Western Canadian Basin is F'ed

Reducing Costs in an Oil and Gas Company: Depreciations, Depletion and Amortization

noreply@blogger.com (Chris Hamilton) — Mon, 04 Jan 2010 03:25:00 +0000

Oil and gas companies look for ways to cut costs on each Barrel of Oil Equivalent (BOE) produced in order to become more profitable. Even pennies pre BOE add up. If a 100K BOED company can reduce costs per BOE by $.10, this would add up to $3.65M per year.

There are only a few areas that oil and gas companies can reduce their costs. They typically include:

Operating Costs: includes numerous different items such as power, well servicing and others
General and Administrative: office expenses such as wages, benefits and others
Marketing and Transportation: costs associated with moving oil and gas
Interest: money paid on loans
Royalties: money owed to either the government or a freehold land owner for payment on the right to remove product. This can also be revenue depending on how your contracts are written.
Depreciation, Depletion and Amortization (DD&A): The allocation of costs over the useful life of an asset.

Most of these costs have subcategories of costs, but we won't do into a bunch of deal here. In later posts, I will talk about some of the sub categories.

By far, on average, the largest cost that an oil and gas company incurs are the DD&A costs. These costs are quit often associated with expenses that an oil and gas company undertakes while adding reserves, although it can include facilities, pipelines, and other costs.

On TSX listed Junior Oil and Gas Companies with production in the Western Basin, the average cost per BOE is $50.20. The following breaks our the costs by line item (with the exclusion of interest costs) and the percent of the total BOE costs.

Operating expenses: $12.60/BOE or 25%

G&A expenses: $5.23/BOE or 10%

DD&A costs: $27.09/BOE or 54%

Royalties: $5.28 or 11%

As can be seen, DD&A costs are by far the largest single expense that the average oil and gas company has.

So how do you reduce the DD&A costs for an oil and gas company? I somewhat answered this in my post Analysis of Q3 Results for Junior Oil and Gas Companies on the TSX: Part One, but it probably should be repeated.

DD&A costs are typically costs that are associated with adding reserves (and other assets such as pipelines, facilities and such) to an oil and gas company. One of the easiest ways that reducing DD&A costs can be accomplished is by buying existing reserves for less than the companies current DD&A costs/BOE. Since the average DD&A cost is $27.09/BOE and the average Reserve life Index is 10.4 years, then the cost to replace one Barrel of Oil Equivalent per Day (BOED) is $102,833. All you have to do is find a way to purchase pre-existing production for less then that (give it has 10.4 years as a RLI) and you will reduce your DD&A costs. This is marginalizing the acquisition process, but it is for illustrative purposes.

Another way to reduce DD&A costs is to identify reserves that are missing on the reserves report, which Argentis Group can help with with a service we offer. With this service, a company can add reserves for as little as $.05 per BOE as opposed to the industry average of $16 per BOE for Find and Develop (F&D) costs for oil and gas.

Another way of looking at how to reduce the DD&A costs (including F&D costs) would be as follows:

If the average oil and gas company has a daily production of 2690 BOE and has a reserves life index of 10.4 years, then the DD&A costs associated with this company would be $276,622,492. This is derived by 2690 BOED X 10.4 years X 365 Days X $27.09 DD&A costs. By adding 9% reserves that a company does not know about, then your overall DD&A costs for the company have now shrunk on a BOE basis (assume that the cost to add the additional 9% is not included, and this cost is minimal). The new DD&A costs per BOE are $24.85. For the average Oil and Gas company, this would be a reduction of $602,183 per quarter (or $2.4M per year) on DD&A costs, which is amazing.

There is a potential double effect on a DD&A reduction, the company can take the money that was going to be spent on reserves replacement and now use it to pay down interest, which will reduce the costs per BOE.

One other point that is overlooked here, for every BOE a company finds that they didn't know about, this would add net asset value (NAV) to the company. Typical NAV per BOE is $12. So in the example above, the additional NAV would be $11M. Could you imagine a company leaving that much money on the table if there were to sell? Believe it or not, leaving money on the table happens all the time.

Anyway, long story short, if oil and gas companies were to identify missed reserves first (low hanging fruit) instead of drilling for reserves, they might be able to uncover reserves for a significantly lower price. Since the industry average is $16/BOE to find and develop reserves worth $12/BOE in NAV, it would make sense to look at a process that can identify reserves for less than a dollar a BOE (which Argentis Group can provide through a service we offer).

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. ArgentisGroup assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Analysis of Q3 Results for Junior Oil and Gas Companies on the TSX: Part One

noreply@blogger.com (Chris Hamilton) — Sat, 26 Dec 2009 13:23:00 +0000

As Q3 numbers have now been released, I will now analyze of the Q3 results for Junior and Intermediate Oil and Gas companies that are TSX listed and producing predominantly in the Western Canadian Basin.

In this post I will focus on the Junior Oil and Gas companies, which means companies with production between 500 and 10,000 barrels of oil equivalent per day (BOED). Most of this information comes from the Brian Mills Iradesso Quarterly Report. You can find access to this report here. This is an excellent free report that provides comparisons on key metrics of oil and gas companies.

There are 54 companies that fit the Junior classification and they have production between 517 BOED and 9,907 BOED.

Here are the averages:

Productions: 2,690 BOED

% Gas: 66%

Market Cap per BOED: $63,446

Netback: $9.99/BOE

Operating Expense: $12.60/BOE

General and Administrative Expense: $5.23/BOE

Depletion, Depreciation and Amortization Expense: $27.09/BOE

Royalty Expense: $5.02/BOE

Op Ex + G&A + DD&A + Royalty Expenses: $49.95/BOE

Sell Price: $34.66/BOE

The main point to look at here is that the expenses are higher than the sell price (or revenue per BOE) by $15.29/BOE. Not a great place to be in. In my opinion, the junior oil and gas companies have to look at ways to reduce the costs that they can, such as Operating expenses, G&A costs and DD&A costs. I have excluded interest costs in this analysis.

Since the biggest costs are DD&A costs, oil and gas companies should find ways to reduce these costs per BOE. DD&A costs are costs that are associated with adding reserves to an oil and gas company. One of the easiest ways that reducing DD&A costs can be accomplished is by buying existing reserves for less than the companies current DD&A costs/BOE. Since the average DD&A cost is $27.09/BOE and the average Reserve life Index is 10.4 years, then the cost to replace one Barrel of Oil Equivalent per Day (BOED) is $102,833. All you have to do is find a way to purchase pre-existing production for less then that (give it has 10.4 years as a RLI) and you will reduce your DD&A costs. This is marginalizing the acquisition process, but it is for illustrative purposes.

Another way of looking at how to reduce the DD&A costs would be as follows:

So the above example is one way to help reduce the costs per BOE. There are others expense reduction strategies that can be look at to reduce the overall costs per BOE. All you have to do is find some more (email me and I can work with 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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Question 10 - How will your auditors ensure your Cash Generating Unit’s will be authenticated?

noreply@blogger.com (Chris Hamilton) — Sat, 26 Dec 2009 02:59:00 +0000

This is the tenth and final question in the list of ten questions to ask your auditor if you are a Canadian based oil and gas company. The original post can be found here.

How will your auditors ensure your Cash Generating Unit’s will be authenticated?

Believe it or not, there are companies that do not know that they own an oil or gas well(s). This is due to numerous reasons, but suffice to say, without going into detail, it is true.

If you can't authenticate that you own a well, then how would you be able to ensure that your cash generating units are authenticated.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Question 9 - How can your auditors potentially make your IFRS conversion pay for itself and add asset value to your company?

noreply@blogger.com (Chris Hamilton) — Sat, 26 Dec 2009 02:54:00 +0000

This is the ninth question in the list of ten questions to ask your auditor if you are a Canadian based oil and gas company. The original post can be found here.

How can your auditors potentially make your IFRS conversion pay for itself and add asset value to your company?

Most companies look at the transition to IFRS as cost that they have to incur, but there is a potential to increase the value of your oil and gas company, reduce capital expenditures and identify missed revenues that will help pay for the conversation.

For example, Argentis Group has a process that we run in oil and gas companies to identify missed reserves and missed revenue. On average we identify 9% missed on reserves. For the average junior oil and gas company this would be equal to identifying 919,011 barrels of oil equivalent (BOE). This number was derived from using the average barrel of oil equivalent per day (BOED) of Junior oil and gas companies listed on the TSX with production in the Western Canadian Basin, which is 2,690 and multiplying it by the average reserve life index of junior companies of 10.4 year. (2,690 BOED X 10.4 years x 365 days). The average Find and Develop (F&D) cost per BOE in the Western Canadian Basin is $16. So at $16/BOE in F&D costs times 919,011 BOE would be equal to $14,704,176 in find and develop costs.

So by identifying 9% missed reserves, a company has the potential to free up $14.7M in capital that would normally be associated with reserves replacement.

In addition to this, by identifying these missed reserves, a company will now be able to increase net asset value (NAV) by up to $11M. This is calculated by using the same 919,011 BOE and multiplying this by $12/BOE for NAV. $12 is the average NAV per BOE in the Western Canadian Basin.

