The Energy Return of Norwegian Oil and Gas Production

This is a guest post by Leena Grandell, an independent energy analyst from Norway. Her research summarized in this post was carried out in collaboration with Charles Hall from New York State University and Mikael Hook from Uppsala University, and published in the journal Sustainability.

Norway is one of the few petroleum producing countries where data on the production details is abundant and to a large degree public. Even statistical data on energy consumption of the petroleum industry is available on an annual basis – which allows us to take a closer look at the evolution of Energy Return on Energy Invested (EROI) for Norwegian petroleum production. The following text is a short version of our EROI analysis published through Sustainability. Here we assume that the reader is familiar with the EROI concept. More details and theoretical background can be found in the original article, downloadable at

EROI is a tool used in net energy analysis. EROI is a simple way to examine the quality of an energy resource. What really matters to our economies is the net energy flow (not the gross) provided by our energy sector and this can be estimated through the EROI approach. EROI is calculated from the following simple equation, although the devil is in the details:

Energy Outputs

Calculating energy output is easy because of the availability and organization of the data in national database. We calculated the energy output of all petroleum components (oil, gas, condensate, NGL) from all oil and gas fields based on raw data. The data was kindly supplied on a private basis by the Norwegian Petroleum Directorate. Also data on oil and gas field investments was used from the Norwegian Statistics Bureau.

Energy Inputs

In our analysis we have taken into account both direct energy consumption on site as well as indirect energy consumption in form of materials used for the production

On site energy consumption

Normally, energy companies use natural gas as much as possible in the fields since oil is more valuable. We were able to derive energy inputs used on-site (i.e., at the platforms) from two different sources:

  1. The first energy input is fuel consumed for all other aspects of petroleum production except drilling. The data covers only the fuel (gas and diesel) consumed for petroleum production (i.e., energy used to pump products or pressurize fields) but not the energy consumed in drilling. The data is compiled and given to us by the Norwegian Petroleum Directorate, NPD.
  2. Energy used to drill wells. The NPD data base provides the fuel consumption for petroleum production, but not the energy used to drill wells. Thus we need to know the direct fuel consumption for both exploratory and production drilling activities. For this purpose we use investment data in monetary terms published by Statistics Norway. The data is very detailed, including also direct fuel consumption for drilling purposes, in monetary terms. We divided monetary investments for fuels by average fuel prices paid by Norwegian industry to give fuel consumption for drilling in physical units.

Indirect Energy

The calculation of indirect energy is an attempt to estimate the energy consumption of materials, services etc. related to petroleum production by deriving the energy intensity (energy used per dollar or Krone) of an activity for which there is financial data. An estimate (4.01MJ/$) for the energy intensity of the Norwegian economy as a whole was calculated based on the Norwegian GDP and the primary energy consumption of the Norwegian economy.

Estimates for the indirect energy associated with the purchases by the petroleum sector were derived based on comprehensive investment data provided by Statistics Norway. The statistics give detailed information on commodities, services, administrative costs and drilling activities. We excluded the investments needed for fuel (which we had calculated independently). The costs given in current value were inflation-adjusted to 2005 and converted to US dollars (6.445 NOK/US$, average exchange rate for 2005).

The following figure adds all energy components(both direct and indirect also called embodied energy) together.

Figure 1: Energy cost of producing petroleum in Norway.


We found that the energy return on energy Investment (EROI) for Norwegian petroleum production ranged from 44:1 in the early 1990s to a maximum of 59:1 in 1996, to about 40:1 in the latter half of last decade. The curve basically follows, and is dependent upon, the pattern of production over time (peak in oil production was in 2000 and peak in total petroleum production was in 2004). Approximately 74% of the energy cost is due to direct fuel consumption in production (i.e., pressurizing fields, lifting oil and so on), 2% is due to direct fuel consumption for drilling (including both exploratory and production drilling). The remaining 24% of energy cost is energy used indirectly in generating the needed infrastructure and services.

