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Just a couple months ago, some were declaring the old oil order dead after the Organization of the Petroleum Exporting Countries (OPEC) failed to agree on coordinated action at its April meeting in Doha.

That meeting was meant to bring about a production freeze to arrest the downward spiral of prices that began in July 2014. Instead, the Doha meeting was 
over before it began. Iran refused to slow production until it had regained its pre-sanctions position in the market, so Saudi Arabia canceled the freeze and continued to produce at peak levels.

This week, with oil 
trading at six-month highs, OPEC members once again had high hopes to show that the organization remains relevant as they gathered in Vienna. Yet, once again, the meeting ended without agreement, resulting in no change to the current policy of essentially unlimited production.

So does the verdict that OPEC is dead still stand, signaling the end of an era in which it supposedly ruthlessly controlled the price of oil? In fact, that era 
barely existed in the first place. The failed meetings confirm a longstanding truth: the world's most famous cartel has never really been a cartel.Rather than the arbiter of global energy, OPEC is and has always been a dysfunctional, divided and discouraged organization.

My recent research has taken me through the 
history of oil, particularly the relationship between oil revenues, economic development and the geopolitical balance of power in the 1960s and 1970s. Oil's history has been dominated by a struggle for balance, a contest between competing interests, both economic and political, and between the fundamental market forces of supply and demand.

OPEC has never been shielded from or been able to fully thwart these forces.

Early days: divided and powerless

When it was created in 1960, OPEC was meant to offer members a greater say in how their oil was produced and priced, addressing the disproportionate power wielded by private Western corporations. Its larger goal, to bring order to the chaotic world of global energy, has always been elusive.

OPEC was formed from frustration. In the 1950s, the 
world was awash in oil as small nations in the Middle East and Latin America discovered enormous deposits, and Western oil companies sought to tap them to meet rising demand.

To gain access to those deposits, the major oil companies (known as the 
'Seven Sisters') signed concessionary agreements with local governments, allowing them to pump, refine, transport and market a nation's oil in return for a royalty, typically 50 percent of profits.

This arrangement gave 
the companies control over the oil - they set production levels and prices - while governments simply collected a check and had little influence on anything else.

In February 1959, amid an oil glut, the Seven Sisters 
decided that a price correction was necessary. And so they unilaterally began cutting the posted price, from $2.08 to $1.80 by August 1960. (Back then, oil prices didn't always follow market forces and were typically set by producers.)

The cuts meant a significant loss of revenue for the oil-producing states. In protest, the oil ministers of Iraq, Iran, Venezuela, Saudi Arabia and Kuwait 
met in Baghdad that September and formed OPEC to achieve a more equitable arrangement with the Sisters.

In reality, the oil-producing states could do little to coerce the companies into offering better terms. The Seven Sisters dominated global markets and were capable of shutting out individual producers. Oil was abundant, and nationalization seemed out of the question because the companies could successfully exclude an offending country from the market, as 
they did with Iran in 1951.

In addition, the United States itself was the world's top producer and immune from supply shocks thanks to 
import quotas.. If OPEC threatened to take production offline in order to put pressure on the companies, the U.S. could increase its own to make up the difference, as it did during a partial Arab oil boycott in 1967.

In the end, OPEC did not possess enough market share to make a meaningful impact.

A new balance of power

Besides being relatively impotent, OPEC couldn't agree on a consistent policy among its members. Saudi Arabia wanted to keep production levels low and prices consistent, preserving the global economy and the political status quo. Iran and Iraq, with huge military and development budgets, wanted prices pushed as high as possible in order to maximize revenue.

According to scholar and oil consultant 
Ian Skeet, an attempt to extract more favorable terms from the Sisters in 1963 was sabotaged by the shah of Iran, who sought a separate agreement.

During the 1960s, OPEC met, debated and released grandiose statements on their rights, yet failed to form a united front.

Nevertheless, significant changes were occurring at the time. 
Demand for oil shot up, while production in the U.S. stagnated. The ability of the Seven Sisters to control the market was undermined by international competitors drilling new fields in North Africa, where Libya's Muammar Qaddafi threatened to shut off supply if he didn't get higher prices.

