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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of the sector as a whole because the analysis does not represent the financial situation of private companies that do not publish financial reports.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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Natural gas inventories surpass five-year average for the first time in two years

Working natural gas inventories in the Lower 48 states totaled 3,519 billion cubic feet (Bcf) for the week ending October 11, 2019, according to the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR). This is the first week that Lower 48 states’ working gas inventories have exceeded the previous five-year average since September 22, 2017. Weekly injections in three of the past four weeks each surpassed 100 Bcf, or about 27% more than typical injections for that time of year.

Working natural gas capacity at underground storage facilities helps market participants balance the supply and consumption of natural gas. Inventories in each of the five regions are based on varying commercial, risk management, and reliability goals.

When determining whether natural gas inventories are relatively high or low, EIA uses the average inventories for that same week in each of the previous five years. Relatively low inventories heading into winter months can put upward pressure on natural gas prices. Conversely, relatively high inventories can put downward pressure on natural gas prices.

This week’s inventory level ends a 106-week streak of lower-than-normal natural gas inventories. Natural gas inventories in the Lower 48 states entered the winter of 2017–18 lower than the previous average. Episodes of relatively cold temperatures in the winter of 2017–18—including a bomb cyclone—resulted in record withdrawals from storage, increasing the deficit to the five-year average.

In the subsequent refill season (typically April through October), sustained warmer-than-normal temperatures increased electricity demand for natural gas. Increased demand slowed natural gas storage injection activity through the summer and fall of 2018. By November 30, 2018, the deficit to the five-year average had grown to 725 Bcf. Inventories in that week were 20% lower than the previous five-year average for that time of year. Throughout the 2019 refill season, record levels of U.S. natural gas production led to relatively high injections of natural gas into storage and reduced the deficit to the previous five-year average.

The deficit was also decreased as last year’s low inventory levels are rolled into the previous five-year average. For this week in 2019, the preceding five-year average is about 124 Bcf lower than it was for the same week last year. Consequently, the gap has closed in part based on a lower five-year average.

Lower 48 natural gas inventories, difference to five-year average

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report

The level of working natural gas inventories relative to the previous five-year average tends to be inversely correlated with natural gas prices. Front-month futures prices at the Henry Hub, the main price benchmark for natural gas in the United States, were as low as $1.67 per million British thermal units (MMBtu) in early 2016. At about that same time, natural gas inventories were 874 Bcf more than the previous five-year average.

By the winter of 2018–19, natural gas front-month futures prices reached their highest level in several years. Natural gas inventories fell to 725 Bcf less than the previous five-year average on November 30, 2018. In recent weeks, increasing the Lower 48 states’ natural gas storage levels have contributed to lower natural gas futures prices.

Lower 48 natural gas inventories and Henry Hub futures prices

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and front-month futures prices from New York Mercantile Exchange (NYMEX)

October, 21 2019
Your Weekly Update: 14 - 18 October 2019

Market Watch  

Headline crude prices for the week beginning 14 October 2019 – Brent: US$59/b; WTI: US$53/b

  • Crude oil prices remain stubbornly stuck in their range, despite several key issues that could potentially move the market occurring over the week
  • The sudden thawing of the icy trade relations between the US and China last week – announcing a partial trade deal where new tariffs would be halted – was a positive for the waning health of the global economy; this, however, failed to send prices any higher as previous optimism has always been dashed
  • The trade spat has already caused fears of an economic recession and tumbling global oil demand, with the IEA projecting yet another drop in the demand that has neutralised another possible ‘geopolitical premium’ on prices
  • That geopolitical premium focuses on the fragile situation in the Middle East, with risk spiking up as Iran announced that one of its tankers in the Red Sea – far away from the Persian Gulf - had been struck by missiles; an initial accusation that Saudi Arabia was behind the attack was later withdrawn
  • Meanwhile, news emerged that Nigeria had been quietly handed an increased quota under the OPEC+ supply deal, from 1.685 mmb/d to 1.774 mmb/d, in July, which would help it meet compliance under the deal
  • After more than two months of continuous declines, the US active rig count increased for the first time, but not by much; two oil rigs were added, offset by the loss of a gas rig, but a net gain of 1 to a total of 856
  • We expect prices to remain entrenched as it displays resilience against political and economic factors, with Brent hovering in the US$58-60/b area and WTI at the US$52-54/b range