Figure 2. EROI of the Norwegian petroleum production and of oil production only.

EROI values for oil alone varied from 46:1 in 1996 to around 20:1 in recent years. In terms of production, these values only take oil into account (they exclude gas, NGL and condensate). On the consumption side, however, it covers the whole energy consumption of the petroleum industry.


These EROI values for Norwegian oil and gas reflect the very high quality of the North Sea oil fields, their high profitability, their newness and the impact of the high level of technology and human skills used. There are few oil and gas resources today with such a favorable EROI. Like all petroleum-based wealth, Norway’s present high living standard is likely to be a passing phenomenon, unless the country’s wealth is prudently invested, financially and physically.

What are the reasons for the decline in the EROI estimates, especially since 1999? Probably the most important factor is that it appears that depletion is a somewhat more powerful force than technological improvement. A second effect is that of drilling intensity presented in figure 3. Previous studies have shown that exploitation efficiency in the petroleum industry declines when exploitation intensity increases. The integrated effects of depletion and variable drilling effort may also explain much of the variability in both the US and the global data. This data shows both a general secular decline over the entire period analyzed and a flattening or even an increase in EROI during periods of reduced drilling effort and a reduction during times of intense drilling.

Figure 3: EROI and drilling intensity.

When looking closer at the Norwegian data, it seems that changes in EROI are mostly due to field age. However changes in drilling activity could also have a small impact on the calculated EROI values. Linear curves fitted to the data show that, since 2003, years with higher drilling activity lead to a slightly lower value of EROI whereas years with higher drilling activity lead to somewhat lower values of EROI.

The overwhelming share of the energy expenditures in the oil and gas sector is due to production. Drilling activity uses only 2–4% of total direct fuel consumption of the industry. However, 23–54% of investments are caused by drilling activity, which means that a similar share of the indirect energy can be attributed to drilling. This way the share of drilling activity in the total energy cost (both direct and embodied energy) of the sector varies between 7–17%.

Between 1999 and 2001 there was an almost 30% increase in drilling activity and, in the same timeframe, a small decline in EROI. This increased drilling intensity may be the cause of a decline in EROI, and may not result in as much additional net energy delivered to society as would initially seem to be the case. The subsequent decline in drilling activity in 2001 to 2004 may have helped the EROI to increase again. Since 2003, the drilling activity has been oscillating between 700 and 800 km annually whereas EROI declined steadily by 25% from 2003 to 2008. It is most likely that this decline was caused by field depletion and it may continue as the Norwegian oil and gas fields continue to age. A recent announcement by the Norwegian Petroleum Directory to enhance recovery in mature fields could further deteriorate EROI of the Norwegian oil and gas production, since it requires often very energy intensive techniques such as nitrogen or CO2 injection.

I think you overestimate the EROI by underestimating the embodied energy. Energy intensity of the oil industry is about twice the energy intensity of the overall economy. EROI should be lower accordingly.

I think your critic is justified. If I assume an energy intensity that is twice as high ( =8MJ/US$) , I will get an EROI peaking at 48. It then decreases slowly to a value of 30 in 2008. We could take an even higher energy intensity of 14 MJ/US$, which could reflect even better heavy industry. In that case we get a peak value for EROI of 38 and then decreasing to 23.

To be more sophisticated one could also separate the different categories of investments, like commodities or technical services which are very energy intensive or administration, studies etc, that are less energy intensive, and then use different energy intensities for each category.

Hi Leena,

A very good article! You might be one of the first to have such detailed data on the offshore industry.

Do I understand correctly:

Capital Expenditure Input = Capital Expenditure - cost of fuel.

Energy Input = energy content of fuel + Capital Expenditure Input * energy intensity.

Is this correct?

Did you ever reverse this calculation to estimate the energy used per $ expended by the industry? I am curious how your results compare to those Dr. Hall found for the UK? Estimates based on input - output analysis in the US were 14MJ/$(2002) of goods sold by the oil and gas industry, or I found they were 24MJ/$(2002) expended by the industry. If you do such a calculation I would be very interested to see the results.



