How to Value Oil & Gas Companies (E&P)
We are all familiar with the three valuation methodologies; discounted cash flows, comparables and ratio analysis, but not all companies in all industries can be valued the same.
Oil and gas companies offer a unique problem of valuation due to their large value based on oil and gas reserves, the same problem is often seen in mining stocks. There is also a large uncertainty in many of the assumptions, such as value and quality of their reserves.
Below are some basic explanations of how E&P, exploration and production, companies are valued;
• Net Asset Value or NAV – This is the major valuation metric used to evaluate oil and gas companies. It is a value, generally shown per share, of the value if the company produced all of its assets for their entire life. The final result of valuing the NAV is the Price/NAV ratio, and can also be used for a PNAV, or present net asset value comparison.
• Cash is King. It is a capital-intensive business with high costs to bring oil and gas production online. P/CF, and P/CFPS are important metrics to analyze.
• Other oil and gas specific metrics includes valuation based of flowing barrel of oil per day (boe/d), EV/BOED, P/E, Net Debt/CF.
• Final considerations for valuation are also given to the management team. Experience is crucial to the success of any company, but the complexity of projects within this sector put big trust on management teams.
Oil and Gas companies are complex to value but offer investment vehicles for growth, dividend payments and long-term safety. The industry is already on an upswing and we will see company valuations grow, so it’s a good time to learn valuations and pick some winners.
What are some stocks and metrics you think are out of whack?
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EV/DACF (debt adjusted cash flow) and EV/Reserves are also metrics commonly used. Also, given the current commodities environment its important to consider the ratio of gas to liquids/oil ratio that a company has.
Lastly, you mention P/E ratio, this would be essentially useless. Earnings don't mean much at all for E&P companies, its all about cash flow.
agreed that P/E ratios are fairly useless, but they are commonly mentioned on equity research reports, mainly for large caps like Suncor and CNQ......
That being said, cash flow is the most important metric.
Lots of companies now that have 40-50% gas are trading at sufficient discounts, but still have solid cash flows to support their dividends from their oil production, two examples in NAL Energy and Bonnavista Energy...
Both of these companies fund their dividends (post-DRIP) with debt. For example, in 2011 Q3 Bonavista made $0.79 in operating cash flows, spent $1.35 in capex and acquisitions, and paid a $0.25 cash dividend per share (net of 30% DRIP). For those of us keeping track - that's $0.81 (or approximately $134MM) in deficit spending, funded through debt in 2011 Q3. Extrapolated over a year, that's $536MM in new debt per year. As at September 30, 2011, Bonavista had only $400MM in credit left on its facilities.
Think that's bad? Bonavista is approximately 60% weighted to natural gas, which it sold for an average of $4.13 in Q3 2011. Gas is currently trading for approximately US$2.50 Henry Hub or C$2.20 AECO. Still feel confident?
I could do the same analysis for NAL - though they're in slightly less shit than Bonavista.
EV/Reserve, EV/BPCD, EV/BPSD, EV/EBITDA
You commonly value based on sum of the parts by assigning values to acreage and to production... you should note that Debt to Production both in oil and gas equivalents is also a great metric to gauge leverage. EV / EBITDAX is commonly used for multiples... other than that it's a decent cursory look at how we value things.
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This is slightly confused.
Net asset value is just the sum of the assets less net debt. To calculate, you need to value each asset - typically on a dcf basis if you can (I.e you know what production and resulting cash flows look like) or on a multiple basis such as $/bbl reserves / risked resources (more relevant for exploration assets). This is the primary method used by ER analysts in the UK for E&P companies (place almost no relevance on standard financial multiples besides maybe CF ones).
EV/resources , EV/production etc used but the issue here is to be meaningful you need to compare companies with similar basins at the same balance in portfolio (Exploration / development / production) and country (fiscal terms vary a lot.... In other words a "comp" has to actually be comparable to be relevant...you'd be surprised at how many people don't get this point!
Disclosure - work in a top tier London o&g IB team
Agreed. Well said
would these metrics be applicable to mining as well? particularly intereseted in any info that OP or others could provide for the mining sector. thanks bros.
Similar.
NAV done using DCF for projects for at least pre-feasibility stage projects In-situ $/oz for explore projects with resources Appraisal value for early stage explore
other stuff is similar
CFPS, P/CF, EV/EBITDA
To clarify even further... NAV gives your value. Comparing to price / PNAV tells you how cheap it is / what's the upside.
The discount is typically lower for companies with either lower risk profile - I.e production / development weighted not exploration weighted OR companies with large exploration portfolio that have demonstrated credibility in delivering value through previous exploration success.