In addition to increasing NAV and offsetting capital costs associated with reserves replacement, Oil and gas companies should also look for missed royalties or missed working interests. These revenues can also add up to potentially offset IFRS costs.

Argentis Group can help your company in providing a way to pay for your IFRS conversion all while increasing the value at the same time.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Question 8 - Do your auditors authenticate well counts for Annual Information Form’s?

noreply@blogger.com (Chris Hamilton) — Sat, 26 Dec 2009 02:54:00 +0000

This is the eighth question in the list of ten questions to ask your auditor if you are a Canadian based oil and gas company. The original post can be found here.

Do your auditors authenticate well counts for Annual Information Form’s?

A quick definition on the Annual Information Form (AIF):

A source of additional investor information not included in a company’s prospectus or annual financial statements. Required by law and must be given to you free of charge if you request it. From http://www.getsmarteraboutmoney.ca/tools_and_calculators/glossary/definition/Pages/annual-information-form-aif.aspx

Although the Annual Information Form does not have the same impact as a quarterlies and annual financial statements, they are important as this is were a publicly listed oil and gas company show what their reserves are and how many wells they own (among other pieces of information).

We have seen in one instance, where a company had 222 gross wells but only listed 57 in their AIF. In another example, a company that we worked with were out by 16% on their net well count. A couple of mighty big discrepancy. If your auditor can not identify how many wells you own our if they can not assist you with this process, then chances are, as an oil and gas company, you might be incorrectly stating reserves and hence, either overstating or understating your asset value. This has an impact on the depletion, depreciation and amortization (DD&A) costs, which would make them lower.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Question 7 - How do your auditors tie up reserves to cash generating units?

noreply@blogger.com (Chris Hamilton) — Sat, 26 Dec 2009 02:53:00 +0000

This is the seventh question in the list of ten questions to ask your auditor if you are a Canadian based oil and gas company. The original post can be found here.

How do your auditors tie up reserves to cash generating units?

This is important as companies move forward with IFRS. As an oil and gas company, you have to be able to identify where your revenue is coming from at a cash generating unit. Since an oil and gas companies future revenues come from their reserves, if you can not tie reserves to cash generating units, then how do you authenticate revenue?

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company. If you would like to find out how to tie up reserves to a cash generating unit, then please contact us.

Question 6 - How do your auditors authenticate your Asset Retirement Obligation’s and Offset well liabilities?

noreply@blogger.com (Chris Hamilton) — Fri, 25 Dec 2009 14:52:00 +0000

This is the sixth question in the list of ten questions to ask your auditor if you are a Canadian based oil and gas company. The original post can be found here.

The question is:

How do your auditors authenticate your Asset Retirement Obligation’s (ARO) and Offset well liabilities?

Let's say an oil and gas company will set aside $50K per well for your asset retirement obligations. For and average Junior Oil and Gas company with production being 2,690 Barrerl of Oil Equivalent per Day (BOED) and the average well producing 30 BOED, then they would have an asset retirement obligation of $4.5M. This is a significant amount. We have seen on different occasions where companies are carrying ARO's on royalty wells (where you shouldn't be). We have also seen where wells that were divested were still being carried as well as ARO's being applied to multiple events on the same well.

As of Offset well liabilities, this is extremely tough to identify. When a company has a lease agreement with a freehold land owner, there is typically a clause in the agreement that states that if a well is drilled within a section or quarter section basis (depending on oil or gas) on the adjoining section/quarter section, this would trigger a drill, drop or compensate mechanism. The leesee has to either drill a well, compensate for drainage or drop the lease. The legality behind this takes too long to go into, but if you want to find out more, I would suggest going to the Freehold Owners Association at www.fhoa.ca. Since an oil an gas company has to look at each freehold lease that they representing for the freehold land owner, it is a very long task to identify any offset well obligations. As an example, say an oil well is drilled on an adjoining quarter section and triggers a potential compensatory royalty. The average oil well produces 40 barrels of oil per day. Say the royalty rate for the freehold land owner is 5% and the average price is $80/barrel. This would mean that the oil and gas company would potentially have to pay the freehold land owner $160/day or $58,400 per year. This is a liability that is carried on the books that is often left un-actioned.

In both cases, more than likely your auditors are not identifying additional ARO's or offset well liabilities, which have impacts on the overall financials of an oil and gas company.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Question 5 - How Do Your Auditors Validate Your Are Not Overpaying Capital, Operating Expenses or Royalties?

noreply@blogger.com (Chris Hamilton) — Sun, 20 Dec 2009 02:50:00 +0000

This is the fifth question in the list of ten questions to ask your auditor if you are a Canadian based oil and gas company. The original post can be found here.

The questions is:

How do your auditors validate that you are not overpaying:

a. Capital?

b. Operating expenses?

c. Royalties?

On the flip side, you could also ask the same question on underpayment.

This is important since all of these can have a positive or negative impact on your overall expenses. Even though your auditors don't have to do a 100% check against all your capital and operating expenditures and your royalty payments, there is still a chance that any errors could have an impact on the financial viability of an oil and gas company. Costs in oil and gas companies can be extremely large and there is potential for error. If your auditor were to take a more through approach to looking at expenses, they might find ways to add to the bottom line.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Question 4 - How do your auditors validate that you are receiving what is owed to you?

noreply@blogger.com (Chris Hamilton) — Sun, 13 Dec 2009 15:53:00 +0000

This is the forth question in the list of ten questions to ask your auditor if you are a Canadian based oil and gas company. The original post can be found here.

The third question(s) is/are:

How do your auditors validate that you are receiving:

a. All revenue due to you?

b. All royalties due to you?

c. All transportation, processing fees and compression fees due to you?

Basically, you should be asking your auditors these questions to ensure that they have a process in place to ensure that you are receiving all that should be owed to you. In most cases, auditors may not have the ability to correlate all the information that is required. This isn't their fault as they may not have the proper tools to do so.

If your auditors were to look at this information, they may be able to identify potential revenues for your company. Then again, they may find areas where you owe money to a partner. We have seen numerous cases where royalties are owed or a working interest isn't being collected.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Question 3 - How do your auditors validate that your working interests are accurate in all your cost centers?

noreply@blogger.com (Chris Hamilton) — Sat, 12 Dec 2009 13:07:00 +0000

This is the third question in the list of ten questions to ask your auditor if you are a Canadian based oil and gas company. The original post can be found here.

The third question is "How do your auditors validate that your working interests are accurate in all your cost centers?"

The importance behind this is to ensure that you are getting the revenue that you are entitled to and paying the expenses that you are suppose to.

Working Interest example:

If you were to take the average oil well which produces 40 barrels of oil a day and look at the forecasted price for oil over the next few years, which is close to $90 per BOE, then the average well would produce $1.3M in revenue per year.

For examples sake, if the working interest is 50% or 50/50 with ABC Co, then your yearly revenue would be $657,000. If, by human error, you were to hit the next digit down on your keyboard, a 4 instead of a 5, you enter your working interest as 40% of the revenue against total production on the well, then the new amount is $525,600 in revenue. That 10% difference in working interest actually has the impact of reducing your revenue by 20% since you would be out $131,400 on $657,000. 20% out on revenue on any well is significant.

29,000 BOED is the average production a TSX listed company with production between 1,000 and 100,000 BOED. Of this 30%,on average, is oil production, or 8,700 BOED. If there were a 10% error rate on the wells and a 10% error rate on the working interests entered (assume entered lower) then this will potentially cost a company $2.9M in revenue per year.

If your auditor is not authenticating your your working interests or royalty rates against their cost centers, then you could potentially be missing revenue.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Question 2 - Cost Centers to Assets Match - Part of the 10 Questions An Oil and Gas Company Should Ask Their Auditors

noreply@blogger.com (Chris Hamilton) — Wed, 02 Dec 2009 13:28:00 +0000

This is the second question in the list of ten questions to ask your auditor if you are a Canadian based oil and gas company. The original post can be found here.

The question was:

How do your auditors tie up every cost center to your assets?

Cost centers allow companies to put the appropriate expenditures against the appropriate budget. This question can probably be best answered by asking a few more questions.

How can you auditors tie up cost centers to assets if they can’t create an authentic asset list or well list?

If your auditor cannot tie up cost centers, then how can they authenticate expenditures?

If you cannot tie up expenditures, then how do you know exactly what your company is spending?

Pretty straight forward, no match to an asset, then there is a possibility that errors can creep in.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Question 1 - Authenticated Master Well List - Part of the 10 Questions An Oil and Gas Company Should Ask Their Auditors

noreply@blogger.com (Chris Hamilton) — Sun, 29 Nov 2009 12:42:00 +0000

In my last post, 10 Questions An Oil and Gas Company Should Ask Their Auditors, I listed off 10 questions that Auditors should be asked to get an understanding of how they approach auditing your financials. This is especially critical as TSX listed oil and gas companies are about to start the switch to International Financial Reporting Standards.

In the next few posts, I will look at each question in more detail and the importance behind the question. The first question is:

How do your auditors authenticate your master asset list or well list to ensure accuracy?