You understood correctly the way I calculated the energy expenditure.

I made some quick calculations to compare to the UK values provided by Charles and interestingly I got 18MJ/US$ for 2000 data and 8MJ/US$ for 2007 data (when using 2002 for inflation adjustment). I would say the 2000 value is more reliable since in 2007 they were already drilling like mad and the investments went sky high. But it is just a quick estimation, to get a more reliable picture I would need to include several years, which I am right now not able to do.


Leena - Nice work...thanks. A question about the NG for production component. I'm assuming this is NG that comes from the production stream. I try to use production gas whenever possible since it's always the cheapest source. Another reason is that we don't pay royalty or production taxes used in processing. But in EROI calculation do you also add the value of that produced NG to the return? IOW that NG isn't being withdrawn from elsewhere in the system so in one sense it costs society no energy. But it did require a certain amount of energy to bring it to production.

Given that this NG is the largest energy cost in getting the reserves to market how it is accounted for in the analysis seems rather critical. It would seem the energy cost to bring that NG to the surface would be a component of the EROI calculation but not the energy from the produced NG to run the production operations.

I understand the point you are making. In fact in my calculations I did not add the NG consumed in the production to the official production figures published by NPD.
If we do this it should increase the EROI when compared to my analysis since the return is increased whereas the cost stays the same.
A quick check reveals however that this has only a minor impact on the results. The peak in EROI remains 59 and in 2008 I get a 1% increase in EROI. However with increasing depletion this factor becomes more and more important since the energy cost relative to the production increases.

Thanks Leena.

Tak Leena
You show Norwegian EROI declining over 15 years from the peak:

EROI values for oil alone varied from 46:1 in 1996 to around 20:1 in recent years (Figure 14).

Your Table 2 cites US EROI for oil & gas declining from 30:1 about at the peak in 1971 to 20:1 in 1980 after 10 years to 10:1 today - after 40 years.

That appears to show roughly similar declines in EROI from the peak.

Suggest comparing declines in EROI versus time relative to the peak, and to the cumulative depth of wells drilled per ultimate resource.

Leena, as I understand things you are looking at time slices of EROI in Norwegian oil production and not the EROI of individual oil fields themselves. This will introduce distortions to the true picture. Certain variables I feel are likely to contribute to the big picture: 1) the peak in Norwegian oil production in 2001 (?) and subsequent decline will tend to press time slice EROI downwards since the energy being produced is in decline, 2) as time passes you tend to have a larger number of installations operating and this too tends to press EROI downwards - since production is in decline; and 3) large projects coming on line (like Troll) will tend to provide a one off hit in energy consumption.

I'm not saying your approach is bad - in fact it is likely very good - but simply that you need to have a good understanding of the underlying drivers. It is not necessarily lower EROI of the new fields that are coming on but the cumulative sag in EROI of the production stack laden with more infrastructure and starved by decline.

Euan - I also noticed the time slice nature of the analysis. In one way it's more interesting to me than a field by field EROI analysis. There's the obvious time lag between prospect generation, exploratory drilling, production facility construction, development drilling and finally full stream production rate. Offshore that span could be 6 or more years. And then there's the time span of the production decline. As Leena pointed out a significant change in exploration drilling rate will ultimately effect the generalized EROI calculation.

But as we've described before the oil patch metric is $'. And we take into account the time lags by using a discount rate to bring an evaluation to a "net present value". In theory equating numerous projects starting at different times and taking varying development times one can compare the value monetary value of multiple projects. It' s well beyond the mind of a feeble geologist, but I wonder if some clever TODster could generate a similar metrics...some like "net present energy".