Other factors which can drive a lower P / NAV ratio include political risk - think Kurdistan, funding risk - i.e. How are you going to raise the cash needed to drill and turn barrels into $$s, frontier basins etc. etc
EV / Reserves ratios can be further broken down into EV / 1P Reserves, EV / 2P Reserves and EV / 3P Reserves. This allows you to consider the likelihood of recovering the reserves.
This!!
PV10 is popular for E&P Companies
Are there any free/cheap resources available to better understand Oil & Gas modelling/Vaulation? BIWS has a course but it's like $250...
Don't spend the cash...it's actually quite straight forward once you've got your head around the cash flows...
When I get some more time I might create a new thread on basic O&G modelling if there's enough demand?
Would like to see this
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I'd love to see this.
London - could you (or anyone) talk about type curves and blow-down models. I heard these terms while doing interviews and wanted to hear them explained. And when a bank tells you that they build their own type curves ...what does that mean, what is the process, and do only a handful of banks actually do this? (the guy spoke as if it was a distinguishable characteristic of his bank compared with most)
Sure.
I type curve set the decline characteristics for a well. The whole underlying valuation principle behind valuing an oil and gas producing company is that you are assessing value for both the reserves and the production from their wells. A type curve expresses the decline of a well over time. It has an initial production rate (IP) which will be given typically in Boe/d or Mcfe/d and is the flowing production rate (no need to get into specifics about the variances between 30 day avg, peak rate, 7 day avg, et al), an initial decline percentage, exponential decline percentage, and a hyperbolic decline or "b factor." What this does is allow you to decline the production of the well over time until it reaches the full economic life. Using this approach you can calculate the EUR or Economic Ultimate Recovery.
The biggest issue in oil and gas is how to value assets across various basins / geographies / operator competency, etc. Once you get cash flows you can run a 3 statement model, build LBOs / Acc/Dil etc. Most of the valuation work I do revolves around calculating NAV and then we typically substantiate a premium to current share price based off of the NAV valuation. Most of the time things applying corporate effects and assessing synergies are an after thought because the inherent value is almost exclusively in the asset, especially if you have a proficient operator with management team looking to acquire with no need for retention.
When you hear people talking about a blow-down model or a drill-out model they are talking about this type of comprehensive NAV valuation.
A blow down NAV model is where you only discount the Proved reserves in the DCF. This doesn't give any credit for reserves which the company hasn't booked yet (i.e. which are part of undeveloped land and haven't been delineated - i.e. haven't been assigned reserves through drilling to see what's actually there).
An unrisked NAV is where you also model what the company may potentially have through modeling new wells being drilled (i.e. 2 new wells / section of land) and then assigning production via a type curve and multiply with your price deck (commodity and differentials forecast) to get revenue and then model costs to get a "maximum" NAV for the total company. However, as per my above post, you can't really give full credit to what's there so you risk the unbooked reserves to get a "risked NAV" which is basically what you think the value of the company is.
PV-10 is an industry standard is something that the SEC requires be reported. In terms of discounting various plays this is not exclusively done based on a 10% basis. Some plays are inherently riskier than others and so a higher discount rate will be used. Alternatively some companies, take the Korean National Oil Company, will have a much lower cost of capital because their cost of capital is essentially the cost of debt of the Korean gov't since they are a state-owned entity. Using a lower discount rate would make more sense in that case. Some shops can use a WACC method but it is usually more tied to the assets themselves and you will typically see 10-12% as a range and 7-9% as a range... for Probable and Possible reserves this can be 20-30% depending on the assets being looked at. If the assets are shitty enough (i.e. there are no reported well results and exploratory drilling is about as successful as poking around in the dirt with a shovel) you may see higher discount rates.
My bank builds its own type curves and what that means is that you will hunt through investor presentations, filings, and press releases to compile the relevant initial declines / exponential declines / b factors and you will apply to kick off production on monthly basis for an entire field. After doing this you can run single-well economics based upon the relevant type curve information which is useful for calculating payback years and single well IRRs.
This isn't true and none of the banks I've worked with/at do it this way. Cost of capital is always project specific; it reflects the risk of the project and not the company. A project isn't less risky because XOM or KNOC owns it rather than some ShitCo junior.
Although you could try to determine a discount rate, oil and gas companies are valued using sum-of-parts given that many assets are very different in nature. Thus you'll almost never have a company-wide discount rate (which is why you don't typically use WACC although I've seen my bank use it in some rare cases) since you'd need a specific discount rate for each project given the varying risk. Instead you discount at 10% (usually) and adjust for risk by "risking" a project, i.e. only giving credit for a certain percentage of the PV10.
