Henk Krijnen

Consultant decision, uncertainty and risk analysis
Last Updated: August 4, 2017
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However interesting and generally appealing scenario thinking, as discussed in my previous article, may be, it only provides a broad, qualitative picture of the context within which one is considering a significant investment decision. But indeed, a very important picture, even with all its caveats. Yet, we need numbers when it comes to sinking capital. No decision executive will sign off on an investment proposal that only consists of a fascinating narrative. She or he will want to see some underpinning of the potential profitability and capital efficiency. And some what ifs. In other words: we need quantification, we need a cash flow outlook of some sort.

In fact, it is one of the more difficult, and therefore avoided, challenges: to combine qualitative with quantitative thinking. Many restrict themselves to one of the two worlds. Yet I believe one has to try to cross the border. Quantification alone can often not tell the story by itself, but only qualitative narratives have the danger of becoming arm-waving.

But this quantification, if done well, does not come easy. How can we put numbers on the future? One way is to assume that whatever was going on in the past will replicate itself going forward. For some variables that is quite doable. If you are investing in wind or solar energy, the wind speed patterns and annual numbers of sun hours at a particular location can reasonably be inferred from historic records, with some averaging over multiple years. However, for many variables such an approach would not be credible.

Nevertheless, this is exactly what was (and is) common across many sectors. In fact, it is well known that this practice was one of the main causes of the financial crisis in 2008. The notion of ‘risk’ was strongly related to the degree of stock volatility in prior periods. Risk models were used that were only driven by historic behaviour; there was no forward looking element (see NYT, 2009). In essence, the quantitative models made people stop thinking. For the calculation of the minimum coverage for Dutch pension funds (i.e. stretching out multiple decades) the use of the current interest rate is mandatory. Similarly for the oil and gas reserves calculations for the SEC (US Securities and Exchange Commission) it is required to use, for the purpose of asset valuation, the currentoil price for several decades of remaining production. Of course these last two examples have auditing and legal dimensions, but they do illustrate the dilemma when considering future cash flows: we know that the value that some important variable assumes today may not be representative for the future, but we (think we) have nothing else (that is auditable).

For investment decisions and strategy development we will often need both a scenario approach and quantitative analysis. It will depend on the investment project where the emphasis lies, but I would argue that for major capital decisions or strategies both should have equal weight. What we see in practice is that (if done at all) scenario work and quantitative investment evaluations are poorly linked, perhaps because these different approaches are serviced by different departments, they require different styles of working, different areas of expertise.

And of course, to come back to the earlier point, the quantification developed should use historic data as a basis, but needs also to include a forward looking, judgemental dimension. Scenario narratives and (probabilistic and judgementally forward looking) quantification should go hand in hand, in some way, for maximum understanding and clarity.

For quantitative analysis we require a choice of models and methods, fit for purpose, not too complicated, but yielding consistent results. And we need mathematics, to do things smartly, quickly and consistently. To deal with uncertainty in the numbers, we need probability theory and probability distributions. There is no way we can arrive at exact estimates of all future variables (costs, prices, schedules, sales quantities, tax rates, etc.). But what we can do is to try to estimate a range (under certain scenario assumptions).

One of the most important distributions for this purpose is the lognormal distribution. It is representative of multiplicative processes (as is the normal distribution for additive processes). This means that the product of variables with ranges of uncertainty will tend to be lognormally distributed. Examples are volumes (L*W*H) and revenues (number of units solds * price). The lognormal distribution is also used quite a bit to model share price behaviour. It has an elegant mathematical formulation and allows for modelling upsides and downsides (with a trick). A recent article I came across (Surovtsev, D. and Sungurov, A. “Vaguely Right or Precisely Wrong?”: Making Probabilistic Cost, Time and Performance Estimates for Bluefield Appraisal. SPE 181904. SPE Economics & Management Journal, July 2017.) confirms that most cost, schedule and production variables are best represented by such a distribution.

Rather than (only) relying on integrated systems and black-box like simulation software, for practitioners and analysts it may be useful to get into the guts of the lognormal distribution, understand its mathematical articulation and have some practical formulas to calculate things by hand. It gets a bit nerdy, but do check out a useful article for this purpose in our free knowledge base (in which more articles are to come).

A next blogpost will again be about global scenarios in a qualitative discussion: what can we learn from our predecessors?

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“Lubricants Shelf” to Assess Engine Oil Market

Already, lubricant players have established their footholds here in Bangladesh, with international brands.

However, the situation is being tough as too many brands entered in this market. So, it is clear, the lubricants brands are struggling to sustain their market shares.

For this reason, we recommend an impression of “Lubricants shelf” to evaluate your brand visibility, which can a key indicator of the market shares of the existing brands. 

Every retailer shop has different display shelves and the sellers place different product cans for the end-users. By nature, the sellers have the sole control of those shelves for the preferred product cans.

The idea of “Lubricants shelf” may give the marketer an impression, how to penetrate in this competitive market. 

The well-known lubricants brands automatically seized the product shelves because of the user demand. But for the struggling brands, this idea can be a key identifier of the business strategy to take over other brands.