This is an important question to ask your auditor, as an oil and gas company’s primary asset typically will be their reserves. Hard to believe, but there are few companies that even have an accurate master wells list. Smaller companies typically do, if they have high ownership and few wells, but Argentis Group had one client with production of about 300 barrels a day who stated that they had 59 gross wells and 56 net wells in their Annual Information Form (AIF) when in fact we uncovered over 200 gross wells and 56 net wells. Of the 56 net wells that they claimed they had, we had 20% different wells then they listed. Another firm that Argentis Group worked with had just gone through a 3-month process of creating a master well list, but we were still able to identify 4% of their wells missing of the newly made master list and 2% of the overall proved reserves missing.

The reason that companies do not have an accurate master well list is that there may be several different departments that keep a well list (no two being the same in most cases) and no true owner of the well list. For example, the Land department and the reserves department may have a list, engineering might have a list and finance might say that their Asset Retirement Obligation (ARO) list might be the well list, but basically, there is no authentic master well list.

In order for an auditor to do their job thoroughly and to have a starting point, they should have a process to look at a master well list with meta data such as working interests, royalty rates, operatorship, etc. I know that in reality the auditor only has to take the information that you provide and authenticate it, but for the fees that they charges, they should at least be able to help with a master well list.

If your auditor doesn’t have a process for assisting you create a master well list, then how do they know that you ARO’s and the wells on the ARO List are accurate. If your auditor doesn’t have or can’t compile a master well list, then they don’t know your reserves and how do they know if all your reserves are being tied up to a cash generating unit?

If you look at a company having an inaccurate master well list, then they are more than likely understating or overstating Depletion, Depreciation and Amortization (DD&A) costs. For example, let’s say that a company has $100 DD&A costs overall and you have 10 BOE as reserves. This translates to $10/BOE in DD&A. If you find 2 more BOE in reserves that you didn’t know you had, then you end up with $8.33/BOE in DD&A, which is derived from $100 (total DD&A costs) divided by 12 BOE (the new amount of reserves). In this case, the oil and gas company is overstating their DD&A costs by 20%. In addition, this company will now be able to increase their Net Asset Value (NAV) by potentially 20% through the additional reserves that were found.

The bottom line is, if your auditors don’t have a master well list or have no way of providing you with a master wells list, then they are doing you a disservice. You should be demanding more from your audit firms and be asking for more rigor in their process. If they can’t provide you with an accurate well list and help boost your overall value of your company, then you should look for a firm that will help you. Argentis Group can help create the accurate well list for your company.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

10 Questions An Oil and Gas Company Should Ask Their Auditors

noreply@blogger.com (Chris Hamilton) — Sat, 28 Nov 2009 07:52:00 +0000

With the introduction of International Financial Reporting Standards (IFRS) in Canada the financial landscape will be changing for publicly listed companies in January 2011 or just a little over a year. As such, companies would be wise to review not only how they are audited and how they will report, but also who is actually doing their financial audits for them.

Typical audits do have a lot of rigor built into them, but in most cases audit firms will use a spot check analysis (1 in every 5 or 1 in every 10 results for example) to determine if results are correct. Audit firms do this because they do not have the technology to perform a full verification of your financial results.

In fact, if the audit firms were to employ a more thorough approach and check all results, there are opportunities to uncover potential missed revenue and reserves, which would have a tremendous impact on the overall financial health of your company. On average, when my company Argentis Group performs an operational audit on a company, we expect to find 9% out on proved reserves. 9% out on reserves can have a significant impact on DD&A and thus the overall financials of an oil and gas company.

Listed below are ten questions that you should ask your auditor. I will go into more detail as to why you should ask these questions in subsequent posts.

Top 10 Questions An Oil and Gas Company Should Ask Their Auditors

1. How do your auditors authenticate your master asset list or well list to ensure accuracy?

2. How do your auditors tie up every cost center to your assets?

3. How do your auditors validate that your working interests are accurate in all your cost centers?

4. How do your auditors validate that you are receiving:

a. All revenue due to you?

b. All royalties due to you?

c. All transportation, processing fees and compression fees due to you?

5. How do your auditors validate that you are not overpaying:

a. Capital?

b. Operating expenses?

c. Royalties?

6. How do your auditors authenticate your Asset Retirement Obligation’s and Offset well liabilities?

7. How do your auditors tie up reserves to cash generating units?

8. Do your auditors authenticate well counts for Annual Information Form’s?

9. How can your auditors potentially make your IFRS conversion pay for itself and add asset value to your company?

10. How will your auditors ensure your Cash Generating Unit’s will be authenticated?

The numbers for the top 5 audit firms in Calgary are listed below.

Deloitte – 403-267-1700

E&Y – 403-290-4100

KPMG – 403-777-9999

PWC - 403-509-7500

MNP - 403-444-0150

Give your auditor a call and see if they can answer these questions for you. If they can not provide a thorough check against all results then you should ask them how they are going to do this to ensure accuracy as you move towards IFRS.

Argentis Group can perform a full array of operational audits to assist companies in identifying opportunities to help offset the costs of IFRS for oil and gas companies and also allow you to ensure financial accuracy. Typically, we will find enough value for your company to more that offset the costs and to make you transition to IFRS smoother and potentially allow for greater overall financial strength.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

The High Cost of Natural Gas - Potentially Breaking the Bank

noreply@blogger.com (Chris Hamilton) — Fri, 27 Nov 2009 18:06:00 +0000

I have written quite a bit about natural gas, but I recently found some information that highlights some of the issues facing oil and gas companies who depend on natural gas as part of their business.

Here are some interesting numbers on Natural Gas production in Western Canada:

Q2 2009 numbers that I have shown in the past show that the average sales price is $6.34/mcf
The average price for natural gas since 1999 was $5.90/mcf Canadian
The average price for natural gas since 2006 has been $6.44/mcf Canadian
The average price for natural gas over the last 12 months has been $4.64/mcf Canadian
In 2008, the National Energy Board of Canada claimed that the average cost per mcf for companies was $7.63 Canadian
Intermediate oil companies (between 10,000 and 100,000 BOED) had an average cost of $7.07 Canadian (excluding royalties)
Juniors (between 500 and 10,000 BOED) had an average cost of $9.27/mcf Canadian (excluding royalties)
In US dollars the average price of natural gas on the NYMEX was $5.43/mcf and $4.67/mcf on the AECO - This represents a NYMEX premium of 14%
In US dollars, since 2006, the average price of natural gas on the NYMEX was $6.77/mcf and $5.86/mcf for the AECO - This represents a NYMEX premium of 13%
In US Dollars, over the last 12 months (Oct 08 to Sept 09), the average price of natural gas on the NYMEX was $4.54/mcf and $3.93/mcf for the AECO - This represents a NYMEX premium of 14%

Below shows a graph of the monthly price of natural gas in Canadian dollars since 1999.

Above shows the price of natural gas since 2006 on a monthly basis in Canadian Dollars.

So no matter how you cut it, Western Canadian Gas is at a significant price and cost disadvantage. If we are pulling a mcf of gas out of the ground for $7.63 on average and we are getting a significantly lower price, $4.64/mcf (based on an average of the last 12 months), then you are losing $2.99/mcf and this isn't much of an economic business model. This example represents a 39% difference in price just to break even.

Over the long term the price of natural gas is, on average, lower than the current costs to extract it. Something has to be done to reduce the cost per mcf as we have very little impact over price of natural gas since it is market driven.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

No Two Companies are the Same - Cash Flow Analysis on Canadian Oil and Gas Companies

noreply@blogger.com (Chris Hamilton) — Sun, 22 Nov 2009 13:07:00 +0000

When you look at companies, a typical measure of a companies financial health is done via cash flow. It is basically the incoming cash vs. the outgoing cash or do you have enough cash to pay your bills.

A lot of times, people will look at cash flow per share as a financial benchmark, but in the oil and gas industry, if you use barrels of oil equivalent per day (BOED), or even better barrels of oil equivalent (BOE), then you get a better gauge of a companies overall financial health.