Headlines of the week

Upstream

  • The US Department of the Interior will be opening up 722,000 acres of federal land along California’s central coast near Fresno, San Benito and Monterey for oil and gas leasing – the first sale in the state since 2013
  • Alongside the lease sale in California, the US will also be opening up some 78 million acres in Gulf of Mexico federal waters for sale in 2020, covering all available unleased areas not subject to Congressional moratorium
  • Santos has confirmed oil flows at the Dorado-3 well in the Bedout Basin offshore Western Australia, with some 11,1000 b/d in place
  • After having exited Norway, ExxonMobil is now reportedly looking into selling its Malaysian offshore upstream assets as part of its divestiture programme, fetching up to US$3 billion for assets including the Tapis Blend operations
  • Equinor has won a new exploration permit – WA-542-P – in the offshore Western Australia Northern Carnarvon Basin, located new the Dorado well
  • Nigeria is looking to settle a US$62 billion income-sharing dispute with international oil firms such as ExxonMobil, Shell, Chevron, Total and Eni operating in the country, with hopes of reaching a settlement
  • Barbados is looking to emulate its nearby neighbour Guyana as it gears up for its third offshore bid round that will launch in early 2020
  • Petroecuador has been forced to declare force majeure on its crude exports, as widespread protests over the removal of fuel subsidies have led to the shutdown of some oilfields
  • Abu Dhabi is looking to create a new benchmark price for Middle Eastern crude based on its Murban grade that could compete with Brent and WTI

Midstream/Downstream

  • Aruba has ended its contract with Citgo – PDVSA’s US refining arm – to operate its 209,000 b/d refinery that is currently idled; a new operator is being sought, paralleling the situation over Curacao’s Isla refinery and PDVSA
  • Poland’s crude pipeline operator expects to only be able to clear its system of contaminated Russian oil from the Druzhba incident by July 2020
  • Gunvor’s Rotterdam refinery will only be able to produce low sulfur fuel oil by March 2020, part of a larger planned overhaul of the 88,000 b/d site

Natural Gas/LNG

  • After Total’s departure, it is now the turn of CNPC to quit the South Pars Phase 11 project in Iran, leaving Iran to go ahead alone its largest natural gas project ever as the threat of US sanctions bites down
  • CNPC has taken over operation of the Chuandongbei sour gas field in China’s Sichuan basin from Chevron, and will kick of Phase 2 development soon
  • Qatar has invited ExxonMobil, Shell, Total, ConocoPhillips and some other ‘big players’ to assist in the North Field expansion that will underpin its ambitions to boost gas output to 110 million tpa from a current 77 million tpa
  • The FID on the Rovuma LNG project in Mozambique has been pushed back by a year, with first production now expected by 2025 at the earliest
  • Pakistan has cancelled a ‘huge’ 10-year tender covering 240 LNG cargoes to its second LNG terminal, turning instead to spot cargoes due to inadequate demand
  • Inpex has formally received a 35-year extension for the PSC covering the Abadi LNG project in Indonesia, extending its operation of the Masela block to 2055
October, 18 2019
Ecuador Exits OPEC

Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.

The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can. 

This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.

The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.

The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis. 

Current OPEC membership:

  • Middle East: Iran, Iraq, Kuwait, Saudi Arabia, UAE
  • Africa: Algeria, Angola, Equatorial Guinea, Gabon, Libya, Nigeria, Republic of Congo
  • Latin America: Venezuela
  • Total: 13
  • Withdrawing: Ecuador (January 2020)
  • Membership under consideration: Sudan (October 2015)
October, 18 2019