The companies were under 
more and more pressure to deliver satisfactory terms to the OPEC members. The price of oil, which had held steady at $1.80 a barrel for years, began ticking upwards. American import quotas ended, leaving the U.S. more vulnerable to supply shocks as its production capacity steadily declined.

These conditions, while not the result of actions by OPEC, gave the organization an opportunity to influence the market and upset the balance of power.

The oil price revolution

This shift accelerated in the 1970s as 
war broke out between Israel and its Arab neighbors, creating an opportunity for OPEC to wrest control from the Western oil companies.

To punish the U.S. for supporting the Jewish state, Arab oil producers (
not OPEC, as popularly believed) cut production and declared an embargo. Together with the war, this destabilized energy markets as demand outpaced supply.

Amid the fighting, OPEC met with the Seven Sisters in Geneva and demanded an increase in the posted oil price. After rejecting a small change, OPEC announced it would double the price to $5 and later doubled it again to $11.65.

This triggered a massive shift in economic power, what Stanford University professor 
Steven Schneidercalled 'the greatest non-violent transfer of wealth in human history.' With the uptick in oil revenues, OPEC states spent lavishly on economic development, social programs and investments in Western industry and steadily nationalized their domestic industries, pushing out the Seven Sisters.

How did the balance of power seem to shift so suddenly? Among other reasons, the major oil companies could not agree among themselves on a new price and were actually tempted by the high profits that would result. In other words, OPEC had seized control of the oil market largely due to circumstances
beyond its control.

The oil crisis

Despite its victory, OPEC had come no closer to resolving its internal divisions. This became evident when another energy crisis hit.

In January 1979, the shah of Iran fled amid revolution, and 
global oil markets panicked. Prices soared, from $12.70 to over $30 by 1980. Iran's 6 million barrels per day (bpd) disappeared, and other OPEC states eagerly seized the opportunity to sell oil at costly premiums, sending the price even higher.

In the ensuing years, Saudi Arabia tried to impose 
a quota system, with overall production capped at 20 million bpd. Most members ignored their quotas or over-produced to gain greater revenue.

Meanwhile, the West worked to improve energy efficiency and invested heavily in non-OPEC oil sources, including Alaska, Canada and the North Sea. By 1985, OPEC's market share 
had fallen below 30 percent. OPEC dropped its production quota to 19 million bpd, then 17 million, to account for diminishing demand, but only the Saudis obeyed the rules, losing market share as other producers pumped above the quota level.

By 1986, the Saudis had had enough. Without warning, the Saudi oil minister announced that Saudi production would increase. Overnight, Saudi 
production shot up more than 2 million bpd, flooding the market and sending prices plunging below $10 a barrel. Sick of watching other OPEC members cheat them out of profits, the Saudis chose to enforce new discipline through an artificial market shock.

Just as the kingdom did in 2014, this move indicated Saudi willingness to use its massive reserves to 'correct' the market and push out high-cost producers, even at the cost of its OPEC allies.

Feeling the pain

OPEC's fortunes have oscillated since the 1986 shock. Cooperation remained elusive.

A 2011 meeting, dubbed 
'the worst ever' by recently-removed Saudi oil minister Ali al-Naimi, produced disagreements over production levels. Acrimony reigned as OPEC states ignored calls for economic diversification in favor of oil-fueled economic growth.

High prices during the early 2000s accounted for a huge boom in oil revenues for OPEC members. For
Venezuela and Nigeria, oil accounts for over 90 percent of all exports. Most OPEC states believed that high demand would last forever, that high prices could fund government programs and that the good times would never end.

Yet the good times appear to be over. OPEC has failed to control the downward spiral in prices, 
reportedly begun by Saudi Arabia in November 2014 to flood the market with cheap crude to put new and old competitors - U.S. shale producers and Iran - out of business. Saudi Arabia pursued its political interests and existing market share, leaving other OPEC members to fend for themselves.

