To operate well is to operate responsibly—but more must be done on sustainable design and balanced portfolios to achieve a net-zero future.
Hydrocarbons have powered economic growth for 150 years, but their emissions are destabilizing the earth’s climate. Now that the atmospheric impact of fossil fuels is widely recognized, the sector is under increasing pressure. Policy makers, investors, and society are pressing for change, threatening operators’ license to operate.
Operators have responded with strategic convening and conspicuous investments in innovation and diversification. Yet they have barely begun to address the 4.1 GtCO2e of emissions—almost 10 percent of all anthropogenic greenhouse gas—created every year by their own operations, two-thirds of it from upstream.
Technologies to decarbonize the extraction and production of hydrocarbons already exist and many are economically viable, yet the sector’s atmospheric emissions continue to rise. This paper explores why there has been little change so far, and shows how, with a bold vision and the determination to act, the oil and gas sector can step on a different path, an energy pathway that can contribute to limiting the rise in average global temperatures to 1.5°C.
Why so much greenhouse gas? A trio of emission-intensity drivers
Studying the emission intensity of upstream oil and gas assets reveals that three structural factors drive their “well to pipe” emission intensity.
First, resource complexity structurally sets an asset’s emission intensity
All else being equal, the least emission-intensive assets are large producers with high API gravity and low reservoir complexity. The data show that assets with API gravity of 20° or less can be, on average, three times more emission-intensive than those with API gravity of 50° or more. Assets with the highest structural emission intensity in our data set are complex reservoirs: viscous, in deep or ultra-deep water, compartmentalized, or high pressure and temperature. Pressure maintenance during primary production or secondary and tertiary recovery also increases energy and emission intensity. Simulations of GHG emissions from oil production show average emissions doubling over 25 years. In the IEA’s terminology, these are resources with intrinsically low energy return on energy invested (EROI).
Second, processes and engineering are crucial controllable drivers
Complex facilities are typically more energy-intensive, and therefore more emission-intensive. Hub platforms with more equipment and personnel require more energy for running core and auxiliary systems, while high manning levels intensify their logistics, which again increases emissions. A small single-steel-jacket platform is less emission-intensive than an FPSO with complex subsea export infrastructure connecting many complex wells.
Operations benchmarks—and our emission data—both show that the age of a production facility does not limit operational performance. However, older assets face more complex challenges in reducing emission intensity. Older equipment may be less efficient and economically challenging to replace. Aging production facilities may also suffer from higher fugitive emissions as wear parts degrade. On the other hand, process design choices can help offset the challenges of maturity.
Third, routine flaring and venting, if prevalent, can contribute 40 percent of the carbon intensity of hydrocarbon production in a region
In jurisdictions where venting and flaring are still common, such as Russia, Iran, the United States, Algeria, and Nigeria, oil facilities with high gas-to-oil ratios and few export or recovery options will routinely flare or vent the associated gas, emitting large volumes of CO2, some methane, and other volatile organic compounds (VOCs). More widely, fugitive emissions and intermittent flaring and venting materially increase upstream methane emissions, which account for 34 percent of oil-production emissions and 41 percent of gas-production emissions, assuming 100-year global-warming potential. This waste is a problem, but its mitigation presents an economic opportunity.
So what is to be done? The path to decarbonization of upstream operations
In the short term, the structural drivers of emission intensity seem to limit the freedom upstream leaders have to reduce their atmospheric emissions. For producing assets, these constraints appear to be the hand they have been dealt. However, operators can choose how to play this hand, giving them more ways to reduce emission intensity than at first appear. Our operations benchmarks show that raising operational performance has a large impact on emissions. And 90 percent of known technological solutions to decarbonization are within the grasp of operators at a cost of no more than $50/metric ton of carbon.
We describe three levers to reduce emission intensity across the full spectrum of scope 1 (direct) and scope 2 (indirect) emissions from upstream oil and gas operations (Exhibit 1). The first, indisputable, step is optimizing operations—maximizing stability and uptime reduces intermittent flaring and venting, and requires few major process changes. Second, sustainable design choices are now available for deployment and increasingly present a positive economic benefit. Third, producers must start to balance their portfolios across resources with a spread of emission intensity in anticipation of the risks from future policy scenarios and investor choices.