Lets say we have an oil sands project with a PV-10 of $2 billion but there are uncertainties involved (i.e. regulatory risks, the fact that the project may not be fully delineated, etc.). In other industries this would usually be captured with a higher discount rate but in oil and gas you just risk it by some percentage, lets say 50%, so your value for the project becomes $2bn*0.5=$1.0bn. It seems a bit arbitrary but so is trying to determine project specific discount rates.
Bottom line: you discount at 10% and adjust later with a risking %.
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Oil and gas modelling (Originally Posted: 08/31/2011)
Hi People,
this is my first post here and i'm looking to seek some advice. I am starting out with oil and gas valuation and modelling.
there is basic valuation model online which i found at
http://www.marketoracle.co.uk/Article16413.html
it states:
"As an example, he said to assume that base production in a hypothetical North American oilfield is worth $60,000-$80,000/boepd."
"So if Company X has 500 boepd of production with reserves, the independent report might say it’s worth $35 million (500 x $70,000/boe). "
& later
"That would make the total possible value of the deal worth $167 million ($35 million for base production + $132 million for undeveloped land), or $335,000 per flowing boe ($167M/500 boepd)."
Just a question is the $60 000 - $80 000 total cash worth of oil produced on that day? If so why do you need to multiply it by 500? 500 isn't the no. of reserves ain't it? I'm confused to why to they divide the total worth by 500 to get the boepd all over again.
Anyone care to share or explain this model? Also anyone purchased the oil and gas modelling kit from breaking into wall street? thx alot in advance!
Probably depends on the bank, but my guess would be that they all just train you within the group as mine did. There isn't a specified industry group focus in training if that's what you mean. Some groups might give you additional primers or maybe wall street prep / other modeling training programs to reference that are specific to the industry for things like FIG and O&G, but I'm not sure how common that is. I know in my group they just pass it down.
No, thats the value of 1 boe of daily production.
Multiplying by 500 (daily production) is just to determine the value of daily production based on the assumed value of 70,000/boed (35m)
Dividing by 500 again is to include the potential value of land in the metric. Its just a better practice to gross up the value before recalculating it. Taking 132m/500boed + 70,000boed is basically the same thing (although it looks like the value of the deal was rounded so you won't get the exact same valuation)
hi kalga, thx alot for the reply!
the figure 500 is not an actual number of barrels produced per day but rather a unit am i right to say?
anyone care to give a brief explanation on how do they arrive at the figure of $70 000/boepd for that particular reserve
The example stated the company currently has 500 boepd in production. So if they tell you that in that oilfield the valuation for 1 boepd is $60,000 - $80,000, they are taking the middle of that ($70,000) as an average estimate and multiplying by 500 to give you the total value of the producing oil in that field. They then add the undeveloped assets into account and add $132mm.
The 500 number means they are actually producing 500 barrels of oil equivalent per day, so yes there are actually 500 barrels of oil (or an equivalent mix of oil/gas) coming out of the ground every day.
Again, they arrive at $70,000 by taking the average of $60,000 and $80,000.
Does that help any?
Says it in the article. $70,000 is just the mid-point of a range that Peter's determined in a study of the M&A/A&D market for oil-weighted production over the year (likely in a particular basin/area).
hi ppl thx for the replies again.
i understand the part that 70 000 is the ave of the above 2 values. I am just curious on the model they used to determine that oilfield the valuation for 1 boepd is $60,000 - $80,000.
also it's pretty impossible to have a 500 barrel per day production isn't it? or this is just simply an example so figures do not matter.
Definitely possible, there are many examples of fields with well over 1,000 boepd.
hi westsidewolf, thx for the reply.
i get it now tt there are smaller figures available since i'm always used to huge numbers for boepd.
since i'm gussing it's producing 500 Physical barrels per day from it's oil field.
how do they come to the figure of $60 000 to 80 000 which is how much the oilfield is valued.
anyways anyone has experience with the oil and gas modelling kit from breaking into wall street ?
The $60,000-80,000 is just a basic comps multiple like EV/EBITDA or P/E. but in this case it's EV/production (boe per day), which is an oil and gas industry metric (another one is EV/reserves). You find a set of comparable companies based on size, oil/gas mix, resource play, geographic location, etc. and use the average EV/production (usually forward estimates).
hi ppl thx for the replies again.
catscradle: i see, basically the figure of 60 000 to 70 000 is just a company analysis ratio. a question, what is the main difference between "EV/production (boe per day)" and "per flowing barrel" which is also used to assess or value oil companies.
westsidewolf: thx for the info i did a search and actually found ave production as low as 158 boepd!