The 
death of OPEC has been announced in some quarters, with its long-term decline seemingly assured as global energy enters a new era.

It is possible that Saudi Arabia may emerge from this current crisis unscathed, free to embark upon its recently announced Vision 2030 plan for an 'oil-less' economy, 
however dubious that plan might appear. It's possible that OPEC may succeed in concerted action in the future. But its recent failures suggest that political interest will be more likely to divide OPEC and prevent mutual self-interest from uniting its members.

Gregory Brew - PhD Student in History, Energy and Foreign Relations, Georgetown University

OPEC oil crisis oil price Vision 2030
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Leveraging Synergies Created by the Convergence of Operational and Engineering Technologies and Digitalisation, Can Deliver Significant Savings for Energy Companies

Pioneering technology expert tells ADIPEC Energy Dialogue up to 80 per cent of plant shutdowns could be mitigated through combination of advanced electrification, automation and digitalisation technologies

 

Greater use of renewables in power management processes offers oil and gas companies opportunities to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects


Abu Dhabi, UAE – XX August 2020 – Leveraging the synergies created by the convergence of electrification, automation and digitalisation, can create significant cost savings for oil and gas companies when making both operational and capital investment decisions, according to Dr Peter Terwiesch, President of Industrial Automation at ABB, a Swiss-Swedish multinational company, operating mainly in robotics, power, heavy electrical equipment, and automation technology areas.

Participating in the latest ADIPEC Energy Dialogue, Dr Terwiesch said up to 80 per cent of energy industry plant shutdowns, caused by human error, or rotating machinery or power outages, could be mitigated through a combination of electrification, automation and digitalisation.

“Savings are clearly possible not only on the operation side but also, using the same synergies between dimensions, you can bring down the cost schedule and risk of capital investment, especially in a time when making projects work economically is harder,” explained Dr Terwiesch.

A pioneering technology leader, who works closely with utility, industry, transportation and infrastructure customers, Dr Terwiesch said despite the increasing investment by oil and gas companies in renewables and the growing use of renewables to generate electricity, both for individual and industrial uses, hydrocarbons will continue to have an important role in creating energy, in the short to medium term.

“If you look at the energy density constraints, clearly electricity is gaining share but electricity is not the source of energy; it is a conduit of energy. The energy has to come from somewhere and that can be hydrocarbons, or nuclear, or renewables.” he said.

Nevertheless, he added, the greater use of renewables to generate electricity offers oil and gas companies the option of integrating a higher share of renewables into power management processes to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects.

The ADIPEC Energy Dialogue is a series of online thought leadership events created by dmg events, organisers of the annual Abu Dhabi International Exhibition and Conference. Featuring key stakeholders and decision-makers in the oil and gas industry, the dialogues focus on how the industry is evolving and transforming in response to the rapidly changing energy market.

With this year’s in person ADIPEC exhibition and conference postponed to November 2021, the ADIPEC Energy Dialogue, along with insightful webinars, podcasts and on line panels continue to connect the oil and gas industry, with the challenges and opportunities shaping energy markets in the run up to, and following, a planned three-day live stream virtual ADIPEC conference taking place from November 9-11.

An industry first of its kind, the online conference will bring together energy leaders, ministers and global oil and gas CEOs to assess the collective measures the industry needs to put in place to fast-track recovery, post COVID-19.

To watch the full ADIPEC Energy Dialogue series go to: https://www.youtube.com/watch?v=QZzUd32n3_s&t=6s