Consider a typical Eagle Ford shale well. A great deal of energy is expended initially with a significant energy return in just a couple of years. But once that rapid decline sets in the EROI drops very quickly as not only the volume declines but the energy used to produce the well increases significantly. So a quick recovery to an EROI approaching say X but then deteriorates quickly. But a conventional oil well may take 2 or 3 times as long to reach the same X EROI but might produce for many years with little energy required to produce...such as a strong water drive reservoir. Thus it's later life will represent a much higher EROI THAN X DURING THAT TIME SLICE as the unconventional well which may have a significantly higher EROI during its EARLY TIME SLICE.

OK...I'm sure that idea is a clear as mud. Get to it. And post the results ASAP. LOL

This is a good point Euan.

EROI gets pushed down by increasing expenditures vs flow, and pushed up by decreasing expenditures vs flow.

So EROI can actually spike up by halting new drilling while continuing to flow older wells. All the capital was charged off long ago and only the overhead is being spent, while the older fields just keep pumping.

I think EROI gets really knocked down when more and more small fields must be brought on line to make up for larger fields depleting. As Leena found the greatest energy consumption was in production, it would be interesting to hear if production costs rise as a function of size of field or number of fields? Meaning, does a few large fields cost less energy to produce than many small fields? Or is it that the industry goes after fields with good natural drives early, and fields with poor performance are ignored until the end?

To learn if the fields are getting worse (lower EROI) you need the EUR of the field plus the cost of drilling and operating that field to the end of life.

The Canadian NEB has done such a calculation for gas wells and found the $/MCF cost of new wells is still rising because the EUR is dropping and the wells are getting deeper and more complex to drill. That study was on land in Western Canada. It would be interesting to see such data for off shore.

Jon - "As Leena found the greatest energy consumption was in production, it would be interesting to hear if production costs rise as a function of size of field or number of fields?"

I don't doubt Leena's number but that is the most difficult aspect for me to understand. Granted I don't know anything specific about Norw. production practices. But onshore US energy consumption is a much lower percentage during the production phase. Offshore US somewhat higher but still not of that magnitude. Again, the disconnect may be with "fuel gas" produced by each well. Between lifting and compression of the production of my NG well I may burn 1 bcf over the life of the well that ultimately produces a NET 5 bcf. But the 1 bcf I burned didn't come from society's came from that producing well. So subtracting that fuel gas the well produced a net 4 bcf. And did so with a completely insignificant amount of energy input DURING THE PRODUCTION PHASE... perhaps only 5% of the energy produced net.

So one could say the well had a production phase EROI of 5 (5/1). Or an EROI of 20 (5/0.25 bcf) with 0.2 bcf being 5% of 5 bcf. That 0.25 bcf would be the imbedded energy in the production hardware. IMHO the 20 EROI seems to be the logical answer. The well essentially supplies most of its energy requirement during it production phase. Even in the case of pumping or gas lift oil wells this equipment is commonly run with a portion of the production stream.

I understand why Leena had to do the study industry wide and over an extended time period: this was the format of the data base available. One obvious drawback is the dependence of any forward prediction on the need to predict future drilling activity. If oil/NG prices collapse and drilling grinds to a near halt the future EROI of existing production will increase. Or if there's a drilling boom, as going on in the US today, EROI would decrease. But in either case the actual EROI of any individual well or field hasn't changed.

Hi Rock,

Yes, I need to dig into the paper and see the actual breakdown of energy used. Other studies that looked at drilling only found it was the steel in the casing pipe that was the largest energy input. So this result is very interesting.

I am not sure how the accounting should be done correctly. I think you are basically right that a BTU at the well head should be handled differently as a BTU that comes back as casing pipe.

A BTU at the well head is as close to 1 actual BTU expended as you can get. A BTU powering a factory actually has many more BTU expended to get it there. It needed to be lifted, compressed, seperated, piped long distance, compressed for winter storage, uncompressed, distributed, metered, fed into machinary and burned at a (typically) large loss. A BTU in a factory might have 2 or 3 more "wasted" BTU hiding behind it. If that BTU is casing pipe from China, well, there are likely 8 or 10 lost BTU behind it.

And those lost BTU show up in the cost. The well head NG is "free" and the casing pipe is expensive.

