rear-end 2021 recovery.
• The U.S. rig count increased in May to 372, twice the number in mid-August last year, but even with West Texas Intermediate crude prices approaching $70/bbl, further additions will be limited.

OPEC Wary of Pandemic Setbacks but Goes Ahead With Planned Increases

OPEC+ reaffirmed that it will proceed with the easing of production cuts that it proposed the meeting prior. The cartel will go forth with its planned additions of 350 mb/d in May, 350 mb/d in June, and 450 mb/d in July, while acknowledging pandemic-driven headwinds in many parts of the world. Members declined to adjudicate on production policy past July, but further upticks are likely (the group meets again on the first of the month). Despite vaccination shortages and mounting coronavirus cases throughout much of Asia and Latin America, OPEC remains cautiously optimistic for a rear-end 2021 recovery; its total oil estimate is unchanged from last month.

During April, the producers participating in the cuts produced 21.1 mmb/d, almost exactly in line with the combined target. These producers have held volumes flat for three straight months now, but the cartel expects to gradually ramp up output in the summer. De facto head Saudi Arabia is also expected to bump up its own production after enduring self-imposed incremental cuts. Overall, conformity with agreed production ceilings has been strong since the pandemic began, but it remains to be seen if OPEC members can be trusted to accelerate production at the agreed rate; historically, the cartel has struggled with producers willing to sacrifice group targets for their own benefit. We forecast an incremental 2.2 mmb/d and 4.2 mmb/d, respectively, in 2021 and 2022 from OPEC, Russia, and Kazakhstan combined.

Iran seem to be edging closer to a resolution as negotiations in Vienna motor onward and are optimistic that an agreement can be reached by August. If so, Iranian production, which has steadily increased in the past six months, could see the floodgates burst open. However, this sentiment was tempered by the International Atomic Energy Agency, which chastised the country in a June 1 report for failing to explain undeclared nuclear material at multiple locations. Iranian output fell over 1.5 mmb/d when the current sanctions came into effect, so an agreement could materially boost supply in the region. We’d argue, though, that the rest of OPEC would be willing to make sacrifices to accommodate these volumes (despite Iran-Saudi tensions). Otherwise, the cartel’s progress reducing inventories since the peak of the pandemic would be quickly undone, and the market would be thrown back into oversupply.

Source:Morningstar

Disclaimer

General Advice Warning

Any advice/ information provided is general in nature only and does not take into account the personal financial situation, objectives or needs of any particular person.

Management has significantly improved disclosure, earnings streams have been materially diversified and the investment strategy has consistently generated high returns on invested capital. We expect a well-supplied lithium market in the longer term, coupled with weaker demand growth for steel, particularly from China, to drive lower prices and reduce the pool of available contracting work. Despite this, we think Mineral Resources can drive EPS growth on volume.

Key Considerations

• Management has significantly improved disclosure, earnings streams have been materially diversified and the investment strategy has consistently generated high returns on invested capital.

• We think the business model is demonstrably sustainable, centring on Mining Services around Australian bulk commodities.

• Mineral Resources will selectively own and develop its own mining operations, though with the aim of subsequent sell down while retaining core processing and screening rights.

• Mineral Resources grew strongly since listing in 2006. The chairman and managing director have been with the business for over a decade and have meaningful shareholdings.

• Australian iron ore is mainly purchased by Chinese steel producers, meaning Mineral Resources offers leveraged exposure to Chinese economic growth.

• Mineral Resources has a recurring base of revenue and earnings from processing infrastructure.

• Mineral Resources’ balance sheet is very strong with net cash. This has opened up the opportunity for lithium investments selling into highly receptive markets.

• Mineral Resources’ profits are exposed to volatile iron ore price. We expect future iron ore prices to be much less favourable than the decade-long boom to 2014.

• Investments developing lithium bear fruit now in a booming market, but a strong third-party supply response into a small market risks hollowing out returns.

• Mineral Resources has poor geographic diversification, with a high dependence on capital activity in Western Australia. Mineral Resources is highly dependent on likely Chinese demand for iron ore.

 (Source: Morningstar)

Disclaimer

General Advice Warning

Any advice/ information provided is general in nature only and does not take into account the personal financial situation, objectives or needs of any particular person.

The long life Sierra Rutile operation is the key source of rutile but lacks a cost advantage. It may come in time as the company expands and builds scale economies. The new Cataby mine bolsters zircon output and maintains feedstock for the production of synthetic rutile. Iluka’s 20% ownership of Deterra Royalties brings exposure to the high-returning iron ore royalty over BHP’s Mining Area C. It is the sole moat-worthy asset but comprises less than 10% of our fair value estimate.

Key Considerations

• Iluka’s shares are undervalued with demand set to recover from coronavirus-inspired lows. Disruption to other suppliers is likely to see prices remain resilient despite lower demand.

• As a large producer of both zircon and high-grade titanium dioxide products (rutile and synthetic rutile), Iluka has some ability to flex output to meet either weak demand and strong demand.

• Reserve life is moderate at around 10 years but Iluka has a sizable resource base which covers at least 25 years of production at 2018 rates. We expect resources to convert to reserves as Iluka clears feasibility and technical hurdles.

• Iluka is an industry leader with relatively high grade zircon and rutile deposits. Supply can be withheld to defend prices and margins in times of weak demand.

• Management has improved company fortunes with a strong focus on returns on capital. Demand for zircon is likely to be bolstered by new applications such as chemicals and digitally printed tiles.

• Iluka has some diversification. The revenue mix is approximately half from zircon and half from highgrade titanium products. Geographically, revenue is split between North America, Europe, China and the rest of Asia.

• Mineral sands markets are relatively small. Sales volumes can go through periods of significant demand weakness, such as in 2008-09 and 2012-16.

