Analysis of Q2 Results for Junior Oil and Gas Companies on the TSX Part Two - Costs and Revenue

Further to the last post, I am going to show a comparison of the average sell price per BOE and the costs per BOE for 57 junior oil and gas companies with production in the Western Canadian Basin that are listed on TSX.

The average oil and gas company have Operating and Transportation Costs per BOE at $12.80, General and Administration Costs per BOE of $5.57 and DD&A Costs per BOE of $27.76. The total costs are $46.14 per BOE of oil or $7.69 per MCF of natural gas. Neither of these costs include royalties, which would probably add around 20% of the sell price per BOE.

Just to be clear, DD&A (depletion, depreciation and amortization) costs give a good representation of how much it costs to add reserves to the company. DD&A costs show the acquisition costs of proved properties and the costs of wells and equipment and are amortized over the life or proved reserves.

Here is a list of companies with their respective Operating and Transportation Costs, G&A costs and DD&A costs vs. their average selling price and the potential profit or loss per BOE.

Company	Op Costs / BOE	G&A/ BOE	DD&A / BOE	Total Costs BOE Oil	Average Sell Price/BOE	Profit/Loss per BOE
Fairwest	$15.55	$2.62	$88.45	$106.62	$37.88	$(68.74)
Action	$30.84	$11.54	$45.70	$88.08	$39.29	$(48.79)
Questerre	$12.18	$17.83	$53.65	$83.66	$40.56	$(43.10)
One	$24.69	$10.76	$32.71	$68.16	$31.27	$(36.89)
Canadian Phoenix	$16.81	$23.63	$45.04	$85.48	$53.27	$(32.21)
Result	$9.74	$7.34	$30.34	$47.42	$19.02	$(28.40)
Insignia	$15.44	$8.97	$31.73	$56.14	$28.18	$(27.96)
Dejour	$17.38	$19.30	$25.10	$61.78	$34.61	$(27.17)
Fortress	$18.07	$8.38	$31.74	$58.19	$37.35	$(20.84)
Monterey	$13.43	$3.46	$29.48	$46.37	$26.42	$(19.95)
Redcliffe	$17.63	$6.79	$24.71	$49.13	$30.04	$(19.09)
Culane	$12.48	$4.31	$33.56	$50.35	$31.81	$(18.54)
Bellamont	$13.31	$4.04	$30.63	$47.98	$29.99	$(17.99)
Great Plains	$23.06	$6.56	$31.42	$61.04	$43.35	$(17.69)
Second Wave	$27.42	$6.15	$25.86	$59.43	$42.30	$(17.13)
Twin Butte	$16.03	$5.15	$27.90	$49.08	$32.07	$(17.01)
Anderson	$9.58	$2.34	$29.65	$41.57	$24.70	$(16.87)
Crocotta	$13.41	$5.98	$32.10	$51.49	$34.82	$(16.67)
Midnight	$9.16	$5.35	$33.82	$48.33	$31.99	$(16.34)
Argosy	$6.90	$12.89	$22.73	$42.52	$26.21	$(16.31)
Petro-Reef	$12.32	$3.57	$27.07	$42.96	$26.85	$(16.11)
Sure	$10.41	$4.82	$23.83	$39.06	$23.54	$(15.52)
Prospex	$10.23	$3.03	$29.34	$42.60	$27.32	$(15.28)
Orleans	$12.39	$3.32	$26.29	$42.00	$27.03	$(14.97)
Canext	$11.80	$5.53	$23.98	$41.31	$26.49	$(14.82)
Triton	$9.94	$4.76	$22.75	$37.45	$23.62	$(13.83)
BlackPearl	$13.94	$4.58	$41.72	$60.24	$47.07	$(13.17)
Diaz	$15.23	$(0.90)	$30.17	$44.50	$31.53	$(12.97)
International Sov	$8.50	$4.14	$22.91	$35.55	$24.28	$(11.27)
Cinch	$3.23	$3.74	$25.19	$32.16	$21.90	$(10.26)
Nuloch	$11.36	$6.79	$26.87	$45.02	$35.50	$(9.52)
Midway	$9.33	$5.55	$23.07	$37.95	$28.67	$(9.28)
Painted Pony	$16.89	$4.61	$28.07	$49.57	$40.48	$(9.09)
Arsenal	$17.72	$5.31	$33.13	$56.16	$47.35	$(8.81)
TRUE	$14.83	$2.90	$30.80	$48.53	$39.85	$(8.68)
Wrangler West	$15.67	$2.72	$22.05	$40.44	$32.16	$(8.28)
Twoco	$7.32	$3.25	$25.07	$35.64	$27.49	$(8.15)
Cequence	$17.39	$13.37	$23.98	$54.74	$47.00	$(7.74)
Open Range	$5.97	$4.22	$25.18	$35.37	$28.03	$(7.34)
Yoho	$8.55	$1.70	$19.69	$29.94	$23.12	$(6.82)
Berens	$8.52	$3.55	$23.22	$35.29	$28.61	$(6.68)
Seaview	$14.35	$3.04	$26.79	$44.18	$39.26	$(4.92)
Vero	$9.99	$2.73	$19.50	$32.22	$27.49	$(4.73)
Delphi	$13.39	$1.97	$24.68	$40.04	$37.49	$(2.55)
Ironhorse	$2.98	$3.81	$14.85	$21.64	$20.85	$(0.79)
West	$11.06	$4.11	$38.95	$54.12	$54.08	$(0.04)
Terra	$7.42	$3.13	$12.72	$23.27	$24.47	$1.20
Rock	$12.40	$2.58	$22.10	$37.08	$38.37	$1.29
Angle	$4.56	$3.15	$15.57	$23.28	$25.60	$2.32
Storm	$7.12	$1.71	$14.43	$23.26	$25.81	$2.55
Zapata	$12.70	$4.21	$20.20	$37.11	$39.88	$2.77
Buffalo	$14.64	$4.81	$14.89	$34.34	$37.27	$2.93
Zargon	$13.08	$4.29	$18.09	$35.46	$40.92	$5.46
Stonefire	$5.86	$1.96	$17.26	$25.08	$31.70	$6.62
Arcan	$11.50	$6.92	$23.11	$41.53	$52.01	$10.48
Freehold	$5.39	$2.86	$23.87	$32.12	$42.99	$10.87
Bonterra	$16.12	$2.43	$10.76	$29.31	$44.44	$15.13
Average	$12.80	$5.57	$27.76	$46.14	$33.61	$(12.42)