The first decarbonization lever: Optimizing operations
Operating well equals operating responsibly. Above all, it is an economical first step in reducing intermittent flaring and venting and fugitive emissions, the third biggest source of emissions. Our analysis shows that across a global sample, once you correct for structural factors, assets in the top decile of production efficiency have the lowest emissions in the sector, based on the stability of their operations. The best can achieve less than 7 kg per barrel of oil equivalent, whereas assets in the third quartile emit at least three times as much.
To catch up, lower-performing assets must address three areas. First, resolve repeat failures that cause process trips or shutdowns. The flaring or venting of methane and other VOCs as equipment is depressurized for safe maintenance and restart leads to high emission intensity. Second, ensure operating parameters have not diverged significantly from the design envelope due to changes in fluid rates and properties. For example, pumps not running at their best efficiency point not only use more energy, but are also less reliable, both of which lead to higher emissions. Third, find and fix asset-integrity issues that increase fugitive emissions, such as degradation of flange joints, valve glands, or seals.
All three areas can be addressed within current operating models and are the core components of traditional levers to improve operational performance. We observe, on average, that a 10 percent increase in production efficiency delivers a 4 percent reduction in emission intensity, all else being constant. Maximizing stability and integrity may require upgrades of process, controls, and parts. A less capital-intensive route is to leverage data and advanced analytics to help optimize and stabilize operations. Predictive maintenance and automated condition-monitoring can reduce planned interventions and extend runs, improving stability and reducing emissions. Advanced analytics enables the next level of energy efficiency, isolating operating parameters that minimize power per unit throughput.
The second decarbonization lever: Sustainable design
There are multiple sustainable design options to make processes less emission-intensive. However, their use is not yet routine: traditional investment stage gates weight up-front capital costs over other considerations, such as energy efficiency or cost-to-operate. With total life-cycle value as the target function, operators may be more motivated to explore sustainable design. Doing so using proven technologies can not only reduce operating costs, but also generate new revenue streams.
Monetizing wasted gas. By some estimates, 257 bcm of natural gas—equivalent to nearly half the consumption of Europe—is wasted globally in flares, vents, and leaks. If monetized, this could generate nearly $40 billion of revenue globally. New ventures such as Capterio improve data transparency around flaring and install bespoke technological solutions that monetize the gas. Solutions include reinjecting to enhance recovery or disposal, power generation (for own use or grid export), building export routes to destination markets, or installing small-scale converters to create products such as CNG, LPG, GTL or LNG.
Reducing energy demand. Energy costs (including opportunity costs) are close to 15 percent of total production costs; recent work with upstream operators suggests they can save up to 20 percent in energy usage. This makes a compelling business case, with a total prize of up to $10 billion in cost reduction per year for the upstream industry. Modular unmanned installations around a supporting hub, as Norway is building in the NOAKA area, or better still, linked to a remote operations center, are gaining traction. Simpler, modular, and reusable facilities with low equipment counts and manning levels reduce costs and emissions from energy use and logistics.
Using zero-carbon energy supply. Sustainable sources of energy improve conversion efficiencies or generate revenue. Offshore grid-based electrification was first shown to be viable in 2003, when the Abu Safah development, 50 kilometers offshore in Saudi Arabia, started up with a connection to the main grid. More recently, the newly commissioned Johan Sverdrup is powered from shore even though it is 140 kilometers from Stavanger at a water depth of 110 to 120 meters. For more remote platforms, localized renewables generation offers a sustainable design option. Platforms in both the southern North Sea and Norwegian sectors, for instance, have introduced zero-carbon power sources with conventional backup for stand-alone facilities. To improve the economics of their deployment, operators might supply power to clusters of their own and third-party offshore facilities.
Removal through carbon capture, usage, and storage (CCU/S). CCU/S is an increasingly popular decarbonization option as seen in the Norwegian Continental Shelf with an encouraging example of CCU/S collaboration across the industry in the renewed Northern Lights project. When combined with CO2-enhanced recovery, it improves recovery rates in a closed-loop CO2 system and raises both production and emission performance.
The third decarbonization lever: Balanced portfolios
The demands of policy makers and investors are fast evolving. Credible scenarios show shareholders reducing their exposure to high-emitting resources, freezing out operators holding the highest-intensity assets. There are also credible scenarios in which policy and markets accelerate peak oil demand to 2025, thereby raising the cost of capital and making oil and gas unattractive as investments for growth.globall
Integrated oil company portfolios have tilted toward natural gas over the past few years, attracted by its reputation as a transition fuel. More recently, Equinor has announced the ambition to meet a carbon-intensity target of 8 kgCO2e/boe by 2030. Other producers have set emission-reduction targets at varying levels. Bold visions must recognize that the highest-emitting reservoirs are nearly three times more emission-intensive than the lowest-emitting ones. What follows is a set of choices for upstream leaders to make around their field-development plans, resource funnels, and portfolios.