August, 12 2020
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

  • The August Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty because mitigation and reopening efforts related to the 2019 novel coronavirus disease (COVID-19) continue to evolve. Reduced economic activity related to the COVID-19 pandemic has caused changes in energy demand and supply patterns in 2020. Uncertainties persist across the U.S. Energy Information Administration’s (EIA) outlook for all energy sources, including liquid fuels, natural gas, electricity, coal, and renewables. The STEO is based on U.S. macroeconomic forecasts by IHS Markit, which assume U.S. gross domestic product declined by 5.2% in the first half of 2020 from the same period a year ago and will rise from the third quarter of 2020 through 2021.
  • Daily Brent crude oil spot prices averaged $43 per barrel (b) in July, up $3/b from the average in June and up $25/b from the multiyear low monthly average price in April. EIA expects monthly Brent spot prices will average $43/b during the second half of 2020 and rise to an average of $50/b in 2021.
  • U.S. regular gasoline retail prices averaged $2.18 per gallon (gal) in July, an increase of 10 cents/gal from the average in June but 56 cents/gal lower than at the same time last year. EIA expects that gasoline prices will gradually decrease through the rest of the summer to reach an average of $2.04/gal in September before falling to an average of $1.99/gal in the fourth quarter. Forecast U.S. regular gasoline retail prices will average $2.23/gal in 2021, compared with an average of $2.12/gal in 2020.
  • EIA expects high inventory levels and surplus crude oil production capacity will limit upward price pressures in the coming months, but as inventories decline into 2021, those upward price pressures will increase. EIA estimates global liquid fuels inventories rose at a rate of 6.4 million barrels per day (b/d) in the first half of 2020 and expects they will decline at a rate of 4.2 million b/d in the second half of 2020 and then decline by 0.8 million b/d in 2021.
  • EIA estimates that demand for global petroleum and liquid fuels averaged 93.4 million b/d in July. Demand was down 9.1 million b/d from July 2019, but it was up from an average of 85.0 million b/d during the second quarter of 2020, which was down 15.8 million b/d from year-ago levels. EIA forecasts that consumption of petroleum and liquid fuels globally will average 93.1 million b/d for all of 2020, down 8.1 million b/d from 2019, before increasing by 7.0 million b/d in 2021. Reduced economic activity related to the COVID-19 pandemic has caused changes in energy supply and demand patterns in 2020.
  • EIA estimates that global liquid fuels production averaged 91.8 million b/d in the second quarter of 2020, down 8.6 million b/d year over year. The decline reflects voluntary production cuts by the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+), and reductions in drilling activity and production curtailments in the United States because of low oil prices. In the forecast, the global supply of oil continues to decline to 90.4 million b/d in the third quarter of 2020 before rising to an annual average of 99.4 million b/d in 2021.
  • EIA estimates that U.S. liquid fuels consumption averaged 16.2 million b/d in the second quarter of 2020, down 4.1 million b/d (20%) from the same period in 2019. The decline reflects travel restrictions and reduced economic activity related to COVID-19 mitigation efforts. EIA expects U.S. oil consumption will generally rise through the end of 2021. EIA forecasts U.S. liquid fuels consumption will average 18.9 million b/d in the third quarter of 2020 (down 1.8 million b/d year over year) before rising to an average of 20.0 million b/d in 2021. Although the 2021 forecast level is 1.6 million b/d more than EIA’s forecast 2020 consumption, it is 0.4 million b/d less than the 2019 average.
  • EIA has lowered U.S. crude oil production estimates for 2020 by 370,000 b/d from the previous STEO. EIA expects crude production to average 11.3 million b/d in 2020 and 11.1 million b/d in 2021, down from 12.2 million b/d in 2019. Recently released EIA data show that average monthly U.S. oil production for May was 1.2 million b/d lower than the July STEO forecast, indicating more extensive production curtailments than previously estimated. Also, EIA’s August STEO assumes that the Dakota Access Pipeline will remain operational. A U.S. District Court ordered on July 6 the temporary closure of the Dakota Access Pipeline beginning in early August. A U.S. appeals court has overturned the lower court decision, allowing the pipeline to remain running while further litigation proceedings continue.
  • In July, the Henry Hub natural gas spot price averaged $1.77 per million British thermal units (MMBtu). EIA expects natural gas prices will generally rise through the end of 2021 but the sharpest increases will be during this fall and winter when they rise from an average of $2.11/MMBtu in September to $3.14/MMBtu in February. EIA expects that rising demand heading into winter, combined with reduced production, will cause upward price pressures. EIA forecasts that Henry Hub natural gas spot prices will average $2.03/MMBtu in 2020 and $3.14/MMBtu in 2021.
  • EIA estimates that total U.S. working natural gas in storage ended July at about 3.3 trillion cubic feet (Tcf), 15% more than the five-year (2015–19) average. In the forecast, inventories rise by 2.0 Tcf during the April-through-October injection season to reach nearly 4.0 Tcf on October 31.