The follow information shows the cash flow per BOED and BOE for some select Junior and Intermediate companies:

Company	Size	Cash Flow	Cash flow/ Share	Cash flow/ BOED	Cash flow Per BOE
CrescentPoint	Intermediate	$137,960,000	$0.92	$3,339	$36.29
ParamountEng	Intermediate	$88,718,000	$0.78	$3,216	$34.96
Freehold	Junior	$21,884,000	$0.44	$3,000	$32.97
West	Junior	$12,063,000	$0.15	$2,948	$32.40
Peyto	Intermediate	$46,063,000	$0.43	$2,562	$27.84
Fairborne	Intermediate	$35,742,000	$0.41	$2,335	$25.38
NAL	Intermediate	$52,972,000	$0.52	$2,298	$24.98
Zargon	Junior	$21,325,000	$0.92	$2,240	$24.62
Baytex	Intermediate	$86,661,000	$0.82	$2,146	$23.32
Enerplus	Intermediate	$199,815,000	$1.18	$2,114	$22.98
Daylight	Intermediate	$48,459,000	$0.45	$2,103	$22.85
Culane	Junior	$3,032,000	$0.13	$2,049	$22.51
Bonterra	Junior	$9,780,000	$0.55	$1,951	$21.43
Bonavista	Intermediate	$101,655,000	$0.85	$1,964	$21.34
Pengrowth	Intermediate	$160,095,000	$0.62	$1,948	$21.18
ARC	Intermediate	$120,500,000	$0.51	$1,884	$20.48
Galleon	Intermediate	$29,605,000	$0.39	$1,842	$20.02
Delphi	Junior	$12,371,000	$0.16	$1,817	$19.97
Arcan	Junior	$2,764,000	$0.07	$1,815	$19.94
Celtic	Intermediate	$20,008,000	$0.46	$1,834	$19.94
Birchcliff	Intermediate	$20,026,000	$0.18	$1,770	$19.24
EagleRock	Junior	$916,000	$0.02	$1,738	$19.10
Fairwest	Junior	$1,388,000	$0.01	$1,716	$18.85
Advantage	Intermediate	$51,590,000	$0.36	$1,662	$18.06
NuVista	Intermediate	$41,779,000	$0.53	$1,621	$17.62
Rock	Junior	$5,195,000	$0.20	$1,561	$17.15
BlackPearl	Junior	$8,013,000	$0.03	$1,550	$17.03
Seaview	Junior	$3,076,000	$0.05	$1,489	$16.36
Stonefire	Junior	$2,037,000	$0.08	$1,488	$16.35
Crew	Intermediate	$20,036,000	$0.27	$1,488	$16.17
Zapata	Junior	$3,853,000	$0.23	$1,461	$16.05
Painted Pony	Junior	$1,826,000	$0.06	$1,391	$15.28
Diaz	Junior	$822,000	$0.01	$1,218	$13.38
NuLoch	Junior	$601,000	$0.02	$1,185	$13.03
Angle	Junior	$8,539,000	$0.21	$1,143	$12.56
Great Plains	Junior	$1,486,000	$0.02	$1,142	$12.55
Open Range	Junior	$2,508,000	$0.09	$1,117	$12.28
TRUE	Junior	$10,765,000	$0.14	$1,102	$12.11
Trilogy	Intermediate	$21,857,000	$0.22	$1,104	$12.00
Breaker	Junior	$7,493,000	$0.16	$1,064	$11.70
Storm	Junior	$8,460,000	$0.18	$1,038	$11.40
Buffalo	Junior	$2,743,000	$0.04	$1,011	$11.11
Cequence	Junior	$1,541,000	$0.04	$995	$10.94
Cinch	Junior	$2,569,000	$0.05	$982	$10.79
Redcliffe	Junior	$747,000	$0.01	$944	$10.38
Twin Butte	Junior	$2,691,000	$0.06	$940	$10.33
Crocotta	Junior	$1,884,000	$0.04	$939	$10.32
Midnight	Junior	$2,054,000	$0.04	$938	$10.31
ProspEx	Junior	$2,864,000	$0.05	$927	$10.19
Wrangler West	Junior	$1,034,000	$0.16	$926	$10.17
Berens	Junior	$3,866,000	$0.04	$925	$10.16
Yoho	Junior	$2,475,000	$0.12	$923	$10.14
Terra	Junior	$4,930,000	$0.07	$911	$10.01
Arsenal	Junior	$2,032,000	$0.02	$909	$9.99
ParamountRes	Intermediate	$12,236,000	$0.19	$916	$9.95
Questerre	Junior	$717,000	$0.004	$890	$9.78
Progress	Intermediate	$29,619,000	$0.18	$876	$9.52
Anderson	Junior	$6,692,000	$0.06	$859	$9.44
Enterra	Intermediate	$8,561,000	$0.14	$851	$9.25
Vero	Junior	$5,767,000	$0.15	$819	$9.00
Petro-Reef	Junior	$619,000	$0.02	$731	$8.03
Ironhorse	Junior	$877,000	$0.04	$717	$7.88
Midway	Junior	$673,000	$0.05	$687	$7.55
Intl Sovereign	Junior	$593,000	$0.04	$622	$6.83
Orleans	Junior	$2,326,000	$0.04	$604	$6.64
Sure	Junior	$372,000	$0.01	$570	$6.26
Bellamont	Junior	$394,000	$0.01	$454	$4.99
Triton	Junior	$420,000	$0.01	$447	$4.92
Fortress	Junior	$557,000	$0.02	$435	$4.79
Compton	Intermediate	$9,214,000	$0.07	$430	$4.67
Twoco	Junior	$511,000	$0.03	$403	$4.43
Monterey	Junior	$844,000	$0.03	$362	$3.98
Insignia	Junior	$273,000	$0.02	$353	$3.88
Canext	Junior	$347,000	$0.004	$349	$3.83
Iteration	Intermediate	$5,464,000	$0.03	$319	$3.47
DeeThree	Junior	$95,000	$0.01	$176	$1.93
Canadian Phoenix	Junior	$149,000	$0.0001	$169	$1.86
Argosy	Junior	$78,000	$0.01	$83	$0.92
Second Wave	Junior	$(26,000)	$(0.001)	$(26)	$(0.29)
Result	Junior	$(32,000)	$(0.0004)	$(52)	$(0.57)
Dejour	Junior	$(243,000)	$(0.003)	$(439)	$(4.82)
One	Junior	$(355,000)	$(0.01)	$(529)	$(5.81)
Action	Junior	$(855,000)	$(0.01)	$(880)	$(9.67)


Average		$18,687,410	$0.19	$1,180	$12.91

If you look at the low end of the cash flow per BOE, you will notice that one company, Action Energy, has been put into CCAA and most of their assets have been sold off and Result Energy was just recapitalized taken over by the former management team of Tristar Oil and Gas (watch Result Energy, this team has done wonders in the past).

On the upper end, it is good to see that there is a mix of intermediates and juniors, but heavily weighted to the intermediates. Towards the lower end, you see mostly the juniors.

It looks as if a lot of these companies still have pretty decent cash flow, even if we are in a period where gas prices are low. In the long run though, companies are going to have to look at ways to reduce their operating costs, particularly on the natural gas side of their business, to keep their cash flow strong.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company

Potential Loss or Profits for Oil and Gas Companeis

noreply@blogger.com (Chris Hamilton) — Tue, 17 Nov 2009 04:11:00 +0000

If you were to look at the strip forward prices for 2010 and apply the Q2 09 expenses per BOE numbers and apply them to the weighted production of the TSX listed Junior and Intermediate OIl and Gas companies with production in the Western Basin, you would see that about half of these companies will not turn a profit next year.

These are just potential projections use Q2 09 costs per BOE and 2010 strip forward prices on gas and oil. The expenses per BOE by company may move up or down depending on numerous factors. Junior companies have production between 1,000 and 10,000 BOED and Intermediates have production between 10,000 and 100,000 BOED.

Highlights:

80 Companies with production between 1,000 and 100,000 BOED
Production averaged 10, 744
Gas weighted at 68%
6,543 BOED Gas and 4,201 BOED Oil
Average expense per BOE $51.81 and $8.64 per MCF
Based on average price of $5.07/MCF on gas the average company will lose $27M from gas production
Based on average price of $89.40 per BOE of oil, the average company will make $66M from oil production
The average company is expected to make $38.6M in straight profit
Based on a blended rate, average company will lose $2.59 per BOE

The following table lays out the information:

Company	Junior or Intermediate	Expenses per BOE	Expenses per MCF	Profit/Loss Gas	Profit/Loss Oil	Profit Loss Total	Projected Profit / Loss Per BOE
Baytex	Intermediate	$37.39	$6.23	$(25,693,891)	$574,997,743	$549,303,852	$37.26
Freehold	Junior	$32.89	$5.48	$(2,437,109)	$94,788,408	$92,351,299	$34.68
Bonterra	Junior	$34.59	$5.76	$(3,052,126)	$60,185,743	$57,133,617	$31.22
Culane	Junior	$43.06	$7.18	$(1,912,098)	$18,023,094	$16,110,996	$29.82
ARC	Intermediate	$30.16	$5.03	$3,176,935	$663,943,167	$667,120,103	$28.57
Angle	Junior	$28.87	$4.81	$2,451,540	$69,334,343	$71,785,883	$26.32
West	Junior	$52.48	$8.75	$(7,576,614)	$42,465,153	$34,888,540	$23.36
Compton	Intermediate	$17.68	$2.95	$83,762,608	$89,803,405	$173,566,013	$22.18
Bonavista	Intermediate	$34.81	$5.80	$(47,294,812)	$443,533,226	$396,238,415	$20.97
Peyto	Intermediate	$19.85	$3.31	$58,296,617	$73,041,894	$131,338,511	$20.01
Enerplus	Intermediate	$36.01	$6.00	$(115,699,596)	$736,622,607	$620,923,011	$18.00
NAL	Intermediate	$43.84	$7.31	$(55,305,789)	$195,494,730	$140,188,941	$16.66
Pengrowth	Intermediate	$43.38	$7.23	$(194,369,170)	$690,107,149	$495,737,979	$16.53
Rock	Junior	$44.07	$7.34	$(8,125,682)	$28,092,172	$19,966,490	$16.43
Zargon	Junior	$43.83	$7.31	$(23,307,075)	$79,164,777	$55,857,702	$16.08
Zapata	Junior	$45.21	$7.54	$(6,836,426)	$22,124,709	$15,288,283	$15.88
Stonefire	Junior	$32.76	$5.46	$(819,859)	$8,490,058	$7,670,199	$15.35
Terra	Junior	$26.71	$4.45	$6,150,425	$19,812,776	$25,963,201	$13.14
NuVista	Intermediate	$36.01	$6.00	$(37,363,866)	$145,665,364	$108,301,498	$11.51
ParamountRes	Intermediate	$34.80	$5.80	$(15,809,109)	$69,235,261	$53,426,152	$10.95
Arcan	Junior	$61.39	$10.23	$(5,164,478)	$10,900,233	$5,735,756	$10.32
Storm	Junior	$28.73	$4.79	$4,319,026	$25,275,245	$29,594,271	$9.94
Enterra	Intermediate	$49.26	$8.21	$(35,973,108)	$70,736,678	$34,763,570	$9.47
Yoho	Junior	$30.49	$5.08	$(56,549)	$8,650,614	$8,594,065	$8.78
BlackPearl	Junior	$69.96	$11.66	$(14,177,858)	$29,709,101	$15,531,243	$8.23
Crew	Intermediate	$42.00	$7.00	$(38,139,978)	$76,879,000	$38,739,022	$7.88
Progress	Intermediate	$31.48	$5.25	$(11,279,286)	$100,084,149	$88,804,863	$7.19
Arsenal	Junior	$63.08	$10.51	$(8,796,390)	$14,391,740	$5,595,349	$6.86
Birchcliff	Intermediate	$40.64	$6.77	$(30,380,487)	$56,377,370	$25,996,883	$6.30
CrescentPoint	Intermediate	$77.75	$12.96	$(78,524,335)	$156,305,289	$77,780,954	$5.16
Ironhorse	Junior	$26.65	$4.44	$1,664,481	$280,097	$1,944,577	$4.36
Wrangler West	Junior	$41.98	$7.00	$(3,487,253)	$5,026,823	$1,539,570	$3.78
Berens	Junior	$38.44	$6.41	$(9,794,526)	$15,548,526	$5,754,000	$3.77
Redcliffe	Junior	$45.80	$7.63	$(3,019,803)	$4,028,008	$1,008,205	$3.49
Iteration	Intermediate	$43.39	$7.23	$(59,242,938)	$77,696,681	$18,453,743	$2.95
NuLoch	Junior	$46.65	$7.77	$(2,042,124)	$2,531,655	$489,531	$2.65
Cinch	Junior	$32.51	$5.42	$(1,834,032)	$4,345,836	$2,511,804	$2.63
Trilogy	Intermediate	$40.41	$6.74	$(57,047,189)	$74,347,734	$17,300,545	$2.39
ProspEx	Junior	$41.04	$6.84	$(9,339,451)	$11,995,590	$2,656,139	$2.36
Galleon	Intermediate	$49.31	$8.22	$(70,950,307)	$84,679,002	$13,728,695	$2.34
Twin Butte	Junior	$44.70	$7.45	$(10,748,392)	$13,083,563	$2,335,171	$2.23
Celtic	Intermediate	$45.22	$7.54	$(43,017,073)	$47,497,909	$4,480,837	$1.13
Painted Pony	Junior	$56.75	$9.46	$(7,065,592)	$6,885,446	$(180,146)	$(0.38)
Crocotta	Junior	$52.12	$8.69	$(10,169,291)	$9,826,218	$(343,073)	$(0.47)
Open Range	Junior	$37.36	$6.23	$(5,118,064)	$4,264,295	$(853,769)	$(1.04)
Anderson	Junior	$39.23	$6.54	$(21,783,642)	$18,543,276	$(3,240,366)	$(1.14)
Dejour	Junior	$49.93	$8.32	$(2,722,597)	$2,473,972	$(248,625)	$(1.23)
Midnight	Junior	$50.20	$8.37	$(10,906,690)	$9,708,375	$(1,198,316)	$(1.50)
Diaz	Junior	$41.50	$6.92	$(2,347,191)	$1,652,267	$(694,924)	$(2.82)
Vero	Junior	$44.08	$7.35	$(28,792,327)	$20,959,635	$(7,832,692)	$(3.05)
Triton	Junior	$37.16	$6.19	$(2,195,687)	$895,163	$(1,300,524)	$(3.79)
Delphi	Junior	$41.99	$7.00	$(25,009,982)	$15,318,550	$(9,691,432)	$(3.90)
Advantage	Intermediate	$53.83	$8.97	$(177,713,443)	$133,010,451	$(44,702,992)	$(3.95)
Orleans	Junior	$45.20	$7.53	$(17,020,689)	$11,174,697	$(5,845,992)	$(4.16)
Midway	Junior	$44.55	$7.43	$(4,297,030)	$2,406,272	$(1,890,757)	$(5.29)
Bellamont	Junior	$49.37	$8.23	$(4,678,059)	$2,786,741	$(1,891,318)	$(5.98)
Petro-Reef	Junior	$46.00	$7.67	$(4,045,158)	$2,146,928	$(1,898,231)	$(6.14)
Fairborne	Intermediate	$53.62	$8.94	$(94,618,072)	$53,981,703	$(40,636,369)	$(7.27)
Sure	Junior	$42.52	$7.09	$(2,681,202)	$782,220	$(1,898,981)	$(7.97)
Intl Sovereign	Junior	$46.28	$7.71	$(4,805,030)	$1,951,872	$(2,853,158)	$(8.19)
Argosy	Junior	$46.28	$7.71	$(4,761,636)	$1,766,094	$(2,995,542)	$(8.78)
Canext	Junior	$48.60	$8.10	$(5,612,314)	$2,222,601	$(3,389,713)	$(9.33)
Monterey	Junior	$52.02	$8.67	$(14,688,641)	$6,355,442	$(8,333,199)	$(9.80)
Great Plains	Junior	$63.18	$10.53	$(10,421,598)	$4,109,462	$(6,312,137)	$(13.29)
Seaview	Junior	$56.48	$9.41	$(15,721,142)	$4,964,960	$(10,756,182)	$(14.26)
Daylight	Intermediate	$62.82	$10.47	$(190,780,947)	$67,081,407	$(123,699,540)	$(14.70)
Twoco	Junior	$46.39	$7.73	$(7,394,933)	$-	$(7,394,933)	$(15.97)
Result	Junior	$50.13	$8.36	$(4,217,122)	$442,176	$(3,774,946)	$(16.76)
Insignia	Junior	$59.75	$9.96	$(6,702,579)	$1,589,563	$(5,113,015)	$(18.12)
Buffalo	Junior	$77.24	$12.87	$(25,047,474)	$5,539,305	$(19,508,169)	$(19.69)
Action	Junior	$81.40	$13.57	$(9,044,047)	$1,418,415	$(7,625,632)	$(21.49)
ParamountEng	Intermediate	$52.14	$8.69	$(218,666,684)	$-	$(218,666,684)	$(21.72)
One	Junior	$70.05	$11.68	$(7,085,462)	$1,279,523	$(5,805,939)	$(23.71)
Second Wave	Junior	$87.87	$14.65	$(9,313,603)	$303,020	$(9,010,583)	$(25.01)
Cequence	Junior	$64.16	$10.69	$(16,585,972)	$1,853,871	$(14,732,102)	$(26.07)
Questerre	Junior	$92.28	$15.38	$(10,190,898)	$(372,551)	$(10,563,449)	$(35.91)
Fairwest	Junior	$91.10	$15.18	$(15,409,190)	$(70,246)	$(15,479,436)	$(52.42)
TRUE	Junior	$150.82	$25.14	$(261,827,829)	$(85,396,312)	$(347,224,142)	$(97.40)
Canadian Phoenix	Junior	$189.85	$31.64	$(2,053,068)	$(31,045,696)	$(33,098,764)	$(102.81)
Fortress	Junior	$161.47	$26.91	$(60,567,127)	$(336,450)	$(60,903,577)	$(130.46)

Averages:		$51.81	$8.64	$(27,510,739)	$66,197,116	$38,686,377	$(2.59)


AECO 12 Month Strip: $5.07/mcf
Oil NYMEX 12 Month Strip @ $.91 exchange: $89.40

Based on this information, approximately half of these companies will not turn a profit in the next year. Now, these are only projects and not actuals, so some of these companies will probably be able to put a strategy in place that will reduce gas production and boost oil production and thus move them to profitability. There are other companies that, no matter how hard they try, may not be able to reduce their costs and hedge a higher rate received to turn them to profitability.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Offset Wells in the Western Basin - Millions of Dollars Owned to Owners!

noreply@blogger.com (Chris Hamilton) — Sat, 14 Nov 2009 20:33:00 +0000

There are numerous potential drilling locations in the Western Canadian Basin that go undrilled even though they can be easily identified through an offset well or offset wells.