Field-development plans need to weigh recovery factor against the emission performance of different production and pressure maintenance techniques. Likewise, building portfolios with better emission performance would involve high-grading only the lower-intensity resources or those for which sustainable design can fully offset the emission implications of resource complexity. Critical factors are viscosity, water depth, distance from shore, initial pressure, and depletion. If emission intensity were always a decision criterion, or a $50/metric ton carbon price were imputed in shaping resource funnels, investment committees would favor “advantaged” resources—those with higher API gravity, in shallow to medium water or requiring conventional production techniques. Or they might limit offshore investments closer to shore to enable grid-based electrification. The value equation, fortunately, boosts balanced portfolios: breakeven economics of many reservoirs with high emission intensity are marginal at more than $65.
How to make a strong start: The decarbonization fundamentals
Upstream leaders aspiring to reduce emissions must first overcome the uncertainties in understanding the emission performance of their assets and portfolios: what is really driving emissions, which emission sources to tackle urgently, and by how much. We respond to this baselining challenge by drawing on the McKinsey Upstream Energy & Emissions Index (MUEEI), a proprietary upstream energy and emission index of assets of different types and at different life stages. The index brings both consistency and detail, which enable operators to separate the controllable factors in emission intensity across the oil and gas life cycle from the external ones. The following sidebar explains the methodology, using a global sample of offshore assets, and illustrates how to apply the MUEEI in assessing current emission performance and in setting reduction targets.
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Technology has indeed changed the way we think, act and react. Every activity we perform is directly or indirectly linked to technology one way or another. Like everything else, technology also has its pros and cons, depending on the way it is used. Since the advancement in cyberspace, scammers and hackers have started using advanced means to conduct fraud and cause damage to individuals as well as businesses online.
According to the Federal Trade Commission (FTC), 1.4 million cases of fraud were reported in 2018 and in 25% of the cases, people said they lost money. People reported losing $1.48 billion to fraudulent practices in 2018. This has caused considerable loss to individuals and businesses. Global regulatory authorities have introduced KYC and AML compliances that businesses and individuals are encouraged to follow. However, banks and financial institutions have to follow them under all circumstances.
KYC or Know Your Customer refers to the process where a business attains information about its customers to verify their identities. It is a complex, time-taking process and customers nowadays don’t have the time or resources to deal with the government, consulate, and embassy offices for their KYC procedures. However, due to technological advancement, the identity verification process has been automated through the use of artificial intelligence systems. These systems seamlessly increase the accuracy and effectiveness of the identity verification process while reducing time and human efforts.
The following methods are used to digitally authenticate identities nowadays:
The use of artificial intelligence systems to detect facial structure and features for verification purposes.
The use of artificial intelligence systems to detect the authenticity of various documents to prevent fraud.
The use of artificial intelligence technology to verify addresses from documents to minimize the threat of fraudsters.
The use of multi-step verification to enhance the protection of your accounts by adding another security layer, usually involving your mobile phone.
The use of pre-set handwritten user consent to onboard only legitimate individuals.
Digital Document Verification
Document verification is an important method to conduct KYC or verify the identity of an individual. The process involves the end-user verifying the authenticity of his/her documents. In banks, financial institutions and other formal set-ups, customers are required to verify their personal details through the display of government-issued documents. The artificial intelligence software checks whether the documents are genuine or have been forged. If the documents are real and authentic, the digital documentation verification is completed and vice versa.
There are four steps that are mainly involved in the digital document verification process. First, the user displays his/her identity documents in front of the device camera. Then the document is critically analyzed by artificial intelligence software to check its authenticity. Forged or edited documents are rejected by the software. The artificial intelligence system then extracts relevant information from the document using OCR technology. The information is sent to the back-office of the verification provider and analyzed by human representatives to further validate the authenticity. Then the results are sent to the business or individual asking for the verification. The whole process takes less than five minutes.
