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Last Updated: September 27, 2019
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The stock prices of U.S. oil exploration and production (E&P) companies relative to the broader U.S. equity market index have declined since the start of the year. Lower stock prices could make it more difficult for U.S. E&P companies to raise the capital needed for their investment programs. Despite the implication of lower market capitalization, through the second quarter of 2019, the profitability and cash flow generation for the 42 U.S. oil producers the U.S. Energy Information Administration (EIA) regularly follows have increased since 2017, suggesting less reliance on capital markets to fund capital expenditure. EIA based this analysis primarily on the published financial reports of these 42 companies, so it is not necessarily representative of the sector as a whole because the analysis does not represent the financial situation of private companies that do not publish financial reports.

The combined cash from operations for these 42 companies totaled $19.2 billion in the second quarter of 2019, a year-over-year increase of $0.8 billion. In addition, these companies' combined capital expenditure totaled $18.5 billion, a year-over-year decline of $0.9 billion (Figure 1). Since the beginning of 2017, quarterly capital expenditures ranged between $16 billion and $21 billion. Growth in cash from operations has been larger than the growth in capital expenditures since mid-2017, and the two have been relatively consistent since mid-2018. This trend implies that the companies generally have been able to fund their capital expenditure programs increasingly through cash flow from operating activities and less from outside sources of capital, such as debt or equity. In fact, these companies have used more funds for financing activities such as reducing debt and repurchasing shares than they received from incurring debt and issuing shares since the second quarter of 2017.

Figure 1. Cash flow items for 42 U.S. oil producers

The 42 companies' production and returns on equity have also increased since 2017. Production gains have come largely through productivity increases during this time, although some production growth is the result of companies that merged with or acquired assets from companies outside of this set of 42. By using longer laterals in horizontal drilling, as well as injecting more proppant per foot, U.S. E&P companies have increased average output per well. According to the 42 companies' income statements, however, upstream production costs did not increase at the same rate as total output growth through the second quarter of 2019, allowing the 42 companies to increase production and returns on equity while maintaining capital expenditures lower than $21 billion per quarter. The companies' combined return on equity and year-over-year production growth each reached 11% as of the second quarter of 2019 (Figure 2).

Figure 2. Production and return on equity for 42 U.S. oil producers

Despite the increase in returns, production, and cash flow from operations, the combined market capitalization for these 42 companies was $380 billion as of the end of the second quarter of 2019, a year-over-year decline of 28%. The stock prices for many of them continued to decline in the third quarter of 2019. The broader S&P Oil & Gas Exploration & Production Select Industry Index, which represents stock prices for 63 U.S. oil companies, recently declined to low levels relative to the broader U.S. equity market. When compared with the Russell 3000 Index, a stock index that represents almost all publicly traded equities in the United States, the S&P Oil & Gas E&P Index declined throughout the second quarter of 2019 and reached the lowest level since late 2000 in August (Figure 3).

Figure 3. Stock price index for U.S. oil companies

Market capitalization and stock prices often indicate investors' forward-looking expectations and sentiment. In this case, relatively low stock prices for U.S. E&P companies may reflect investor beliefs that E&P companies' future growth or profitability potential is low. Similarly, a declining ratio with the broader Russell 3000 Index implies investors expect other sectors of the U.S. economy have greater growth potential than the U.S. E&P sector. This expectation suggests that investors may have some concerns about whether the profitability and production growth seen in the financial statements as of the second quarter of 2019 will continue.

Low stock prices indicate expectations of lower profits and growth for U.S. E&P companies. More directly, some E&P companies would not be able to raise as much debt or equity financing with a low stock price than they otherwise would. At the same time, more companies have been able to increase cash from operations and fund investment through retained earnings, effectively reducing the need for outside sources of capital. The ability of these companies to maintain similar returns and production growth rates through cash from operations will continue to depend primarily on crude oil prices, trends in productivity per well, and oilfield services costs.

U.S. average regular gasoline and diesel prices increase

The U.S. average regular gasoline retail price rose 10 cents from the previous week to $2.65 per gallon on September 23, 19 cents lower than the same time last year and the largest single week increase in the U.S. average regular gasoline retail price since September 4, 2017. The Midwest price rose by 13 cents to $2.59 per gallon, the Gulf Coast price rose by 12 cents to $2.35 per gallon, the East Coast price rose nearly 9 cents to $2.54 per gallon, the West Coast price rose over 8 cents to $3.34 per gallon, and the Rocky Mountain price increased by more than 4 cents to $2.70 per gallon.