Two companies have been omitted that were on the last post due to the fact that there was no way to determine their average sell price. They were Dee Three and Eagle Rock.

Based upon the above figures, only 11 companies (or 19%) actually make money when you take the average sell price and back out the Operating/transportation cost, G&A cost and DD&A costs.

If you add royalties at an average rate of 20% of the sell price, then only 4 companies can make money on each BOE. They are Bonterra at $6.24, Freehold at $2.27, Stonefire at $0.28 and just scraping by is Arcan at $0.08. That's only 7% of the sample companies.

Another approach is to remove the DD&A costs and use the industry standard of $16/boe for find and develop costs and add approximately 20% of the average sell price for royalty costs. If you do this, there are only 6 companies of the 57 that would turn a profit on each boe. They are Bonterra, Stonefire, Black Pearl, Arcan, Freehold and West.

In looking at the prices received and the costs, these junior companies may have problem in the future unless they can cut their costs. There is only so long that you can produce oil and gas at a loss before that catches up to you.

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.

Analysis of Q2 Results for Junior Oil and Gas Companies on the TSX Part One

This might be a little late as Q3 numbers will be out soon, but I finally just got around to analyzing the results for Q2 2009. I have some of the published results from Q2 2009 for Junior listed companies (500 BOED to 10,000 BOED) on the Toronto Stock Exchange. This list comes from the Iradesso Quarterly or IQ report. The I Q Report shows the Junior and Intermediate oil and gas companies with production in the Western Canadian Basin. You can sign up for the report here.

I will have several posts over the next little while that analyze some of the numbers from Q2 2009. In this post I will look at the Costs that Juniors incur for producing natural gas. A little background, the costs that are listed here include Operating, Transportation, General & Administrative and DD&A (Depletion, depreciation and amortization). These costs do not include Royalty expenses. Operating and transportation costs are those that are associated with the direct day to day operations on the well. General and Administrative typically are those that are associated at the office level. DD&A costs are costs associated with acquiring reserves. Together these will give the approximate costs per BOED for oil and condensate or MCF for natural gas.