• The largest single source of demand for zircon is China, accounting for nearly half. China could throttle back on fixed-asset investment-driven growth, which may see subdued zircon sales volumes and prices. OThe Jacinth Ambrosia deposit is very high-grade, with a large component of high-value zircon. Reserve life is less than 10 years and it will be nearly impossible to replicate the returns and competitive position once depleted.

 (Source: Morningstar)

Disclaimer

General Advice Warning

Any advice/ information provided is general in nature only and does not take into account the personal financial situation, objectives or needs of any particular person.

So there is no need to pay for cryogenic processing to extract NGLs from its wellhead gas volumes (saving it around $0.20 per thousand cubic feet). And because natural gas flows more easily out of a reservoir without liquids, the wells in this area are typically characterized by very high daily production rates.

As a result, the firm is among the lowest-cost natural gas producers in the Appalachia region, and this competitive advantage enables it to consistently deliver very strong returns on invested capital. But there is one catch: The Company’s acreage contains enough lucrative Lower Marcellus drilling opportunities to last until the late 2020s. Beyond that, the firm will have to rely on the overlying Upper Marcellus layer for growth, and such wells are typically up to 30% less productive. So it would be a mistake to think that all of the 3,000 or so potential drilling locations that the firm has access to will perform at the same level as the stellar wells it is drilling today. However, when the firm pivots to the Upper Marcellus, it will be able to reuse existing roads and pad sites, and as there are no well configuration constraints in this undeveloped interval, it could enhance returns by drilling longer laterals. As a result, we expect well costs to decrease enough to offset the dip in flow rates, leaving potential returns unchanged.

Our primary valuation tool is our net asset value forecast.

This bottom-up model projects cash flows from future drilling on a single-well basis and aggregates across the company’s inventory, discounting at the corporate weighted average cost of capital. Cash flows from current (base) production are included with a hyperbolic decline rate assumption. Our valuation also includes the mark-to-market present value of the company’s hedging program. We assume oil (West Texas Intermediate) prices in 2021 and 2022 will average $60 and $58 a barrel, respectively. In the same periods, natural gas (Henry Hub) prices are expected to average $3.20 per thousand cubic feet and $2.80/mcf. Terminal prices are defined by our long-term midcycle price estimates (currently $60/bbl Brent, $55/bbl WTI, and $2.80/mcf natural gas).

• After the Cimarex merger, the firm will have ideal real estate in the lowest-cost oil and natural gas basins, amplifying returns and boosting product and geographic diversification.
• By focusing on dry natural gas in the Marcellus, Cabot avoids NGL processing fees that would otherwise drive up production costs
• The firm is one of the few oil and gas producers that can consistently generate excess returns on invested capital at midcycle commodity prices.
• Cabot has less than 10 years’ worth of drilling opportunities targeting the prolific Lower Marcellus interval, and well performance could deteriorate when it is forced to pivot to the less productive Upper Marcellus.
• The firm’s midcontinent assets have significantly higher break-evens, and expanded development in the region could dilute returns.

About Cabot Oil & Gas

Houston-based Cabot Oil & Gas is an independent exploration and production company with operations in Appalachia. At year-end 2020, Cabot’s proved reserves were 13.7 trillion cubic feet of equivalent, with net production that year of approximately 2,344 million cubic feet of natural gas per day. All of Cabot’s production is Marcellus dry natural gas.

(Source: Morning star)

Disclaimer

General Advice Warning

Any advice/ information provided is general in nature only and does not take into account the personal financial situation, objectives or needs of any particular person.

The USD 19 billion PNG liquefied natural gas, or LNG, plant went a long way toward countering stagnating traditional oilfield productivity monetising isolated, but high-quality, gas resources. PNG gas is liquids-rich, which increases its value, but the entire proposition carries substantial risk because of investment needs and sovereign uncertainty. We expect near-term capital expenditure commitments to continue with expansion of the 29%-owned PNG LNG project, which produces 8.6 million metric tons per year. Production and earnings increased materially with the first LNG output in 2014. Oil Search has a debt-heavy balance sheet, as LNG was fully debt-funded.

Key consideration

• More than 80% of our Oil Search fair value estimate derives from just one product, LNG. LNG prices are referenced on a three-month running lag to the average  oil price. Any analysis of fair value depends on the successful prediction of oil prices and the maintenance of the link between them.

• Current earnings multiples are high, but the future is key. Earnings will rise when three additional PNG LNG trains are completed.

• We are not entirely comfortable with such a significant proportion of value in one project, particularly with PNG sovereign risk. We apply a high discount rate to our fair value estimate.

• Active in Papua New Guinea, or PNG, since 1929, Oil Search operates all producing oil fields in the country. The company has a long and profitable history of Highlands oil production, but the future value lies in substantial gas resources that were quarantined by a lack of infrastructure and high capital costs.

• Oil Search can service its $2.3 billion in net debt using LNG and oil cash flow. OGroup equity output tripled to 29 million barrels of oil equivalent with the startup of the PNG LNG project and can grow further with completion of additional trains.

• Past PNG LNG equity sell-downs by independents AGL Energy and IPIC were at prices considerably above levels credited in Oil Search’s share price.

• Capital costs may escalate in this difficult operating environment. The foundation LNG project cost blewout by $3.3 billion to a colossal $19 billion.

• Shareholders could see more heavy capital expenditure with a third PNG LNG train and other development projects.

• Oil Search is an all-or-nothing bet on PNG LNG. Single development- project risk and sovereign risk are concerns.

 (Source: Morningstar)

Disclaimer

General Advice Warning

Any advice/ information provided is general in nature only and does not take into account the personal financial situation, objectives or needs of any particular person.