An offset well is any well that is drilled within a section or quarter section basis either laterally or diagonally around a parcel of land. Imagine a tic tac toe board and the 9 squares are parcels of land. If you look at the middle square then an offsetting well or offset wells would be any well or wells that are drilled in the 8 squares that surround the middle square.

Offset wells are important to monitor for numerous reasons such as:

Compensatory royalties owed to freehold land owners
Potential notice from the government on crown lands from freehold offsets
Drainage reports on undrilled lands
Identify drilling prospects via production numbers from other wells
Identify a better producing zone than the one you are currently producing in

In the case of freehold lands, an offset well could trigger a clause in the land lease that would cause a "Drill, Drop or Compensate". Basically, if there is an offset well or offset wells that was drilled after the effective date of the land lease and the freehold owner has farmed out the land to an oil and gas company, then it potentially triggers the clause that says the oil and gas company has usually 6 months to drill a well, drop the lease or compensate the freehold owner. Typical leases denote that the oil and gas company will pay 50% of the royalty based on production from the offset well. There are circumstances where there are more than one offsetting well, so the freehold land owner should see which one has the best production history that goes back to the effective date. Please note, each lease is different, so there may be different clauses in the lease than what is denoted above. If you have or think you have an offset well against lands that you own, you should consult an attorney for help.

Example of Offsets in Western Canada

My company, Argentis Group has a process to run lands for offsets and we have used public data to identify potential offset wells. One of the companies that we have looked at has over 6,000 wells surrounding their undrilled freehold lands that are listed in public data. Of these 6,000+ sections of land, there are 1,300+ potential locations that have an offset well producing 20 barrels of oil equivalent or greater. If you look at this companies undrilled crown lands, there were over 54,000 sections that were undrilled with over 10,000 offset wells producing more than 20 barrels of oil equivalent.

Offset wells can be significantly costly if not followed. If a freehold land owner has a 5% royalty on an oil well and the average price is $96 Canadian for the next 8 years according to the Sproule price forecast, knowing that the average production from an oil well in the western basin is 40BOED, then this is equal to $70,080 per year in royalties owed to the freehold land owner. Over the average life of a well, approximately 8 years, this means that a freehold land owner could be out over $560,000.

The major reason that offset wells go unnoticed is that it is extremely hard to manage this process. In essence you are looking for wells that competitors are drilling around your lands. A lot of the time, oil and gas companies know what is going on in the core areas, but typically do not know what is going on in their un-core areas. Another major reason is that wells are being drilled all the time and oil and gas companies would have to continually monitor large amounts of land which they do not have time to do.

Argentis Group does have a process that allows us to utilize your land information to show you where wells are producing within a section or quarter section basis around your crown and freehold lands. This information can be run in numerous ways to show the following on freehold or crown lands:

Un-drilled lands with an offset well or offset wells drilled after an effective date of a lease which is producing in an offseting zone
Un-drilled lands with an offset well or offset wells drilled before an effective date of a lease which is producing in an offseting zone
Un-drilled lands with an offset well or offset wells drilled after an effective date of a lease which is not producing in an offseting zone
Un-drilled lands with an offset well or offset wells drilled before an effective date of a lease which is not producing in an offseting zone

If you are an individual freehold land or and oil and gas company and you should be keeping close tabs on your lands and rights. Argentis Group can help you with this. Please feel free to contact me at info@argentis-group.com.

Canadian Based Intermediates Q2 2009 Numbers - Part 1: Costs Per BOE

noreply@blogger.com (Chris Hamilton) — Wed, 11 Nov 2009 14:22:00 +0000

I have now shifted focus to the Canadian based intermediate oil and gas companies with conventional production in the Canadian Western Basin. Intermediate companies are those with production between 10,000 barrels of oil equivalent a day (BOED) and 100,000 BOED.

In Part 1, I am looking at the costs or expenses per BOED, which are derived by taking average sales price per BOE and subtracting the net income per BOE. Sales per BOE is usually found in the quarterly report, or if it isn't listed you can determine it by taking total revenue for the quarter and dividing it by the total boe production for the quarter, in this case BOED rate times 92 days in the quarter.

Here are the highlights:

There were 23 companies that are 65% weighted to natural gas and the average production was 30,664 BOED

The average income for these companies is -$6.08M

Net income per BOED was -$401.88

Income per Barrel of Oil Equivalent (BOE) was -$4.37

Average sales price per BOE was $38.06 and $6.34 per MCF

Average expenses per BOE was $42.43

Based on the average expenses per BOE, the expenses per MCF were $7.07

Here is a list of the 23 companies sorted on expenses per BOE:

Company	Daily Production	Net Income	Income / BOED	Income per BOE	Sales Price / BOE	Expenses per BOE	Expenses per MCF
CrescentPoint	41,318	$(67,262,000)	$(1,628)	$(17.69)	$60.06	$77.75	$12.96
Daylight	23,047	$(14,543,000)	$(631)	$(6.86)	$55.96	$62.82	$10.47
Advantage	31,044	$(37,810,000)	$(1,218)	$(13.24)	$40.59	$53.83	$8.97
Fairborne	15,308	$(17,333,000)	$(1,132)	$(12.31)	$41.31	$53.62	$8.94
Paramount Eng.	27,583	$(8,728,000)	$(316)	$(3.44)	$48.70	$52.14	$8.69
Galleon	16,076	$(22,012,000)	$(1,369)	$(14.88)	$34.43	$49.31	$8.22
Enterra	10,059	$(14,383,000)	$(1,430)	$(15.54)	$33.72	$49.26	$8.21
Celtic	10,909	$(5,459,000)	$(500)	$(5.44)	$39.78	$45.22	$7.54
NAL	23,049	$(9,407,000)	$(408)	$(4.44)	$39.40	$43.84	$7.31
Iteration	17,137	$(22,978,000)	$(1,341)	$(14.57)	$28.82	$43.39	$7.23
Pengrowth	82,171	$10,272,000	$125	$1.36	$44.74	$43.38	$7.23
Crew	13,466	$(12,267,000)	$(911)	$(9.90)	$32.10	$42.00	$7.00
Birchcliff	11,313	$(7,128,000)	$(630)	$(6.85)	$33.79	$40.64	$6.77
Trilogy	19,800	$(19,695,000)	$(995)	$(10.81)	$29.60	$40.41	$6.74
Baytex	40,387	$27,451,000	$680	$7.39	$44.78	$37.39	$6.23
NuVista	25,777	$(7,312,000)	$(284)	$(3.08)	$32.93	$36.01	$6.00
Enerplus	94,501	$(3,569,000)	$(38)	$(0.41)	$35.60	$36.01	$6.00
Bonavista	51,768	$661,000	$13	$0.14	$34.95	$34.81	$5.80
Paramount Res.	13,362	$(2,582,000)	$(193)	$(2.10)	$32.70	$34.80	$5.80
Progress	33,817	$(20,915,000)	$(618)	$(6.72)	$24.76	$31.48	$5.25
ARC	63,969	$66,100,000	$1,033	$11.23	$41.39	$30.16	$5.03
Peyto	17,982	$29,189,000	$1,623	$17.64	$37.49	$19.85	$3.31
Compton	21,440	$19,848,000	$926	$10.06	$27.74	$17.68	$2.95

Averages:	30,664	$(6,080,957)	$(401.88)	$(4.37)	$38.06	$42.43	$7.07

The expenses per MCF are derived by taking the BOE price and dividing by 6.

Of interest:

The average loss per BOE and MCF was 11.5%

The avearge expense for intermediates was 24% lower than the juniors

Average expense for the juniors were $55.60 per BOE or $9.27 per MCF vs. $42.43 per BOE or $7.07 per MCF for intermediates

Average net income pre BOE for the juniors was -$21.17 per BOE compared with -$4.37 per BOE for intermediates

The sell price per BOE was 12% higher for Intermediates, $38.06 vs. $33.61

This potentially shows that companies with more production, on average, should have gains in efficiencies. If you look at the average sell price per barrel, I would bet that there are better hedging programs in place.

The one thing that does stand out is that the expenses per BOE and MCF, especially for gas weighted companies are still too high to allow these companies to turn a profit. Of the 23 companies, only 6 or 26% actually make money on each BOE produced. Expenses have to be looked at, especially gas, to determine where costs can be removed. Based on the AECO 2010 natural gas price of $5.20 for the next year , the costs will probably have do come down, over 25% in just for companies to break even. 25% cost reduction in oil and gas companies will be extermely tough to accomplish, every cost cutting measure will need to be looked at. The juniors are in a worse positions with respect to costs associated with natural gas. At $9.27 per MCF, the juniors will have to reduce their operating costs potentially by over 40% just to break even.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Recent Experiences With Drilling Companies - I Can't Make This Stuff Up

noreply@blogger.com (Chris Hamilton) — Fri, 06 Nov 2009 02:35:00 +0000

I am taking a bit of a deviation from my usual posts with numbers and statistics to write about some experiences that I recently had that continues to support my thoughts that there are problems with the Western Canadian Basin.