The U.S. average diesel fuel price rose more than 9 cents to $3.08 per gallon on September 23, 19 cents lower than a year ago and the largest single week increase in the U.S. average diesel fuel price since September 4, 2017. The Midwest price rose by 11 cents to $2.99 per gallon, the Gulf Coast price rose by nearly 10 cents to $2.86 per gallon, the East Coast price rose by nearly 9 cents to $3.08 per gallon, and the West Coast and Rocky Mountain prices each rose by nearly 8 cents to $3.65 per gallon and $3.03 per gallon, respectively.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 1.0 million barrels last week to 99.7 million barrels as of September 20, 2019, 13.1 million barrels (15.2%) higher than the five-year (2014-18) average inventory levels for this same time of year. East Coast and Midwest inventories decreased by 1.2 million barrels and 0.9 million barrels, respectively. Gulf Coast and Rocky Mountain/West Coast inventories increased by 0.9 million barrels and 0.1 million barrels, respectively. Propylene non-fuel-use inventories represented 4.3% of total propane/propylene inventories.

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The United States installed more wind turbine capacity in 2020 than in any other year

U.S. wind turbine electricity generating capacity additions

Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory

In both 2019 and 2020, project developers in the United States installed more wind power capacity than any other generating technology. According to data recently published by the U.S. Energy Information Administration (EIA) in its Preliminary Monthly Electric Generator Inventory, annual wind turbine capacity additions in the United States set a record in 2020, totaling 14.2 gigawatts (GW) and surpassing the previous record of 13.2 GW added in 2012. After this record year for wind turbine capacity additions, total wind turbine capacity in the United States is now 118 GW.

The impending phaseout of the full value of the U.S. production tax credit (PTC) at the end of 2020 primarily drove investments in wind turbine capacity that year, just as previous tax credit reductions led to significant wind capacity additions in 2012 and 2019. In December 2020, Congress extended the PTC for another year.

net electricity generation from wind and other sources in selected states

Source: U.S. Energy Information Administration, Electric Power Monthly

Texas has the most wind turbine capacity among states: 30.2 GW were installed as of December 2020. In 2020, Texas generated more electricity from wind than the next three highest states (Iowa, Oklahoma, and Kansas) combined. However, Texas generates and consumes more total electricity than any other state, and wind remains slightly less than 20% of the state’s electricity generation mix.

In two other states—Iowa and Kansas—wind is the most prevalent source of in-state electricity generation. In both states, wind surpassed coal as the state’s top electricity generation source in 2019.

wind's share of in-state utility-scale electricity generation

Source: U.S. Energy Information Administration, Electric Power Monthly

Nationally, 8.4% of utility-scale electricity generation in 2020 came from wind turbines. Many of the turbines added in late 2020 will contribute to increases in wind-powered electricity generation in 2021. EIA expects wind’s share of electricity generation to increase to 10% in 2021, according to forecasts in EIA’s most recent Short-Term Energy Outlook.

March, 05 2021
Myanmar’s Coup and Repercussions to Its Oil Industry

It was a good run while it lasted. Almost exactly a decade ago, the military junta in Myanmar was dissolved, following civilian elections. The country’s figurehead, Aung San Suu Kyi, was released from house arrest to lead, following in the footsteps of her father. Although her reputation has since been tarnished with the Rohingya crisis, she remains beloved by most of her countrymen, and her installation as Myanmar’s de facto leader lead to a golden economic age. Sanctions were eased, trade links were restored, and investment flowed in, not least in the energy sector. Yet the military still remained a powerful force, lurking in the background. In early February, they bared their fangs. Following an election in November 2020 in which Aung San Suu Kyi’s National League for Democracy (NLD) won an outright majority in both houses of Parliament. A coup d’etat was instigated, with the Tatmadaw – the Burmese military – decrying fraud in the election. Key politicians were arrested, and rule returned to the military.

For many Burmese, this was a return to a dark past that many thought was firmly behind them. Widespread protests erupted, quickly turning violent. The Tatmadaw still has an iron grip, but it has created some bizarre situations – ordinary Burmese citizens calling on Facebook and foreign governments to impose sanctions on their country, while the Myanmar ambassador to the United Nations was fired for making an anti-army speech at the UN General Assembly.

The path forward for Myanmar from this point is unclear. The Tatmadaw has declared a state of emergency lasting up to a year, promising new elections by the end of 2021. There is little doubt that the NLD will win yet another supermajority in the election, IF they are fair and free. But that is a big if. Meanwhile, the coup threatens to return Myanmar to the pariah state that it was pre-2010. And threatens to abort all the grand economic progress made since.

In the decade since military rule was abolished, development in Myanmar has been rapid. In the capital city Yangon, glittering new malls have been developed. The Ministry of Energy in 2009 was housed in a crumbling former high school; today, it occupies a sprawling complex in the new administrative capital of Naypyidaw. While not exactly up to the level of the Department of Energy in Washington DC, it is certainly no longer than ministry that was once reputed to take up to three years to process exploration licences for offshore oil and gas blocks.