  • EIA expects that total U.S. consumption of natural gas will average 82.4 billion cubic feet per day (Bcf/d) in 2020, down 3.0% from 2019. The largest decline in consumption occurs in the industrial sector, which EIA forecasts will average 22.0 Bcf/d in 2020, down 1.0 Bcf/d from 2019, as a result of reduced manufacturing activity. The decline in total U.S. consumption also reflects lower heating demand in early 2020, contributing to residential and commercial demand in 2020 averaging 12.8 Bcf/d (down 0.9 Bcf/d from 2019) and 8.8 Bcf/d (down 0.8 Bcf/d from 2019), respectively.
  • U.S. dry natural gas production set an annual record in 2019, averaging 92.2 Bcf/d. EIA forecasts dry natural gas production will average 88.7 Bcf/d in 2020, with monthly production falling from its monthly average peak of 96.2 Bcf/d in November 2019 to 82.7 Bcf/d by April 2021, before increasing slightly. Natural gas production declines the most in the Permian region, where EIA expects low crude oil prices will reduce associated natural gas output from oil-directed rigs. EIA’s forecast of dry natural gas production in the United States averages 84.0 Bcf/d in 2021. EIA expects production to begin rising in the second quarter of 2021 in response to higher natural gas and crude oil prices.
  • EIA estimates that U.S. liquefied natural gas (LNG) exports will average 5.5 Bcf/d in 2020 and will average 7.3 Bcf/d in 2021. EIA expects that U.S. LNG exports will decline through the end of the summer as a result of reduced global demand for natural gas. U.S. exports of LNG in July 2020 averaged 3.1 Bcf/d, which is about the same as in May 2018, when the available liquefaction capacity was about one-third of the current capacity. Declines in global natural gas demand associated with COVID-19 mitigation efforts, high natural gas storage inventories in Europe and Asia, and an on-going expansion in LNG liquefaction capacity have contributed to natural gas and LNG prices reaching all-time historical lows. Low international prices have affected the economic competitiveness of U.S. LNG exports and have led to numerous cargo cancellations, particularly at the Sabine Pass, Corpus Christi, and Freeport LNG export terminals. EIA expects LNG exports from the United States to remain low in the next few months. Based on numerous trade press reports, EIA estimates about 45 cargoes have been canceled for upcoming August shipments and about 30 cargoes have been canceled for September shipments.
  • EIA forecasts 3.6% less electricity consumption in the United States in 2020 compared with 2019. The largest decline on a percentage basis is in the commercial sector, where EIA expects retail sales of electricity to fall by 7.4% this year. Forecast industrial retail electricity sales fall by 5.8%. EIA forecasts residential sector retail sales will increase by 2.0% in 2020. Milder winter temperatures earlier in the year led to lower consumption for space heating, but that factor is offset by increased summer cooling demand and an assumed increase in electricity use by more people working from home. In 2021, EIA forecasts total U.S. electricity consumption will rise by 0.8%.
  • EIA expects the share of U.S. electric power sector generation from natural gas-fired power plants will increase from 37% in 2019 to 40% this year. In 2021, the forecast natural gas share declines to 35% in response to higher natural gas prices. Coal’s forecast share of electricity generation falls from 24% in 2019 to 18% in 2020 and then increases to 22% in 2021. Electricity generation from renewable energy sources rises from 17% in 2019 to 20% in 2020 and to 22% in 2021. The increase in the share from renewables is the result of expected additions to wind and solar generating capacity. EIA expects a decline in nuclear generation in both 2020 and 2021, reflecting recent and upcoming retirements of nuclear generating capacity.
  • EIA forecasts that renewable energy will be the fastest-growing source of electricity generation in 2020. EIA expects the electric power sector will add 23.2 gigawatts (GW) of new wind capacity and 12.9 GW of utility-scale solar capacity in 2020. However, these future capacity additions are subject to a high degree of uncertainty, and EIA continues to monitor reported planned capacity builds.
  • U.S. coal consumption, which dropped to its lowest point since April, totaled 95 MMst in the second quarter of 2020. EIA expects coal consumption to rise to a seasonal peak of 127 MMst in the third quarter but remain lower than 2019 levels through the end of 2020. EIA estimates that U.S. coal consumption will decrease by 26% in 2020 and increase by 20% in 2021. EIA estimates that total U.S. coal production in 2020 will decrease by 29% from 2019 levels to 502 MMst. In 2021, EIA expects higher demand and rising natural gas prices to a lead to a recovery in coal production of 12%, with a total annual production level of 564 MMst.
  • EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions, after decreasing by 2.8% in 2019, will decrease by 11.5% (588 million metric tons) in 2020. This record decline is the result of less energy consumption related to restrictions on business and travel activity and slowing economic growth related to COVID-19 mitigation efforts. CO2 emissions decline with reduced consumption of all fossil fuels, particularly coal (24.9%) and petroleum (11.6%). In 2021, EIA forecasts that energy-related CO2 emissions will increase by 5.6%, as the economy recovers and stay-at-home orders are lifted. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.
August, 12 2020
Utility-scale battery storage capacity continued its upward trend in 2018