There is an economic input - output technique that "chains" goods as they move from industry to industry. (so you can see how much wool is used by the oil industry - as worker clothing!) I need to dig into the details and see how lost BTU are handled.

You said:
"But onshore US energy consumption is a much lower percentage during the production phase. Offshore US somewhat higher but still not of that magnitude."

I would be interested to know about your experiences: what makes to most part of the energetic cost? I admit in my analysis I used an energy intensity for imbedded energy which is very low - based on the energy intensity of the Norwegian economy in general. This almost certainly underestimates the indirect energy. If you look at individual fields and take the amount of invested steel, cement etc., then use literature values for the energy cost of producing those commodities, you might get a different over all picture.

Leena – The embedded energy of the drilling equipment is the most difficult component to estimate IMHO. Consider a Deep Water semisubmersible rig that costs $800 million to build. Obviously a lot of embedded steel energy. But do you got all the way back to the mining of the original ore? Lots of transport energy along the way as well as construction energy. Of course, you need to amortize that energy input by the total number of wells drilled during its life. A lot of energy used to move the rig from drill site to drill site…especially if a move is half way around the world. The same would hold true for all the drilling components: drilling mud, chemicals, drill pipe, casing, etc. The actual energy used to drill a well is much easier to estimate. I sign fuel invoices weekly. Typically fuel is 5 – 7% of the cost to drill a well.

The embedded cost of some production ops is also easy. The production equipment is a very small volume compared to the drilling components. So small I think they can be ignore especially since most is recycled from well to well. One big component would be the pipeline systems. But just like the drill rig they have to be amortized over multiple wells.

I think the biggest disconnect remains with how NG produced from a well that’s used to fuel the production process is accounted. I’ve described before why the oil patch never has and never will use EROI to make drilling decisions: it’s all about $’s in and $’s out. Obviously that data is easily available. The capex is related to EROI but difficult to quantify. Take an extreme but valid example: there are millions employed in the oil patch. Do you include the energy used to raise and educate each one of us? Without us the wells wouldn't get drilled so we are no less critical to the EROI than the steel casing. But to put it into perspective: I may burn trillion BTU’s with the production process but that’s energy the well is producing. Typically total production costs are a very minor component of the economic analysis. It’s not uncommon for some operators to not use these costs in their analysis. In fact even the fuel used for production isn’t subtracted from the URR of a well because it’s such a small percentage.

I actually like your industry wide analysis better that that for an individual well or field. As I said the oil patch doesn’t function on the basis of EROI. But cumulatively our efforts, especially as resources become more rare and more expensive to recover, might be better characterized by analysis such as yours.

So EROI can actually spike up by halting new drilling while continuing to flow older wells. All the capital was charged off long ago and only the overhead is being spent, while the older fields just keep pumping.

This is Tom Murphy's energy trap, summarized very nicely.

Do you know where I can obtain the Canadian study? Would be interesting to read it.

But now to your question about the impact of the field size.
First of all field specific investment data is not obtainable. So any analysis on field basis can only take the direct energy cost into account - because of data publicity questions. But when looking at direct energy cost, then yes I can confirm your expectations:
- larger fields (with 150 mill scm o.e. or more) show EROI of more than 100 for the first 5-10 years of production, then declining
- smaller fields barely get over 100 in the first couple of years then followed by a more rapid decline

But as I said, this does not take any indirect energy cost into account. Could imagine, that the indirect energy cost is relatively seen higher at smaller fields.

I suggest that the formula set forth in the post is a false or an incomplete formula.

The IPCC has released a report indicating, among other things, that:

Evidence suggests that climate change has changed the magnitude and frequency of some extreme weather and climate events (‘climate extremes’) in some regions already.

(IPCC News Conference). In light of this reality we need to dispense with the fantasy that the use of fossil fuels has no costs other than the cost of extraction.