The document authentication process can detect both major and minor faults in the documents. It can detect errors and faults in forged documents, counterfeed documents, stolen documents, camouflage or hidden documents, replica documents and even compromised documents. The verification process can be done on a personal computer or a mobile device using a camera. Although only government-issued documents are used for the authentication process, the following are accepted by most verification providers:
Govt ID Cards
Illegal and fraudulent transactions have dangerous consequences for both individuals as well as businesses. Losses due to scams and frauds trickle down at every level and ultimately have negative consequences on the whole system. Therefore it is imperative to conduct proper customer verification and due diligence in order to minimize the risks of fraud. Digital documentation verification plays a key role in the KYC process.
Headline crude prices for the week beginning 23 March 2020 – Brent: US$27/b; WTI: US$23/b
Headlines of the week
Crude oil prices have fallen significantly since the beginning of 2020, largely driven by the economic contraction caused by the 2019 novel coronavirus disease (COVID19) and a sudden increase in crude oil supply following the suspension of agreed production cuts among the Organization of the Petroleum Exporting Countries (OPEC) and partner countries. With falling demand and increasing supply, the front-month price of the U.S. benchmark crude oil West Texas Intermediate (WTI) fell from a year-to-date high closing price of $63.27 per barrel (b) on January 6 to a year-to-date low of $20.37/b on March 18 (Figure 1), the lowest nominal crude oil price since February 2002.
WTI crude oil prices have also fallen significantly along the futures curve, which charts monthly price settlements for WTI crude oil delivery over the next several years. For example, the WTI price for December 2020 delivery declined from $56.90/b on January 2, 2020, to $32.21/b as of March 24. In addition to the sharp price decline, the shape of the futures curve has shifted from backwardation—when near-term futures prices are higher than longer-dated ones—to contango, when near-term futures prices are lower than longer-dated ones. The WTI 1st-13th spread (the difference between the WTI price in the nearest month and the price for WTI 13 months away) settled at -$10.34/b on March 18, the lowest since February 2016, exhibiting high contango. The shift from backwardation to contango reflects the significant increase in petroleum inventories. In its March 2020 Short-Term Energy Outlook (STEO), released on March 11, 2020, the U.S. Energy Information Administration (EIA) forecast that Organization for Economic Cooperation and Development (OECD) commercial petroleum inventories will rise to 2.9 billion barrels in March, an increase of 20 million barrels over the previous month and 68 million barrels over March 2019 (Figure 2). Since the release of the March STEO, changes in various oil market and macroeconomic indicators suggest that inventory builds are likely to be even greater than EIA’s March forecast.
Significant price volatility has accompanied both price declines and price increases. Since 1999, 69% of the time, daily WTI crude oil prices increased or decreased by less than 2% relative to the previous trading day. Daily oil price changes during March 2020 have exceeded 2% 13 times (76% of the month’s traded days) as of March 24. For example, the 10.1% decline on March 6 after the OPEC meeting was larger than 99.8% of the daily percentage price decreases since 1999. The 24.6% decline on March 9 and the 24.4% decline on March 18 were the largest and second largest percent declines, respectively, since at least 1999 (Figure 3).
On March 10, a series of government announcements indicated that emergency fiscal and monetary policy were likely to be forthcoming in various countries, which contributed to a 10.4% increase in the WTI price, the 12th-largest daily increase since 1999. During other highly volatile time periods, such as the 2008 financial crisis, both large price increases and decreases occurred in quick succession. During the 2008 financial crisis, the largest single-day increase—a 17.8% rise on September 22, 2008—was followed the next day by the largest single-day decrease, a 12.0% fall on September 23, 2008.
Market price volatility during the first quarter of 2020 has not been limited to oil markets (Figure 4). The recent volatility in oil markets has also coincided with increased volatility in equity markets because the products refined from crude oil are used in many parts of the economy and because the COVID-19-related economic slowdown affects a broad array of economic activities. This can be measured through implied volatility—an estimate of a security’s expected range of near-term price changes—which can be calculated using price movements of financial options and measured by the VIX index for the Standard and Poor’s (S&P) 500 index and the OVX index for WTI prices. Implied volatility for both the S&P 500 index and WTI are higher than the levels seen during the 2008 financial crisis, which peaked on November 20, 2008, at 80.9 and on December 11, 2008, at 100.4, respectively, compared with 61.7 for the VIX and 170.9 for the OVX as of March 24.