The key objective of this impression of “Lubricants shelf” is to create an overview of your brand positioning in this competitive market.

A discussion on Lubricants Shelves; from the evaluation perspective, a discussion ground has been created to solely represent this trade, as well as its other stakeholders.

Why “Lubricants shelf” is key to monitor engine oil market?

The lubricants shelves of the overall market have already placed more than 100 brands altogether and the number of brands is increasing day by day.

And the situation is being worsened while so many by name products are taking the different shelves of different clusters. This market has become more overstated in terms of brand names and local products.

You may argue with us; lubricants shelves have no more space to place your new brands. You might get surprised by hearing such a statement. For your information, it’s not a surprising one.

Regularly, lubricants retailers have to welcome the representatives of newly entered brands.

And, business Insiders has depicted this lubricants market as a silent trade with a lot of floating traders.

On an assumption, the annual domestic demand for lubricants oils is around 100 million litres, whereas base oil demand around 140 million litres.

However, the lack of market monitoring and the least reporting makes the lubricants trade unnoticeable to the public.

February, 20 2019
Your Weekly Update: 11 - 15 February 2019

Market Watch

Headline crude prices for the week beginning 11 February 2019 – Brent: US$61/b; WTI: US$52/b

  • Oil prices remains entrenched in their trading ranges, with OPEC’s attempt to control global crude supplies mitigated by increasing concerns over the health of the global economy
  • Warnings, including from The Bank of England, point to a global economic slowdown that could be ‘worse and longer-lasting than first thought’; one of the main variables in this forecast are the trade tensions between the US and China, which show no sign of being solved with President Trump saying he is open to delaying the current deadline of March 1 for trade talks
  • This poorer forecast for global oil demand has offset supply issues flaring up within OPEC, with Libya reporting ongoing fighting at the country’s largest oilfield while the current political crisis in Venezuela could see its crude output drop to 700,000 b/d by 2020
  • The looming new American sanctions on Venezuelan crude has already had concrete results, with US refiner Marathon Petroleum moving to replace Venezuelan crude with similar grades from the Middle East and Latin America
  • While Nicolas Maduro holds on to power, Venezuela’s opposition leader Juan Guaido has promised to scrap requirements that PDVSA keep a controlling stake in domestic oil joint ventures and boost oil production through an open economy when his government-in-power takes over
  • Despite OPEC’s attempts to stabilise crude prices, the US House has advanced the so-called NOPEC bill – which could subject the cartel to antitrust action – to a vote, with a similar bill currently being debated in the US Senate
  • The see-saw pattern in the US active rig count continues; after a net loss of 14 rigs last week, the Baker Hughes rig survey reported a gain of 7 new oil rigs and a loss of 3 gas rigs for a net gain of 4 rigs
  • While demand is a concern, global crude supply remains delicate enough to edge prices up, especially with Saudi Arabia going for deeper-than-expected cuts; this should push Brent up towards US$64/b and WTI towards US$55/b in trading this week


Headlines of the week

Upstream

  • Egypt is looking to introduce a new type of oil and gas contract to attract greater upstream investment into the country, aiming to be ‘less bureaucratic and more efficient’ with faster cost-recovery, ahead of a planned Red Sea bid round encompassing over a dozen concession sites
  • Lukoil has commenced on a new phase at the West Qurna-2 field in Iraq, with 57 production wells planned at the Mishrif and Yamama formation that could boost output by 80,000 boe/d to 480,000 boe/d in 2020
  • Aker BP has hit oil and natural gas flows at well 24/9-14 in the Froskelår Main prospect in the Alvheim area of the Norwergian Continental Shelf
  • Things continue to be rocky for crude producers in Canada’s Alberta province; production limits were increased last week after being previously slashed to curb a growing glut on news that crude storage levels dropped, but now face trouble being transported south as pipelines remain at capacity and crude-by-rail shipments face challenging economics

Midstream & Downstream

  • The Caribbean island of Curacao is now speaking with two new candidates to operate the 335 kb/d Isla refinery after its preferred bidder – said to be Saudi Aramco’s American arm Motiva Enterprises – withdrew from consideration to replace the current operatorship under PDVSA
  • America’s Delta Air Lines is now reportedly looking to sell its oil refinery in Pennsylvania outright, after attempts to sell a partial stake in the 185 kb/d plant failed to attract interest, largely due to its limited geographical position

Natural Gas/LNG

  • Total reports that it has made a new ‘significant’ gas condensate discovery offshore South Africa at the Brulpadda prospect in Block 11B/12B in the Outeniqua Basin, with the Brulpadda-deep well also reporting ‘successful’ flows of natural gas condensate
  • Italy’s Eni and Saudi Arabia’s SABIC have signed a new Joint Development Agreement to collaborate on developing technologies for gas-to-liquids and gas-to-chemicals applications
  • The Rovuma LNG project in Mozambique is charging ahead with development, with Eni looking to contract out subsea operations for the Mamba gas project by mid-March and ExxonMobil choosing its contractor for building the complex’s LNG trains by April
February, 15 2019
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