And it is that very future that is now at stake. Energy has been a great focus for investment in Myanmar, drawn by the rich offshore deposits in the Andaman Sea and the country’s location as a possible pipeline route between the Middle East and inland China. Estimates suggest that – based on pre-coup trends – Myanmar was likely to attract over US$1.1 billion in upstream investment in 2023, more than four times projected for 2021 and almost 20 times higher than 2011. The funds would not only be directed at maintaining production at the current Yadana, Yetagun, Zawtika and Shwe gas fields – where offshore production is mainly exported to Thailand, but also upcoming megaprojects such as Woodside and Total’s A-6 deepwater natural gas and PTTEP’s Aung Sinka Block M3 developments.

The coup now presents foreign investors in Myanmar’s upstream energy sector with a conundrum and reputational risk. Stay, and risk being seen as abetting an undemocratic government? Or leave, and risk being flushing away years of hard work? The home governments of foreign investors such as Total, Chevron, PTTEP, Woodside, Petronas, ONGC, Nippon Oil, Kogas, POSCO, Sumitomo, Mitsui and others have already condemned the coup. For now these companies are hoping that foreign pressure will resolve the situation in a short enough timeframe to allow business to resume. Australia’s Woodside Petroleum has already called the coup a ‘transitionary issue’ claiming that it will not affect its exploration plans, while other operators such as Total and Petronas have focused on the safety of their employees as they ‘monitor the evolving situation’.

But the longer the coup lasts without a resolution satisfactory to the international community and the longer the protests last (and the more deaths that result from that), the more untenable the position of the foreign upstream players will be. Asian investors, especially the Chinese, mainly through CNPC/PetroChina, and the Thais, through PTTEP - will be relatively insulated, but American and European majors face bigger risks. This could jeopardise key projects such as the Myanmar-to-China crude oil and natural gas pipeline project (a 771km connection to Yunnan), two LNG-to-power projects (Thaketa and Thilawa, meant to deal with the country’s chronic blackouts) and the massive Block A-6 gas development in the Shwe Yee Htun field by Woodside which just kicked off a fourth drilling campaign in December.

It is a big unknown. The Tatmadaw has proven to be impervious to foreign criticism in the past, ignoring even the most stringent sanctions thrown their way. In fact, it was a huge surprise that the army even relinquished power back in 2010. But the situation has changed. The Myanmar population is now more connected and more aware, while the army has profited off the opening of the economy. The economic consequences of returning to its darker days might be enough to trigger a resolution. But that’s not a guarantee. What is certain is that the coup will have a lasting effect on energy investment and plans in Myanmar. How long and how deep is a question that only the Tatmadaw can answer. 

Market Outlook:

  • Crude price trading range: Brent – US$63-65/b, WTI – US$60-63/b
  • The slow-but-sure recovery in Texan energy infrastructure following the big freeze has caused crude oil benchmarks to retreat somewhat, with all eyes now focusing on OPEC+ as it meets to decide its supply quotas for April and beyond
  • Some form of supply easing is expected, given that the market is showing signs of tight supply, but OPEC+ is still split on how aggressive it can be; Saudi Arabia is advocating caution while most others, led by Russia, favour a bolder easing given current prices
  • While OPEC+ supply will be keenly watched as an indicator of future crude trends, supply elsewhere is picking up, with the Baker Hughes survey of active oil and gas rigs in the USA crossing the 400-site level for the first time in over a year, with gains mainly from onshore shale drillers tempted back after being wiped up last year

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March, 03 2021
The Competition For The LNG Crown

The year 2020 was exceptional in many ways, to say the least. All of which, lockdowns and meltdowns, managed to overshadow a changing of the guard in the LNG world. After leapfrogging Indonesia as the world’s largest LNG producer in 2006, Qatar was surpassed by Australia in 2020 when the final figures for 2019 came in. That this happened was no surprise; it was always a foregone conclusion given Australia’s massive LNG projects developed over the last decade. Were it not for the severe delays in completion, Australia would have taken the crown much earlier; in fact, by capacity, Australia already sailed past Qatar in 2018.

But Australia should not rest on its laurels. The last of the LNG mega-projects in Western Australia, Shell’s giant floating Prelude and Inpex’s sprawling Ichthys onshore complex, have been completed. Additional phases will provide incremental new capacity, but no new mega-projects are on the horizon, for now. Meanwhile, after several years of carefully managing its vast capacity, Qatar is now embarking on its own LNG infrastructure investment spree that should see it reclaim its LNG exporter crown in 2030.

