To get the future FCF's you need a reserve report of the assets that they own. Once you seperate the 1p's from 2p's from 3p's (possibles, probables and proved) you can start allocating the possibility of the oil being present times the amount of the field.

You then forecast this until the terminal value at the end of the R/P life. (Ex- if the reserve/production life is 9 years, your TV would be at the end of year 9).

In oil and gas it is customary to discount everything by 10% (No this is not Re or WACC). To compute the WACC for an oil company it is very much like computing the WACC for any company.

In oil & gas, a DCF is practically useless. In addition to having real sensitive inputs (Rr and g) you have arbitrary FCF's. In practice most people rely on comps and precedent transactions.

 

Valuation metrics: Price to Mcfe Price to Mcfe/d

Other:

R/P (reserves to annual production) 1 Mcfe = 1 Million cubic foot equivalent (natural gas) 1 BOE (1 barrel of oil equivalent) = 6 Mcfe

There are also some metrics related to acreage, but they vary depending upon basin.

Oil and gas is getting crushed right now, so don't get too excited about the field...

 
models_and_bottles:
Valuation metrics: Price to Mcfe Price to Mcfe/d

Other:

R/P (reserves to annual production) 1 Mcfe = 1 Million cubic foot equivalent (natural gas) 1 BOE (1 barrel of oil equivalent) = 6 Mcfe

There are also some metrics related to acreage, but they vary depending upon basin.

Oil and gas is getting crushed right now, so don't get too excited about the field...

How do I estimate the BOE/d ? I mean what does it depend on ? Revenues ? I am doing a valuation on a small cap oil company for my corporate finance project. Thats why I need help. Also where can I get the figures for BOE/d from. We have just bloomberg and some other financial databases.

 

the right way to value the company is to build a model based off well reports like wood mac. you will need production forecasts for each well they own (boe) and multiply that by your predicted oil price. take out operating costs, fiscal regimes (columbia for example takes out taxes as a royalty, tax, and then through their own field ownership) and capex. you now have a series of company cash flows for each well. npv those cashflows at the wacc (as poster above said, 10% is standard) and now you have your dcf value.

this is only to get the value of producing wells though. to get the value of their exploration segment, generally, standard is to take research values and adjust risk weightings. lets assume research says that all of the exploration in ... mexico ... is worth approximately $500 million at 25% risk. well we usually assume that there is really a max of 10% risk for exploration, so we will adjust research's model down based on that.

this yields a SOTP where you have a value of the company where you can compare against its current FV.

IF you dont have the woodmac reports like it sounds, you need to just do a multiples valuation. usually you will do this on their current reserves or LTM production. this is all disclosed in their filings...though reserves generally are not disclosed until the K. Overall, its simple...take the reserves and multiply against the 2p reserve multiple average from its peers and you have a value

 

The method wkbrdr talked about is definitely the preferred method of valuing O&G assets / companies. Unfortunately, you're not going to have access to that information for the project your doing.

As far as the metrics, all public O&G companies are required to discose their reserve and production #'s in their annual 10Ks. They give production updates in their 10Qs as well, although they usually dont update their reserve numbers.

PS - Boe/d is a physical production metric, so revenue depends upon barrels of oil sold * realized price, not they other way around.

A good database to use to look for old transactions is Herolds (www.herold.com), probably expensive to get though.

If I were you, I would try to find a professor or student knowledgable in the subject to help you.

 

Thanks, now I have some questions regarding forward multiples. How do I estimate the future reserves/production. Secondly how do I bring it back to present. Is there a discount factor involved ? Say I have Price/(Boe/d) ratio. If I am able to estimate the future production rate, how do I bring it back ?

 

I am having trouble choosing the peers for my Comps. My company is a micro cap company named Winstar. Its a canadian E&P company with the majority of its operations in Tunisia. I found only similar micro cap canadian companies operating in the middle east. How do I choose the rest of its peers ? Just similar sized canadian oil companies ? Or do I look at international companies of similar size operating in Tunisia ? Please help.

 

Bump - had posted this on another thread but looks like it was a blog on this site...

Am looking at some O&G companies on the side (was curious and am looking at it for my own PA) - how do you effectively come up with your 2P and 3P assumptions? The companies I have looked into don't seem to report it and broker reports don't seem to provide much color regarding to numbers they are using. Is it just a pure estimate based on acreage and region?

Also, how do you guys estimate the production curve for your NAV model - does it vary by group or is there a standard way to look at it? The sample I have seen assumes a 5% decrease after Y5 (end of op model projection period) - not sure if there is a science behind choosing this.

Sorry if this is obvious - thanks!

 
Best Response

If it's an overnight valuation, then I don't know why you're trying to get so far into the weeds (projecting the production of individual wells in one night? Yeah right.)

Were you specifically asked to value it using a NAV approach? If not, just build out a DCF. Keep it high level, and just make sure your model can flex the assumptions - you can always change them later. Dig up some equity research and just use their estimates.

Better yet, just set up a rough public comps screen.

 

For a quick exercise just check the investor presentation. They will probably give you a pv per well number, then assume some drilling schedule based on how many rigs they are running in the play... So if they can drill a well in 20 days and have 5 rigs... You do the math.

Just for a swag take the standardized measure from the 10k x %pdp and apply acreage multiples to capture the resource upside... precedent transactions for this part.

Subtract net debt, add any other random assets they have like midstream or minority ownership in an mlp, divide by fully diluted share count and BAM! You've got an NAV.

 

For a quick exercise just check the investor presentation. They will probably give you a pv per well number, then assume some drilling schedule based on how many rigs they are running in the play... So if they can drill a well in 20 days and have 5 rigs... You do the math.

Just for a swag take the standardized measure from the 10k x %pdp and apply acreage multiples to capture the resource upside... precedent transactions for this part.

Subtract net debt, add any other random assets they have like midstream or minority ownership in an mlp, divide by fully diluted share count and BAM! You've got an NAV.

 

Good answers guys!

for just the night I went with what @CHItizen suggested beut sill got to come up with the detailed one over next week so what what would be your suggestion then. do let me know please. for some reason there isn't a well by well PV in the 10q in case anyone wanted to know. the investor presentation has a total PV10 but that's abt it.

Also ive been under the impression that DCF is just not the way to go about valuing an o&g firm which is why the switch to NAV. Havent really been told what to use but for a more proper analysis wouldn't NAV method be the way to go?

 

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