Global liquid fuels

  • Brent crude oil spot prices averaged $59 per barrel (b) in January, up $2/b from December 2018 but $10/b lower than the average in January of last year. EIA forecasts Brent spot prices will average $61/b in 2019 and $62/b in 2020, compared with an average of $71/b in 2018. EIA expects that West Texas Intermediate (WTI) crude oil prices will average $8/b lower than Brent prices in the first quarter of 2019 before the discount gradually falls to $4/b in the fourth quarter of 2019 and through 2020.
  • EIA estimates that U.S. crude oil production averaged 12.0 million barrels per day (b/d) in January, up 90,000 b/d from December. EIA forecasts U.S. crude oil production to average 12.4 million b/d in 2019 and 13.2 million b/d in 2020, with most of the growth coming from the Permian region of Texas and New Mexico.
  • Global liquid fuels inventories grew by an estimated 0.5 million b/d in 2018, and EIA expects they will grow by 0.4 million b/d in 2019 and by 0.6 million b/d in 2020.
  • U.S. crude oil and petroleum product net imports are estimated to have fallen from an average of 3.8 million b/d in 2017 to an average of 2.4 million b/d in 2018. EIA forecasts that net imports will continue to fall to an average of 0.9 million b/d in 2019 and to an average net export level of 0.3 million b/d in 2020. In the fourth quarter of 2020, EIA forecasts the United States will be a net exporter of crude oil and petroleum products by about 1.1 million b/d.

Natural gas

  • The Henry Hub natural gas spot price averaged $3.13/million British thermal units (MMBtu) in January, down 91 cents/MMBtu from December. Despite a cold snap in late January, average temperatures for the month were milder than normal in much of the country, which contributed to lower prices. EIA expects strong growth in U.S. natural gas production to put downward pressure on prices in 2019. EIA expects Henry Hub natural gas spot prices to average $2.83/MMBtu in 2019, down 32 cents/MMBtu from the 2018 average. NYMEX futures and options contract values for May 2019 delivery traded during the five-day period ending February 7, 2019, suggest a range of $2.15/MMBtu to $3.30/MMBtu encompasses the market expectation for May 2019 Henry Hub natural gas prices at the 95% confidence level.
  • EIA forecasts that dry natural gas production will average 90.2 billion cubic feet per day (Bcf/d) in 2019, up 6.9 Bcf/d from 2018. EIA expects natural gas production will continue to rise in 2020 to an average of 92.1 Bcf/d.

Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants to rise from 35% in 2018 to 36% in 2019 and to 37% in 2020. EIA forecasts that the electricity generation share from coal will average 26% in 2019 and 24% in 2020, down from 28% in 2018. The nuclear share of generation was 19% in 2018 and EIA forecasts that it will stay near that level in 2019 and in 2020. The generation share of hydropower is forecast to average slightly less than 7% of total generation in 2019 and 2020, similar to last year. Wind, solar, and other nonhydropower renewables together provided about 10% of electricity generation in 2018. EIA expects them to provide 11% in 2019 and 13% in 2020.
  • EIA expects average U.S. solar generation will rise from 265,000 megawatthours per day (MWh/d) in 2018 to 301,000 MWh/d in 2019 (an increase of 14%) and to 358,000 MWh/d in 2020 (an increase of 19%). These forecasts of solar generation include large-scale facilities as well as small-scale distributed solar generators, primarily on residential and commercial buildings.
  • In 2019, EIA expects wind’s annual share of generation will exceed hydropower’s share for the first time. EIA forecasts that wind generation will rise from 756 MWh/d in 2018 to 859 MWh/d in 2019 (a share of 8%). Wind generation is further projected to rise to 964 MWh/d (a share of 9%) by 2020.
  • EIA estimates that U.S. coal production declined by 21 million short tons (MMst) (3%) in 2018, totaling 754 MMst. EIA expects further declines in coal production of 4% in 2019 and 6% in 2020 because of falling power sector consumption and declines in coal exports. Coal consumed for electricity generation declined by an estimated 4% (27 MMst) in 2018. EIA expects that lower electricity demand, lower natural gas prices, and further retirements of coal-fired capacity will reduce coal consumed for electricity generation by 8% in 2019 and by a further 6% in 2020. Coal exports, which increased by 20% (19 MMst) in 2018, decline by 13% and 8% in 2019 and 2020, respectively, in the forecast.
  • After rising by 2.8% in 2018, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.3% in 2019 and by 0.5% in 2020. The 2018 increase largely reflects increased weather-related natural gas consumption because of additional heating needs during a colder winter and for additional electric generation to support more cooling during a warmer summer than in 2017. EIA expects emissions to decline in 2019 and 2020 because of forecasted temperatures that will return to near normal. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.

U.S. residential electricity price

  • West Texas Intermediate (WTI) crude oil price
  • World liquid fuels production and consumption balance
  • U.S. natural gas prices
  • U.S. residential electricity price
  • West Texas Intermediate (WTI) crude oil price
February, 13 2019