Key to this is the vast North Field, the single largest non-associated gas field in the world. Straddling the maritime border between tiny Qatar and its giant neighbour Iran to the north, Qatar Petroleum has taken the final investment decision to develop the North Field East Project (NFE) this month. With a total price tag of US$28.75 billion, development will kick off in 2021 and is expected to start production in late 2025. Completion of the NFE will raise Qatar’s LNG production capacity from a current 77 million tons per annum to 110 mmtpa. This is easily higher than Australia’s current installed capacity of 88 mmtpa, but the difficulty in anticipating future utilisation rates means that Qatar might not retake pole position immediately. But it certainly will by 2030, when the second phase of the project – the North Field South (NFS) – is slated to start production. This would raise Qatar’s installed capacity to 126 mmtpa, cementing its lead further still, with Qatar Petroleum also stating that it is ‘evaluating further LNG capacity expansions’ beyond that ceiling. If it does, then it should be more big leaps, since this tiny country tends to do things in giant steps, rather than small jumps.

Will there be enough buyers for LNG at the time, though? With all the conversation about sustainability and carbon neutrality, does natural gas still have a role to play? Predicting the future is always difficult, but the short answer, based on current trends, it is a simple yes. 

Supermajors such as Shell, BP and Total have set carbon neutral targets for their operations by 2050. Under the Paris Agreement, many countries are also aiming to reduce their carbon emissions significantly as well; even the USA, under the new Biden administration, has rejoined the accord. But carbon neutral does not mean zero carbon. It means that the net carbon emissions of a company or of a country is zero. Emissions from one part of the pie can be offset by other parts of the pie, with the challenge being to excise the most polluting portions to make the overall goal of balancing emissions around the target easier. That, in energy terms, means moving away from dirtier power sources such as coal and oil, towards renewables such as solar and wind, as well as offsets such as carbon capture technology or carbon trading/pricing. Natural gas and LNG sit right in the middle of that spectrum: cleaner than conventional coal and oil, but still ubiquitous enough to be commercially viable.

So even in a carbon neutral world, there is a role for LNG to play. And crucially, demand is expected to continue rising. If ‘peak oil’ is now expected to be somewhere in the 2020s, then ‘peak gas’ is much further, post-2040s. In 2010, only 23 countries had access to LNG import facilities, led by Japan. In 2019, 43 countries now import LNG and that number will continue to rise as increased supply liquidity, cheaper pricing and infrastructural improvements take place. China will overtake Japan as the world’s largest LNG importer soon, while India just installed another 5 mmtpa import terminal in Hazira. More densely populated countries are hopping on the LNG bandwagon soon, the Philippines (108 million people), Vietnam (96 million people), to ensure a growing demand base for the fuel. Qatar’s central position in the world, sitting just between Europe and Asia, is a perfect base to service this growing demand.

There is competition, of course. Russia is increasingly moving to LNG as well, alongside its dominant position in piped natural gas. And there is the USA. By 2025, the USA should have 107 mmtpa of LNG capacity from currently sanctioned projects. That will be enough to make the USA the second-largest LNG exporter in the world, overtaking Australia. With a higher potential ceiling, the USA could also overtake Qatar eventually, since its capacity is driven by private enterprise rather than the controlled, centralised approach by Qatar Petroleum. The appearance of US LNG on the market has been a gamechanger; with lower costs, American LNG is highly competitive, having gone as far as Poland and China in a few short years. But while the average US LNG breakeven cost is estimated at around US$6.50-7.50/mmBtu, Qatar’s is even lower at US$4/mmBtu. Advantage: Qatar.

But there is still room for everyone in this growing LNG market. By 2030, global LNG demand is expected to grow to 580 million tons per annum, from a current 360 mmtpa. More LNG from Qatar is not just an opportunity, it is a necessity. Traditional LNG producers such as Malaysia and Indonesia are seeing waning volumes due to field maturity, but there is plenty of new capacity planned: in the USA, in Canada, in Egypt, in Israel, in Mozambique, and, of course, in Qatar. In that sense, it really doesn’t matter which country holds the crown of the world’s largest exporter, because LNG demand is a rising tide, and a rising tide lifts all 😊

Market Outlook:

  • Crude price trading range: Brent – US$64-66/b, WTI – US$60-63/b
  • Despite the thaw after Texas saw a devastating big freeze, the slow ramp-up in restoring US Gulf Coast oil production and refining has supported crude oil prices, with Brent moving above the US$65/b level and WTI now in the low US$60/b level
  • Some Wall Street analysts, including Goldman Sachs, are predicting that oil prices could climb above US$70/b level based on current fundamentals, as the short-term spike gives ways to accelerating consumption trends
  • However, much will depend on OPEC+’s approach to managing supply in Q2, with a meeting set for early March; Saudi Arabia is once again urging caution, but there are many other members of the club champing at the bit to increase output and capitalise on the rising price environment


March, 01 2021