You spent how much? - Expenditures per Well in the WCB: 1981 to 2007

Use "Net Cash Expenditures of the Petroleum Industy" for reference

When you look at information on the expenditures per well in the Canadian Western Basin, there is an interesting and alarming trend. Expenditures per well have increase while production per well and reserves per well have dramatically decreased.

The graph is a comparison of net expenditures to bring a well on line (excluding costs for gas plants) from 1981 to 2007. The x axis is marked from 1 to 27 for years; where 1 is 1981 and 27 is 2007). The y axis is the expenditure per 1000 meters cubed (m3) to bring reserves and production on line. All figures can be found on www.capp.ca - Canadian Association of Petroleum Producers.

Cost per 1000 M3 of Additional Reserves:

In 1981 the average spend to add reserves was $4157 per thousand cubic meters of oil and gas reserves.

In 2007, the average spend was $27,753 per thousand cubic meters of oil and gas for reserves.

Expenditures per well per 1000 M3 increased 568% from 1981 to 2007.

These figures are not prorated for inflation.

The average reserves per well has decreased from 1981 to 2007. For a gas well, it has decreased 93%. For an oil well, reserves per well has decreased 81%.

The last 10 year period, from 1997 to 2007, expenditures per well (excluding expenditures on gas plants) have increased 109%, while production has only increased 13%. The largest and fastest growing expenditure is the drilling component on the development side. It grew 147% over the 10 year period for all wells drilled. The average new developmental well drilled during that period grew 131% from an average cost of $356K/well in 1997 to $822K/well in 2007.

Expenditures:

There are three areas that have costs associated with them; exploration, development and operating. On the exploration side, the costs are; geological and geophysical, drilling and land. Developmental include; drilling, Field equipment, enhanced recovery and gas plants. Operating includes; well and flow lines and gas plants. Royalties are just that, royalties. From 1997 to 2007 the total expenditure breakdown is as follows:

Type Costs 10 Year Increase Percent Increase

Exploration: $75.3B $2.5B 47%

Development: $184.3B $12.1B 104%

Operating: $106.3B $7.9B 122%

Royalties: $107.7B $7.8B 172%

Total: $473.6B $30.4B 109%

Expenditures as a total and also on a well basis have significantly outpaced inflation.

Conclusion:

So reserves have decreased per well and expenditures have increased per well (expenditures increased by 568% - from $4,157/1000 M3 in 1981, to $27,753/1000M3 in 2007).

At this pace, expenditures will get to a point where it is no longer viable to explore and develop conventional oil and gas.

These opinions are mine and may not reflect your view. If you would like to contact me, then please feel free to do so at info@argentis-group.com.

Reserves Per Producing Well - Where Did It Go?

The following information shows the correlation of reserves to active wells on a yearly basis. The bottom of the graphs are years, starting in 1956 for gas and 1962 for oil. Oil and Gas are measured in cubic meters. Production figures are for the Western Canada Basin only. All figures are available on www.capp.ca, which is the Canadian Association of Petroleum Producers.

Gas Reserves per Well: 1956 to 2007

In 1956 there were only 430 producing natural gas wells in the Western Basin.

The reserves per well for that year were equal to 1.13 Billion cubic meters. This equated to a reserve life index of approximately 516 year per active well.

The current reserves per active well is 12,703,314 cubic meters. This roughly translates to a reserve life index of 6 years per active well. There were 128,614 active gas wells in 2007.

Since 1956, the reserves per natural gas well have decreased by 99%.

Since 1956, reserves per well have decrease, with the exception of 6 years (1960, 1964, 1966, 1984, 1989 and 2007).

Oil Reserves per Well: 1962 to 2007

In 1962 there were 14,487 producing oil wells in the Western Basin.

In 1962, reserves per well were 72,702 cubic meters.

Oil reserves per well grew to a high of 102,258 cubic meters in 1968 and declined every single year there after until 2007, with the exception of 1998 when it grew by 557 cubic meters per well.

Over the last 10 years, the reserves per oil well has decreased by 16.5%.