The average Junior profile is as follows:

Production: 2,632 BOED

Gas Weight: 69%

Gas BOED: 1,739 BOED

Oil BOED: 892 BOED

Operating and Transportation Costs per BOE: $12.80

General and Administration Costs per BOE: $5.57

DD&A Costs per BOE: $27.76

Total Costs (excluding Royalties) per BOE: $46.14

Total Costs (excluding Royalties) per MCF: $7.69

Here are the costs as they relate to the companies with production in the Western Basin:

Company	Op Costs	G&A Costs	DD&A Costs	Total Costs Per BOE	Total Cost per MCF
Fairwest	$15.55	$2.62	$88.45	$106.62	$17.77
Action	$30.84	$11.54	$45.70	$88.08	$14.68
Canadian Phoenix	$16.81	$23.63	$45.04	$85.48	$14.25
Questerre	$12.18	$17.83	$53.65	$83.66	$13.94
One	$24.69	$10.76	$32.71	$68.16	$11.36
Dejour	$17.38	$19.30	$25.10	$61.78	$10.30
Eagle Rock	$18.71	$6.08	$36.79	$61.58	$10.26
Great Plains	$23.06	$6.56	$31.42	$61.04	$10.17
BlackPearl	$13.94	$4.58	$41.72	$60.24	$10.04
Second Wave	$27.42	$6.15	$25.86	$59.43	$9.91
Fortress	$18.07	$8.38	$31.74	$58.19	$9.70
Arsenal	$17.72	$5.31	$33.13	$56.16	$9.36
Insignia	$15.44	$8.97	$31.73	$56.14	$9.36
Cequence	$17.39	$13.37	$23.98	$54.74	$9.12
West	$11.06	$4.11	$38.95	$54.12	$9.02
Crocotta	$13.41	$5.98	$32.10	$51.49	$8.58
Culane	$12.48	$4.31	$33.56	$50.35	$8.39
Painted Pony	$16.89	$4.61	$28.07	$49.57	$8.26
Redcliffe	$17.63	$6.79	$24.71	$49.13	$8.19
Twin Butte	$16.03	$5.15	$27.90	$49.08	$8.18
True	$14.83	$2.90	$30.80	$48.53	$8.09
Midnight	$9.16	$5.35	$33.82	$48.33	$8.06
Bellamont	$13.31	$4.04	$30.63	$47.98	$8.00
Result	$9.74	$7.34	$30.34	$47.42	$7.90
Monterey	$13.43	$3.46	$29.48	$46.37	$7.73
Nuloch	$11.36	$6.79	$26.87	$45.02	$7.50
Diaz	$15.23	$(0.90)	$30.17	$44.50	$7.42
Seaview	$14.35	$3.04	$26.79	$44.18	$7.36
Petro-Reef	$12.32	$3.57	$27.07	$42.96	$7.16
Prospex	$10.23	$3.03	$29.34	$42.60	$7.10
Argosy	$6.90	$12.89	$22.73	$42.52	$7.09
Orleans	$12.39	$3.32	$26.29	$42.00	$7.00
Anderson	$9.58	$2.34	$29.65	$41.57	$6.93
Arcan	$11.50	$6.92	$23.11	$41.53	$6.92
Canext	$11.80	$5.53	$23.98	$41.31	$6.89
Wrangler West	$15.67	$2.72	$22.05	$40.44	$6.74
Delphi	$13.39	$1.97	$24.68	$40.04	$6.67
Sure	$10.41	$4.82	$23.83	$39.06	$6.51
Midway	$9.33	$5.55	$23.07	$37.95	$6.33
Triton	$9.94	$4.76	$22.75	$37.45	$6.24
Dee Three	$9.45	$5.10	$22.73	$37.28	$6.21
Zapata	$12.70	$4.21	$20.20	$37.11	$6.19
Rock	$12.40	$2.58	$22.10	$37.08	$6.18
Twoco	$7.32	$3.25	$25.07	$35.64	$5.94
International Sov	$8.50	$4.14	$22.91	$35.55	$5.93
Zargon	$13.08	$4.29	$18.09	$35.46	$5.91
Open Range	$5.97	$4.22	$25.18	$35.37	$5.90
Berens	$8.52	$3.55	$23.22	$35.29	$5.88
Buffalo	$14.64	$4.81	$14.89	$34.34	$5.72
Vero	$9.99	$2.73	$19.50	$32.22	$5.37
Cinch	$3.23	$3.74	$25.19	$32.16	$5.36
Freehold	$5.39	$2.86	$23.87	$32.12	$5.35
Yoho	$8.55	$1.70	$19.69	$29.94	$4.99
Bonterra	$16.12	$2.43	$10.76	$29.31	$4.89
Stonefire	$5.86	$1.96	$17.26	$25.08	$4.18
Angle	$4.56	$3.15	$15.57	$23.28	$3.88
Terra	$7.42	$3.13	$12.72	$23.27	$3.88
Storm	$7.12	$1.71	$14.43	$23.26	$3.88
Ironhorse	$2.98	$3.81	$14.85	$21.64	$3.61
Average:	$12.80	$5.57	$27.76	$46.14	$7.69

If you focus on natural gas, there is an interesting picture. The current 2010 AECO strip is $5.93 per MCF for revenue. Of the 59 companies listed, only 15 companies will turn a profit on natural gas based on their costs and the AECO projections of $5.93/MCF in revenue.