Utility-scale battery storage systems are increasingly being installed in the United States. In 2010, the United States had seven operational battery storage systems, which accounted for 59 megawatts (MW) of power capacity (the maximum amount of power output a battery can provide in any instant) and 21 megawatthours (MWh) of energy capacity (the total amount of energy that can be stored or discharged by a battery). By the end of 2018, the United States had 125 operational battery storage systems, providing a total of 869 MW of installed power capacity and 1,236 MWh of energy capacity.

Battery storage systems store electricity produced by generators or pulled directly from the electrical grid, and they redistribute the power later as needed. These systems have a wide variety of applications, including integrating renewables into the grid, peak shaving, frequency regulation, and providing backup power.

annual utility-scale battery storage capacity additions by region

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

Most utility-scale battery storage capacity is installed in regions covered by independent system operators (ISOs) or regional transmission organizations (RTOs). Historically, most battery systems are in the PJM Interconnection (PJM), which manages the power grid in 13 eastern and Midwestern states as well as the District of Columbia, and in the California Independent System Operator (CAISO). Together, PJM and CAISO accounted for 55% of the total battery storage power capacity built between 2010 and 2018. However, in 2018, more than 58% (130 MW) of new storage power capacity additions, representing 69% (337 MWh) of energy capacity additions, were installed in states outside of those areas.

In 2018, many regions outside of CAISO and PJM began adding greater amounts of battery storage capacity to their power grids, including Alaska and Hawaii, the Electric Reliability Council of Texas (ERCOT), and the Midcontinent Independent System Operator (MISO). Many of the additions were the result of procurement requirements, financial incentives, and long-term planning mechanisms that promote the use of energy storage in the respective states. Alaska and Hawaii, which have isolated power grids, are expanding battery storage capacity to increase grid reliability and reduce dependence on expensive fossil fuel imports.

total installed cost of utility-scale battery systems by year

Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report
Note: The cost range represents cost data elements from the 25th to 75th percentiles for each year of reported cost data.

Average costs per unit of energy capacity decreased 61% between 2015 and 2017, dropping from $2,153 per kilowatthour (kWh) to $834 per kWh. The large decrease in cost makes battery storage more economical, helping accelerate capacity growth. Affordable battery storage also plays an important role in the continued integration of storage with intermittent renewable electricity sources such as wind and solar.

Additional information on these topics is available in the U.S. Energy Information Administration’s (EIA) recently updated Battery Storage in the United States: An Update on Market Trends. This report explores trends in battery storage capacity additions and describes the current state of the market, including information on applications, cost, market and policy drivers, and future project developments.

August, 11 2020