Since the highest point in 1968, reserves per oil well have decreased by 93.5%

My View:

You can probably deduce that you get less oil and gas reserves per well. In my opinion, over drilling has lead to smaller reserves per active well which has had a negative impact on the reserves life index. It's getting harder to find oil and gas and once you do, you are getting less reserves associated with your investment.

An Example of the Cost of Reserves:

Companies spend a significant amount of money to add reserves, which is their largest asset. According to the Q1 2009 Iradesso report, the juniors, 500 BOED to 10,000 BOED, have DD&A costs of $26.05 per BOE, which is a cost per BOE to add reserves to their company.

The average Junior has 2,278 BOED in production with a reserves life index of 9.7 years and their decline per year is 11.4%. This means that they have to replace 266 BOED to keep their reserves where they were last year. Since this is the case, the average DD&A cost per BOED is $95,992 and the company will spend approximately $25.5M to top up reserves.

My company has a patent pending process that will allow companies to find reserves at a low cost. Instead of spending $26.05 per BOE in DD&A, my service can add BOE's for less than $1.00 and BOED's for $877 as opposed to tens of thousands of dollars. Using the average Junior as an example, their DD&A costs for reserves top ups is $25.5M, when our service is run, this cost can usually be reduced to $21.2M (saving $4.3M) or for $79,701 per BOED in DD&A costs, which is a 17% reduction. This example used a 2% outage on reserves, but we typically see 9% missed on reserves, so this number can be significantly higher. If you would like to find out more, please feel free to contact me.

These opinions are mine and may not reflect your view. If you would like to contact me, then please feel free to do so at info@argentis-group.com.

Running out of Gas: Production From a Natural Gas Well

I am a big fan of looking at things over a period of time to see what kind of trends are emerging.

When I looked at the average daily production from a natural gas well from 1971 until 2008, you start to see what has been said for years, the Western basin is in decline.

Natural Gas Production per Well - 1971 to 2008 in BOED

What you see from 1997 to 2007 is that gas has declined from almost 62 BOED/well to 25 BOED/well on average. Years are on the bottom of the graph, 1 is representative of 1971 and 37 is representative of 2007. The numbers along the left side represent BOED rate.

At this pace, the average gas well will produce 12.5 BOED by 2017.

I believe that one of the major reasons for this is over drilling. In 1997, there were 48,991 natural gas wells producing 22,663 BOE per year or 62 BOED. As of 2007 there were 128,614 natural gas wells being operated in the western basin (although I am sure that some of these are now being shut in due to economics) with each well producing 9,087 BOE per year, or 25 BOED.

These figures above represent the following from 1997 to 2007:

• A 60% reduction in production per well
• Each gas well on average is producing 37 BOED less
• There at 163% more gas wells in the western basin
• 79,623 more gas wells
• Production has dropped from 22,663 BOE per well per year to 9,087 BOE

The new well drill rate , on average, for gas wells from 1997 to 2007 was 10.1% as compared to 5.1% from 1987 to 1997. So the drilling rate doubled during that 10 year time frame.

BOED Rate per Well from 1971 to 2007:

As can be seen from the rates above, each well is getting less production daily.

I believe that it is getting less economical for an oil and gas company to turn a profit on a gas well. Given that the average well costs $2.4M to drill (according to the NEB) and the average cost on a MCF for gas is $7.63 (according to the NEB), then it would take 5.25 years to recoup your costs on a well given the daily rate of 25 BOED or 150 MCF/d. In 1997, using the same rates, which is extremely high since the typical cost to drill a well has increased 86%, it would only take 2.32 years to pay out a well using $7.63 per MCF. This also assumes an average price of $7.63 per MCF each year, which is probably not the case.

One way to make a well more economical is to increase the production out of the well and hedge production to cover the costs. I do have a technology that I represent that has the ability to increase production in both a gas and oil well and will make it way more economical for a company to produce out of new and existing wells. This will be in a future blog on how to take an unprofitable company and allow it to turn a profit in a short period of time. This process involves adding reserves for 20% or less of what the industry average and combines a couple of different services.

These opinions are mine and may not reflect your view. If you would like to contact me, then please feel free to do so at info@argentis-group.com.