Hayst, it's exactly the same thing. EV/production is often called the "flowing barrel metric" or "per flowing barrel". All the ratio means is how much value is being ascribed to one barrel of production per day.
ahh icic. thx so much for all tt info! answered my questions!
common multiples used in oil and gas / mining industry (Originally Posted: 09/21/2011)
? For valuation
I'm wondering if someone here could suggest some books that a guy could read in order to become more familiar with valuations/analysis of O&G companies. Currently working as an Engineer in the industry so I'm quite familiar with the ins and outs and the jargon however I don't have any formal training in finance.
EV / Production EV / Proved Reserves EV / Proved + Probable Reserves Price / Net Asset Value
and
EV / EBITDA (called EV / DACF in Canada) Price / Cash Flow (Operating)
EV/EBITDAX
Yeah I forgot, you use EBITDAX in the US to normalize different accounting treatments for exploration expenses. Canadian firms all have the same treatment so you use EBITDA.
Also would add we use Discretionary Cash Flow (DsCF) per share quite a bit in upstream. Particularly when valuing producing assets.
Wow very solid and comprehensive!
agree with Stringer and others... EBITDAX is important because of treatment of exploration exp is different accross frims, but Cash flow (discretionary) per share is quite common in upstream.
I can add a few that we look at heavily in the upstream E&P space:
Trading Metrics:
EV / 3P Reserves (a way to see how much value is driven from upside due to possible reserves) EV + Development Costs / Reserves EV / Daily Production EV / Pre-tax PV-10 EV / Post-tax PV-10
Credit metrics:
Debt / EBITDAX EBITDAX / Interest Exp. Debt / Cap Debt / Reserves Debt / PD Reservs Debt / Production
We are also really concerned with R / P (reserve replacement) on a total and proved developed basis. It gives you the ability of a firm to replace the reserves it is producing from... If you have high production volume, but aren't having success in the exploration portion of your business, you have a problem because your firm will drill out all its reserves
One other should be worth noting. Sometimes, dependent on client, we'll use EBITDE in lieu of EBITDAX which is essentialy the same metric, but is better for small cap exploration companies as the overwhelming majorty of the firms operations are connected to building out their exsisting assets and new acquisitions of new ones. For istance (not small cap) but BBG doesn't disclose dry hole expense which they roll up in amortization.
CapIQ doesn't have an EBITDAX data point and their exploration expense is lumped together with "exploration/drilling expense" Can I include drilling with the exploration add back?
No. Drilling and completion costs (D&C) are capex -> post-EBITDA.
Catalysts & Drivers for O&G (Originally Posted: 04/02/2013)
I'm trying to prep for an interview, and can't quite decide what to say if they ask me for the catalysts, macro events and profit drivers behind the industry. Maybe its just that oil's such a huge market and a good benchmark for the economy, I can pretty much go anywhere with this. But I want to nail the interview...so what kind of things are they looking for? I'm interviewing for energy in general, but 90% certain they're looking to match me up with the oilfield services analyst.
I figured I'd touch on things like - global supply/demand: political stability, economic health, natural disasters, speculators - micro level: utilization rates, input costs, market capacity, legislation, oil vs gas vs ngl prices, crack spreads, technology/R&D, producers budgets (effect on the services revenues)
Oil 101 - Book Deutsche Bank and Credit Suisse Oil Primers (PDFs found floating on the net)
I'm by no means a professional in this space but some things I have considered focus around regulation such as oil drilling regulatory environment, pipeline issues, importance of being energy independent, etc. Important to think globally for oil demand and keep China in the picture.
Also, related to nat gas I have been doing lots of research into alternative uses for nat gas as prices are so low. Safe and effective transportation or the conversion of it into gasoline which apparently some companies have been experimenting with.
Probably want to hit on Baker Hughes and Smith rig count numbers.
Hm good call. I was thinking land sales also, as I'll be focusing on ground extraction.
Land sales could be good. Definitely want to know the shale plays, the biggest players in the Perm. Bakken etc.
One thing that might set you apart is understanding the broader O&G market logistics. The reasons for the WTI-Brent spread and the WCS-WTI spread. Once pipelines start clearing Cushing market, and other pipelines are reversed from the Permian, you'll see crude flowing more from the inland market. This results in better netbacks for producers and more outbound capacity. This might spur on more activitiy which would then impact oilfield services...
I'm actually currently reading Oil 101. I found the DB primer on scribd but I couldn't find a PDF. Anyone have a link?
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