If you were to add royalties to the expenses at 20% of the revenue (a swag on my part), then only 6 of the companies would be able to turn a profit. These companies are; Bonterra, Stonefire, Angle, Terra, Storm and Ironhorse.

Interesting how only approximately 10% of the publicly listed companies on the TSX can make money on natural gas. Also consider that the 59 companies listed are 69% gas weighted, which is a scary picture.

I have an Excel Spread Sheet version of the information contained in the Iradesso report that you can use for analysis. All you have to do is email me and ask for it. It's a great spread sheet for determining where certain companies line up compared to others and compared to the averages.

I will have more analysis in the near future on Q2 results, such as daily profit or loss per company, reserves replacement costs based on year end reserves numbers and Q2 DD&A numbers, among others.

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.

The Average Cost of a Well - Outpacing Inflation By Over 5 Times

In my first post on this blog, I brought the fact that capital costs associated with new wells has increased 86% from 1997 to 2007. This was on the entire Western Basin as a whole. Now I will look at it on the well level.

The spend per average well according to Canadian Association of Petroleum Producers, starting in 1997, was $1,670,674. Ten years later in 2007, the same costs associated on a per well basis were $3,253,541. These costs include: exploration cost, development costs, operating costs and royalties. On a per well basis, this represents a 95% increase in costs over a 10 year period. By the way, the biggest portion of these costs are services by driller, which also increased at the fastest pace.

The average yearly increase was 17% where inflation is typically 3%. At that rate, new well costs outpaced inflation by 5.78 times.

Another view would be demonstrated to the left. The red line shows what has happened from 1997 until 2007 and the blue line shows a straight inflation rate of 3% per year. In actuality, inflation only increased at 2.2% per year over this period.

If I owned an oil and gas company, I guess what I would be doing right now is wondering why these costs have escalated so much. Also, I believe that I would also be putting my drilling company on notice to ask them why they have increased costs so much and have really given very little back in return. Perhaps a new "Risk and Reward" model might work, where the driller can participate on the upside for a diminished fee.

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.

The British Columbia Carbon Tax - The New Additional Costs for Oil and Gas Companies

There is a new major expense that is impacting operating costs for oil and gas companies operating in British Columbia. It is the BC Carbon Tax that applies to the purchase and use of fossil fuels in the province of British Columbia. The tax rate starts at $15/tonne in 2009 and increases energy year by $5/tonne until 2012 when the rate will be $30/tonne.

As of July 1 2009, British Columbia's carbon tax rate on 1 Gigajoule of natural gas is $0.7449 or $0.709 per mcf. In 2010 the tax will be $0.945/mcf, in 2011 it will be $1.18/mcf and it will finally top out at $1.41/mcf in 2012.

Considering that the 2010 strip forward on natural gas is $6.05/mcf Canadian (as of October 3rd, 2009), this would mean that the tax on any gas consumed would be equal to almost 12% of the price. On the current AECO spot price of $2.66/mcf Canadian on October 3rd, 2009, this would represent a tax rate of almost 27%.

Another view on this is that the tax for 2009 is also equal to a 9% additional cost on the average operating costs of $7.63/mcf (based on National Energy Board figures for 2008). If the operating costs were to remain flat at $7.63 until 2012, then the new carbon tax would represent 12.4% additional costs in 2010, 15.5% in 2011 and 18.6% in 2012.

As it relates to oil and gas companies, in their operations, one the of largest consumers of natural gas will be their compressors for pipelines. The average size of a compressor on a pipeline is BC is 970 HP and based on initial calculations, the carbon tax would be approximately $57,000 this year, going to $142,000 in 2012.

Most oil and gas companies currently look at paying the tax as their only option, but there is another option that is available to offset the new tax. It involves harnessing waste heat from compressors and utilizing it to create electricity that can be used to offset the new costs of the carbon tax.

This would be accomplished by harnessing the waste heat to drive a turbine/generator to create electricity that could drive a supplemental electric compressor or this electricity can be sold back into the grid to create a revenue stream that can offset a portion or all of the carbon tax costs.

There is a double positive effect in harnessing waste heat to create electricity. One, you can generate a revenue stream on the electricity sold and two, you will receive carbon offset credits that have a value on the open market. Currently these credits are going for $15/tonne and this is approximately equal to the amount you would receive from generating 1 MW of green electricity.

If an oil and gas company understands the financial impact of the new carbon tax as it relates to their business, then they can start looking for waste heat in their operations to generate green electricity projects to assist with offsetting part or all of the new costs associated with the BC Carbon tax.

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.