Since I am part owner of a consulting company that works with oil and gas companies and also companies that service the oil and gas industry, I have to continually be trying to find sales. Just to give a bit of a background, my company, Argentis Group, provides operational audits in oil and gas companies to identify areas to reduce costs and/or increase revenues. One of the processes that we run in oil and gas companies typically identifies missed reserves, which can have can have a significant impact on reducing capital spend associated with reserves replacement, not to mention reducing DD&A costs and find and develop costs. In addition, we run an offset well report that shows were wells are draining un-drilled land holdings. We also use public data to identify potential drilling prospects for oil and gas companies.

Since Argentis Group can run reports on un-drilled lands to spot potential drainage and we can identify significant cost savings that can be deployed to potential new drills, I thought I would call drilling companies to see if they would be interested in learning about an innovative way to identify drilling prospect for their clients and show them a way to potentially self-fund their projects out of Capital Cost Savings. I thought that since the majority of drilling companies have seen their business reduced 43% in the last year, they might be interested in understanding how to potentially increase their utilization rates on their rigs all while helping their clients out by finding reserves and potentially increasing their client's net asset value. Just a hunch, but I think that drilling companies might want figure out ways to help increase their rig utilization rates.

So, I called the top 7 drilling companies in Canada. I called either a VP of Sales, Sales Manager or a Senior VP who would be in charge of conventional drilling for Canada. I managed to get through to one VP (title and company to remain nameless) and left messaged for 5 and missed one who didn't have voicemail. I have to say, not having a voicemail for the VP responsible for sales for a large drilling company is a little crazy, what if someone wanted to, I don't know, maybe use their services and now can't leave a message to ask this drilling company to do business with them. I wonder how many sales this company has missed because of this?

The VP that I did actually get through to was actually very nice to me, considering that I was actually cold calling him and interrupting his day. Now that said, I was pretty shocked by what I was told. I went through a bit of a spiel about what Argentis Group does, the applicability of our services as it relates to a drilling company and I also mentioned the fact that based on an analysis of what we typically find, that I felt we might be able to have the impact of increasing their rig utilization rate by up to 15%. What I heard in response makes me thank my lucky stars that I do not have any stock in the publicly traded company. I was told that they had heard this type of pitch a couple of times (which I would assume they hadn't since no other company does what we do) and that they were comfortable with their rig utilization rate where it was and were not looking for ways to increase it at this time. WHAT???? If I were an investor in this company and a senior VP told me this, I would be shocked. I would be calling my broker to unload the shares ASAP. Who in their right mind, whether they use my solutions or not, would not be looking for ways to grow their business. I think that this person may not have been familiar with Shareholder Value.

The other shocking part of this is that I have yet to hear back from even one of the companies I called. I am guessing that since the rig utilization rate is 23% this year (January to September, down from an average of 40% in 2008) that they too might be satisfied with these sort of low utilization rates. I sure am glad that they have understanding shareholders that know that senior management is doing all they can to ensure that the company's continued success is first and foremost.

To me, this just highlights yet another problem in the Western Canadian Basin.

Then again, perhaps I did a bad job sell these people on my concepts, I certainly hope so for all the investors in these companies sake.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company. PS. If you are a drilling company and you would like to talk to me about growing your business, then by all means contact me via email.

Analysis of Q2 Results for Junior Oil and Gas Companies on the TSX Part Four - The Value of A BOED

noreply@blogger.com (Chris Hamilton) — Wed, 04 Nov 2009 13:03:00 +0000

In this post, I will look at the value of a Barrel of Oil Equivalent per Day (BOED) for 60 publicly listed oil and gas juniors with production between 500 and 10,000 BOED and production from the Western Canadian Basin. The definition that I will use for the value of a BOED is Market Capitalization divided by the BOED rate plus the Debt divided by the BOED rate. This will give the enterprise value price per BOED based on the share price as of the last day of Q2 2009 which is August 31 2009.

Overview:

60 Junior Oil and Gas Companies with production between 500 and 10,000 BOED

Average market capitalization per BOED is $16,141

Average debt per BOED is -$9,549

Average enterprise value (market cap less debt) per BOED is $30,871

8 of the 60 companies didn't have any debt

Company	Market Cap per BOED	Debt per BOED	Enterprise Value per BOED
Questerre	$183,658	$63,217	$246,875
Insignia	$10,259	$34,508	$44,768
West	$9,596	$23,158	$32,755
Painted Pony	$6,173	$16,976	$23,149
BlackPearl	$30,763	$11,234	$41,997
DeeThree	$2,401	$2,793	$5,194
Sure	$20,185	$2,570	$22,754
Bellamont	$41,061	$977	$42,038
Angle	$2,190	$(1,235)	$3,425
Intl Sovereign	$6,411	$(2,795)	$9,206
Terra	$3,354	$(4,641)	$7,994
Canext	$26,527	$(6,515)	$33,042
ProspEx	$11,146	$(7,530)	$18,677
Culane	$11,875	$(7,703)	$19,578
Triton	$6,935	$(7,798)	$14,733
Zargon	$18,584	$(7,940)	$26,523
NuLoch	$51,004	$(8,615)	$59,619
Anderson	$10,680	$(8,970)	$19,650
Storm	$12,276	$(8,985)	$21,261
Yoho	$5,731	$(9,395)	$15,126
Ironhorse	$1,601	$(9,407)	$11,008
Redcliffe	$32,724	$(9,826)	$42,550
One	$14,468	$(10,204)	$24,672
Wrangler West	$1,430	$(10,235)	$11,665
Breaker	$3,401	$(10,441)	$13,842
Rock	$7,779	$(10,447)	$18,226
Dejour	$49,651	$(10,671)	$60,323
Midnight	$25,137	$(10,938)	$36,075
Diaz	$9,952	$(11,400)	$21,352
TRUE	$6,132	$(11,738)	$17,870
Orleans	$1,241	$(12,324)	$13,565
Midway	$2,052	$(12,581)	$14,632
Cinch	$16,800	$(12,730)	$29,530
Canadian Phoenix	$38,500	$(13,076)	$51,576
Cequence	$6,460	$(13,694)	$20,154
Twin Butte	$13,987	$(13,928)	$27,915
Second Wave	$7,508	$(14,395)	$21,903
Petro-Reef	$12,086	$(14,579)	$26,665
Berens	$17,456	$(14,585)	$32,041
Monterey	$9,465	$(14,664)	$24,129
Crocotta	$658	$(14,894)	$15,552
Vero	$275	$(15,057)	$15,332
Twoco	$8,843	$(15,234)	$24,077
Delphi	$1,858	$(15,289)	$17,147
Stonefire	$3,923	$(15,914)	$19,837
Result	$11,085	$(16,102)	$27,187
Open Range	$5,319	$(16,429)	$21,747
Arsenal	$16,301	$(16,594)	$32,895
Great Plains	$21,803	$(17,005)	$38,808
Bonterra	$19,240	$(17,303)	$36,543
Seaview	$28,476	$(17,477)	$45,953
Fairwest	$8,120	$(19,311)	$27,431
Zapata	$2,717	$(19,779)	$22,496
Buffalo	$14,500	$(20,057)	$34,557
Freehold	$41,048	$(20,811)	$61,859
Fortress	$9,262	$(21,777)	$31,039
Arcan	$9,687	$(25,716)	$35,403
Argosy	$1,629	$(27,538)	$29,167
Action	$8,836	$(33,700)	$42,536
EagleRock	$6,210	$(38,433)	$44,642

Average	$16,141	$(9,549)	$30,871

As can be seen, due to the low valuations or market capitalization and the high debt loads that companies have taken on, the enterprise value per BOED for half of these companies is negative.

The average enterprise value per BOED, $30,871, highlights the fact that there is a problem with the Juniors. Right now, the average Find and Develop (F&D) cost to bring a Barrel of Oil Equivalent (BOE) on line is $16. If the average proved reserves is 8 years then the total cost to bring on a BOED is $16 X 365 days X 8 years = $46,720/BOED. It's less expensive for companies that are looking to acquire production to just buy up these Juniors since the difference between the enterprise value and the actual F&D costs are $12,793. Of the 60 companies listed, there are 55 that have enterprise values lower than $46,720. 92% of the juniors enterprise value is lower than the average F&D costs per BOED, which means that they are undervalued.

I assume that there are several reasons why a lot of these companies have not been acquired and the two that stick out are; lack of access to capital, high debt loads that the juniors are carrying. Acquiring companies probably do not want to take on the debt that the juniors have incurred. Also, as the old saying goes, give them enough rope and they will hang themselves. I think a lot of the juniors have a long enough rope, it is just a matter of time.

I still think that we will see some of these companies get themselves into problems financially since they are carrying a significant amount of debt compared to asset value and banks will start calling there financing. In fact it just happened to one of the juniors listed, Action Energy, where National Bank called the outstanding money owed to them, which was $31.6M. You can see the story here.

At the end of the day, large debt loads and low valuations combined with numerous other factors such as the current market conditions, the low prices of natural gas and such, will be crippling to some of these companies.