Comparing implied volatility for the S&P 500 index with WTI’s suggests that although recent volatility is not limited to oil markets, oil markets are likely more volatile than equity markets at this point. The oil market’s relative volatility is not, however, in and of itself unusual. Oil markets are almost always more volatile than equity markets because crude oil demand is price inelastic—whereby price changes have relatively little effect on the quantity of crude oil demanded—and because of the relative diversity of the companies constituting the S&P 500 index. But recent oil market volatility is still historically high, even in comparison to the volatility of the larger equity market. As denoted by the red line in the bottom of Figure 4, the difference between the OVX and VIX reached an all-time high of 124.1 on March 23, compared with an average difference of 16.8 between May 2007 (the date the OVX was launched) and March 24, 2020.
Markets currently appear to expect continued and increasing market volatility, and, by extension, increasing uncertainty in the pricing of crude oil. Oil’s current level of implied volatility—a forward-looking measure for the next 30 days—is also high relative to its historical, or realized, volatility. Historical volatility can influence the market’s expectations for future price uncertainty, which contributes to higher implied volatility. Some of this difference is a structural part of the market, and implied volatility typically exceeds historical volatility as sellers of options demand a volatility risk premium to compensate them for the risk of holding a volatile security. But as the yellow line in Figure 4 shows, the current implied volatility of WTI prices is still higher than normal. The difference between implied and historical volatility reached an all-time high of 44.7 on March 20, compared with an average difference of 2.3 between 2007 and March 2020. This trend could suggest that options (prices for which increase with volatility) are relatively expensive and, by extension, that demand for financial instruments to limit oil price exposure are relatively elevated.
Increased price correlation among several asset classes also suggests that similar economic factors are driving prices in a variety of markets. For example, both the correlation between changes in the price of WTI and changes in the S&P 500 and the correlation between WTI and other non-energy commodities (as measured by the S&P Commodity Index (GSCI)) increased significantly in March. Typically, when correlations between WTI and other asset classes increase, it suggests that expectations of future economic growth—rather than issues specific to crude oil markets— tend to be the primary drivers of price formation. In this case, price declines for oil, equities, and non-energy commodities all indicate that concerns over global economic growth are likely the primary force driving price formation (Figure 5).
U.S. average regular gasoline and diesel prices fall
The U.S. average regular gasoline retail price fell nearly 13 cents from the previous week to $2.12 per gallon on March 23, 50 cents lower than a year ago. The Midwest price fell more than 16 cents to $1.87 per gallon, the West Coast price fell nearly 15 cents to $2.88 per gallon, the East Coast and Gulf Coast prices each fell nearly 11 cents to $2.08 per gallon and $1.86 per gallon, respectively, and the Rocky Mountain price declined more than 8 cents to $2.24 per gallon.
The U.S. average diesel fuel price fell more than 7 cents from the previous week to $2.66 per gallon on March 23, 42 cents lower than a year ago. The Midwest price fell more than 9 cents to $2.50 per gallon, the West Coast price fell more than 7 cents to $3.25 per gallon, the East Coast and Gulf Coast prices each fell nearly 7 cents to $2.72 per gallon and $2.44 per gallon, respectively, and the Rocky Mountain price fell more than 6 cents to $2.68 per gallon.
Propane/propylene inventories decline
U.S. propane/propylene stocks decreased by 1.8 million barrels last week to 64.9 million barrels as of March 20, 2020, 15.5 million barrels (31.3%) greater than the five-year (2015-19) average inventory levels for this same time of year. Gulf Coast inventories decreased by 1.3 million barrels, East Coast inventories decreased by 0.3 million barrels, and Rocky Mountain/West Coast inventories decrease by 0.2 million barrels. Midwest inventories increased by 0.1 million barrels. Propylene non-fuel-use inventories represented 8.5% of total propane/propylene inventories.
Residential heating fuel prices decrease
As of March 23, 2020, residential heating oil prices averaged $2.45 per gallon, almost 15 cents per gallon below last week’s price and nearly 77 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged more than $1.11 per gallon, almost 14 cents per gallon below last week’s price and 98 cents per gallon lower than a year ago.
Residential propane prices averaged more than $1.91 per gallon, nearly 2 cents per gallon below last week’s price and almost 49 cents per gallon below last year’s price. Wholesale propane prices averaged more than $0.42 per gallon, more than 7 cents per gallon lower than last week’s price and almost 36 cents per gallon below last year’s price.