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

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:

1. Operating Costs: includes numerous different items such as power, well servicing and others
2. General and Administrative: office expenses such as wages, benefits and others
3. Marketing and Transportation: costs associated with moving oil and gas
4. Interest: money paid on loans
5. 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.
6. 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.

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

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

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.

Reserves Per Producing Well - Where Did It Go?

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

Gas Reserves per Well: 1956 to 2007

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

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

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

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

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

Oil Reserves per Well: 1962 to 2007

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

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

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

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

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

My View:

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

An Example of the Cost of Reserves:

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

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

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

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