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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

Analysis of Q2 Results for Junior Oil and Gas Companies on the TSX Part Three - Income per Barrel of Oil Equivalent or Lack of Income

noreply@blogger.com (Chris Hamilton) — Sun, 01 Nov 2009 17:12:00 +0000

This is the third part of as series that look at the Q2 2009 results of 57 TSX listed companies with production in the Western Canadian Basin. In this post I will look at Net Income for the juniors.

First off, the definition of net income is a companies total earnings or revenues less expenses.

Here are the numbers:

Only 3 of the 57 companies had positive net income

True Energy Trust had -$99M in net income for the quarter, which is the worst offender

Freehold Royalty Trust was at the other end with $6.7M in net income

The average net income for the companies was -$4.6M

Average net income per Barrel of oil equivalent per day (BOED) was -$2,023

Average net income per Barrel of oil equivalent was -$21.99

Worst Net Income per BOE (at -$136.58) and per BOED (at -$12,566 per BOED) was Canadian Phoenix

The best Net Income per BOE (at $10.10) and per BOED (at $929) was Freehold Royalty Trust

Below is a list of the 57 companies:

Company	BOED	Net Income	Income per BOED	Net Income per BOE	Average Sell Price Per BOE	Expenses per BOE
Canadian Phoenix	882	$(11,083,000)	$(12,566)	$(136.58)	$53.27	$(189.85)
Fortress	1,279	$(14,605,000)	$(11,419)	$(124.12)	$37.35	$(161.47)
TRUE	9,767	$(99,715,000)	$(10,209)	$(110.97)	$39.85	$(150.82)
Fairwest	809	$(3,961,000)	$(4,896)	$(53.22)	$37.88	$(91.10)
Questerre	806	$(3,835,000)	$(4,758)	$(51.72)	$40.56	$(92.28)
Second Wave	987	$(4,138,000)	$(4,193)	$(45.57)	$42.30	$(87.87)
Action	972	$(3,766,000)	$(3,874)	$(42.11)	$39.29	$(81.40)
Buffalo	2,714	$(9,981,000)	$(3,678)	$(39.97)	$37.27	$(77.24)
One	671	$(2,394,000)	$(3,568)	$(38.78)	$31.27	$(70.05)
Insignia	773	$(2,245,000)	$(2,904)	$(31.57)	$28.18	$(59.75)
Result	617	$(1,766,000)	$(2,862)	$(31.11)	$19.02	$(50.13)
Monterey	2,329	$(5,485,000)	$(2,355)	$(25.60)	$26.42	$(52.02)
BlackPearl	5,170	$(10,889,000)	$(2,106)	$(22.89)	$47.07	$(69.96)
Canext	995	$(2,024,000)	$(2,034)	$(22.11)	$26.49	$(48.60)
Intl Sovereign	954	$(1,931,000)	$(2,024)	$(22.00)	$24.28	$(46.28)
Argosy	935	$(1,726,000)	$(1,846)	$(20.07)	$26.21	$(46.28)
Great Plains	1,301	$(2,373,000)	$(1,824)	$(19.83)	$43.35	$(63.18)
Bellamont	867	$(1,546,000)	$(1,783)	$(19.38)	$29.99	$(49.37)
Petro-Reef	847	$(1,492,000)	$(1,762)	$(19.15)	$26.85	$(46.00)
Sure	653	$(1,140,000)	$(1,746)	$(18.98)	$23.54	$(42.52)
Twoco	1,269	$(2,206,000)	$(1,738)	$(18.90)	$27.49	$(46.39)
Midnight	2,189	$(3,668,000)	$(1,676)	$(18.21)	$31.99	$(50.20)
Orleans	3,848	$(6,432,000)	$(1,672)	$(18.17)	$27.03	$(45.20)
Crocotta	2,006	$(3,193,000)	$(1,592)	$(17.30)	$34.82	$(52.12)
Seaview	2,066	$(3,273,000)	$(1,584)	$(17.22)	$39.26	$(56.48)
Cequence	1,548	$(2,444,000)	$(1,579)	$(17.16)	$47.00	$(64.16)
Vero	7,040	$(10,748,000)	$(1,527)	$(16.59)	$27.49	$(44.08)
Painted Pony	1,313	$(1,965,000)	$(1,497)	$(16.27)	$40.48	$(56.75)
Midway	980	$(1,432,000)	$(1,461)	$(15.88)	$28.67	$(44.55)
Redcliffe	791	$(1,147,000)	$(1,450)	$(15.76)	$30.04	$(45.80)
Arsenal	2,236	$(3,236,000)	$(1,447)	$(15.73)	$47.35	$(63.08)
Dejour	554	$(781,000)	$(1,410)	$(15.32)	$34.61	$(49.93)
Anderson	7,789	$(10,410,000)	$(1,337)	$(14.53)	$24.70	$(39.23)
ProspEx	3,089	$(3,899,000)	$(1,262)	$(13.72)	$27.32	$(41.04)
Triton	939	$(1,170,000)	$(1,246)	$(13.54)	$23.62	$(37.16)
Twin Butte	2,864	$(3,328,000)	$(1,162)	$(12.63)	$32.07	$(44.70)
Culane	1,480	$(1,532,000)	$(1,035)	$(11.25)	$31.81	$(43.06)
NuLoch	507	$(520,000)	$(1,026)	$(11.15)	$35.50	$(46.65)
Cinch	2,616	$(2,553,000)	$(976)	$(10.61)	$21.90	$(32.51)
Diaz	675	$(619,000)	$(917)	$(9.97)	$31.53	$(41.50)
Berens	4,180	$(3,782,000)	$(905)	$(9.83)	$28.61	$(38.44)
Wrangler West	1,117	$(1,009,000)	$(903)	$(9.82)	$32.16	$(41.98)
Arcan	1,523	$(1,314,000)	$(863)	$(9.38)	$52.01	$(61.39)
Open Range	2,245	$(1,927,000)	$(858)	$(9.33)	$28.03	$(37.36)
Yoho	2,682	$(1,818,000)	$(678)	$(7.37)	$23.12	$(30.49)
Ironhorse	1,223	$(653,000)	$(534)	$(5.80)	$20.85	$(26.65)
Rock	3,329	$(1,745,000)	$(524)	$(5.70)	$38.37	$(44.07)
Zapata	2,638	$(1,294,000)	$(491)	$(5.33)	$39.88	$(45.21)
Delphi	6,809	$(2,817,000)	$(414)	$(4.50)	$37.49	$(41.99)
Angle	7,472	$(2,248,000)	$(301)	$(3.27)	$25.60	$(28.87)
Storm	8,153	$(2,192,000)	$(269)	$(2.92)	$25.81	$(28.73)
Zargon	9,520	$(2,553,000)	$(268)	$(2.91)	$40.92	$(43.83)
Terra	5,412	$(1,117,000)	$(206)	$(2.24)	$24.47	$(26.71)
Stonefire	1,369	$(134,000)	$(98)	$(1.06)	$31.70	$(32.76)
West	4,092	$604,000	$148	$1.60	$54.08	$(52.48)
Bonterra	5,014	$4,544,000	$906	$9.85	$44.44	$(34.59)
Freehold	7,295	$6,776,000	$929	$10.10	$42.99	$(32.89)

Averages	2705	$(4,619,825)	$(2,023)	$(21.99)	$33.61	$(55.60)

Here is an example to highlight some serious problems happening to oil and gas companies in the western basin. The main key metric to look at is the Net Income per BOE or how much income a company makes from each barrel of oil equivalent that is produced. Canadian Phoenix Resources Corporation had the worst Net Income per BOE at -$136.58. This was determined by taking the net income for the quarter (-$11M) and dividing it by the total production for the quarter (882 BOED X 92 Days). The bigger issue is that based on the average sell price of $53.27 per BOE less the net income of -$136.58 this probably means that the expenses (all in) per BOE for Canadian Phoenix are $189.85. Hard to believe that a company would have potential expenses that are 3.5 times what they sell a product for, not much of a sustainable business model.

On the other end, Bonterra has a net income per BOE of $9.85 and an average sell price of $44.44 per BOE which would mean that the expenses (all in) per BOE are $34.59. Bonterra actually has positive income.

Bottom line, a lot of these juniors costs are too high and they are not getting a decent sales price on the product they sell. Based on the sheer amount of companies that have negative income, if prices don't increase and if cost don't go down drastically, then there will be a lot of companies facing some serious financial decisions as it relates to the future of their companies. When companies are offering products that cost on average 1.7 times more than what they sell them for, it doesn't take long for this to catch 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. Argentis Group assists oil and gas companies with operational audits to identify areas to reduce costs, increase revenues and increase the overall asset value of an oil and gas company.

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

noreply@blogger.com (Chris Hamilton) — Sat, 31 Oct 2009 01:12:00 +0000

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

noreply@blogger.com (Chris Hamilton) — Mon, 26 Oct 2009 12:39:00 +0000

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

noreply@blogger.com (Chris Hamilton) — Mon, 12 Oct 2009 01:55:00 +0000

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

noreply@blogger.com (Chris Hamilton) — Sun, 04 Oct 2009 20:22:00 +0000

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.