Oil and Gas Modeling Differences??

Hey,

At the highest level, what are the key inputs/differences in building an earnings model for an oil and gas company (e&p) versus a typical model.

I.e. Are cash flows driven simply by expected production based on proven, probable and potential reserves and attributing a probability percentage for those less op. expenses? What are the key metrics? FCF, NAV, Earnings???

I want to model a company and know if im headed in right direction.

Thanks.

Comments (7)

Sep 11, 2009

I am also curious about this

Sep 11, 2009

or utilities (like renewable energy)... i'd be interested in taht...

Sep 11, 2009

Yes, cash flows are derived from expected production. The first step usually involves having an engineer value the reserves into PDP, PDNP, and PUD categories. You will then use a long-term production driven discounted cash flow model (i.e. production will decline each year because oil/gas are depleting assets unless you continue a successful drilling program). Note that production will decline based on where the assets are located (GOM & Haynesville decline very rapidly).

PDP assets are generally not risked as they are generating cash flow. PDNP is risked about 25% and PUDs are risked about 35%. Basically, you're more likely to get cash out of something that is already flowing versus something that is proven but you still have operational risk and will need to drill to get out of the ground (pretty straight forward).

Free cash flow is the name of the game. EPS and NI are not looked at as closely because E&P companies often have a ton of non cash items that reducing their net earnings. These items include ceiling test writedowns, asset impairments, unrealized hedging losses, exploration and dry hole expenses, etc. You'll want to back into an EBITDAX (X is for exploration) and that's usually where you can start comparing companies.

You'll also want to look at finding and developing costs as well as lifting costs and convert those into a Mcfe ratio, such as 'finding & developing costs are $1.25/Mcfe'. I believe Aubrey McClendon made an announcement at the Barclay's conference yesterday about CHK's F&D costs. If you can get gas out of the ground for $1.25 & sell it for $3.00, then you will make $$. The current issue is that a lot of gas fields are only economic at $4.00 + gas. The Lower the F&D costs per Mcf, the more efficient the Company.

A high valuation will be given to an operator that has low F&D, G&A, and lifting costs compared to its peer. While a Company may not be generating free cash flow after CapEx, back into the EBITDAX and make sure that it looks healthy compared to the size of the firm.

Too much info, sorry.

Sep 14, 2009
ChemicalBank:

Yes, cash flows are derived from expected production. The first step usually involves having an engineer value the reserves into PDP, PDNP, and PUD categories. You will then use a long-term production driven discounted cash flow model (i.e. production will decline each year because oil/gas are depleting assets unless you continue a successful drilling program). Note that production will decline based on where the assets are located (GOM & Haynesville decline very rapidly).

PDP assets are generally not risked as they are generating cash flow. PDNP is risked about 25% and PUDs are risked about 35%. Basically, you're more likely to get cash out of something that is already flowing versus something that is proven but you still have operational risk and will need to drill to get out of the ground (pretty straight forward).

Free cash flow is the name of the game. EPS and NI are not looked at as closely because E&P companies often have a ton of non cash items that reducing their net earnings. These items include ceiling test writedowns, asset impairments, unrealized hedging losses, exploration and dry hole expenses, etc. You'll want to back into an EBITDAX (X is for exploration) and that's usually where you can start comparing companies.

You'll also want to look at finding and developing costs as well as lifting costs and convert those into a Mcfe ratio, such as 'finding & developing costs are $1.25/Mcfe'. I believe Aubrey McClendon made an announcement at the Barclay's conference yesterday about CHK's F&D costs. If you can get gas out of the ground for $1.25 & sell it for $3.00, then you will make $$. The current issue is that a lot of gas fields are only economic at $4.00 + gas. The Lower the F&D costs per Mcf, the more efficient the Company.

A high valuation will be given to an operator that has low F&D, G&A, and lifting costs compared to its peer. While a Company may not be generating free cash flow after CapEx, back into the EBITDAX and make sure that it looks healthy compared to the size of the firm.

Too much info, sorry.

No, thank you, that was what I was looking for. So DCF is the primary valuation method and FCF and EBITDAX are key metrics, but what about Net Asset Value (NAV), as I thought this was also a metric readily used (Price/NAV)? I guess NAV could be used as long as it is used with the others b/c NAV doesn't give a good idea of cash flows?

Anything else you care to add, (no matter how detailed)?

I appreciate the insight.

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Sep 14, 2009

They aren't, especially for companies involved with E&P. Some parts of the energy industry will be similar (like services). Anyways, BIWS publishes multiple guides on O&G - read those.

Sep 14, 2009
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