A more realistic formula is therefore suggested:

EROI = (Energy returned to society / Energy required to get said Energy) - (costs of catastrophies caused by use of said Energy)

One federal case has contemplated the legalities of the damage. There are sure to be others.

.... just sayin' ...

Hi Dredd,

Your point is well taken and is the basic premise of Limits to Growth. Chewing up resources produces pollution that is damaging and requires remediation by more industrial output (or the economy just contracts due to the damage, like New Orleans, Fukushima etc).

But EROI is an essential input to the model as rising costs of natural resource production are enough to bring a growing society into decline all by themselves.

Dredd - You make a valid point. OTOH if you include societal negative costs shouldn't you also add the positive beneficial costs? Those bbls of oil and cu ft of NG also add a great amount of value to society. And often taken for granted by many who will learn otherwise as we go down the PO trail. Your ability to post your counterpoint statement is one benefit of our energy dependent technology. No idea how you realistically quantify such an effort. There's also the issue of who benefits and who loses. A farmer in Nebraska probably has a net gain which might ultimately benefit African nation that imports his grain to feed its population. Or a subsistence Chinese farmer may greatly improve his families circumstances due to increased energy production from burning coal. But a citizen of a low lying Pacific island? Not so much. Nor the parent of an asthmatic child. Much as it has always been in the world: winners and losers. This time on a global scale perhaps but the same dynamics.

Rockman and JonFreise,

The formula belongs to all of us, so we are free to change it to make it more accurate for our use. I am not the smartest person in this vast room.

BTW no offense to Leena, or anyone else who developed the formula for its original purpose.

Every energy, tool, formula, and idea should serve the planet as it serves humanity, nations, groups, and individuals.

I am only participating here because I detect very smart people laboring in an industry begun long ago, one we inherited, and one that needs repair.

We have to do it together.

Sure the formula belongs to all of us and can and should be commented or reshaped by anyone who is interested.
But I think there are some pragmatic issues: my pretty simplistic way of taking only into account direct and indirect energy leaves room for dicussions and alternative views. Not to mention what happens if you want to add social, environmental aspects, that are hardly measureable...

I'm curious how the embedded energy is allocated over the life of a well.It would make sense to depreciate this cost fairly quickly, just as a capital asset is depreciated for tax purposes. That might increase the EROI somewhat for an older well in the stripper phase. On the other hand, Rembrandt indicates that drilling increases as a field ages, which would counteract that effect.

sf - That was my challenge to our smarter TODsters. We can calculate the NPV (Net Present Value) of the revenue generated by a well. Just take the projected cash flow, apply a discount rate of your choice and click the mouse. This allows a heads up comparision between differnt drilling projects and allows a rate of return computation. If someone can come up with a valid NPE (Net Present Energy) metric then you'll have a method to compare solar to wind to drilling to etc.

Considering how irrelevant EROEI is to human behavior in regards to oil and gas drilling, I am surprised that calculating it has any value at all.

Using the researchers' estimates of an ERoEI of 20:1 and 4.01 MJ/$ gives an extraction cost of $77.61 per barrel. If in place of the above, we use a world 2010 ERoEI of 9.75:1 and 7.33MJ/$ (taken from the World Bank and the EIA data-sets) we get extraction costs of $86.82 per barrel.

Given the age of the Norwegian fields and the fact that it appears that Brent will be stuck north of $100/barrel forever, one would be inclined to go with the second estimate of a lower ERoEI of 9.75:1 and the greater BTU/GDP number.

If however, the Norwegian fields have an ERoEI of 20:1 - they own a cash cow that grazes on the floor of the Baltic Sea!

"This analysis technique has worked with a 0.96 correlation coefficient from 1960 to 2009"

Hi shortonoil, I think your moniker should include that price at which you shorted. I would be very impressed if you shorted at $120. Less so if you shorted at $80 :)

Unfortunately the present instability in world markets is keeping us out of most investments; "Discretion (truly) is the better part of valor"! However (if they don't get themselves nationalized) the future of oil company stocks over the next decade looks to be almost beyond belief.