- 1 Exploration and Production Industry Primer
- 2 Valuation of Exploration and Production Companies
- 2.1 Valuation Drivers
- 2.2 Calculating Net Asset Value
- 2.2.1 Differences Between NAV and a Normal DCF
- 2.2.2 Oil & Gas NAV Line-by-Line Walkthrough – After-Tax Net Revenue
- 2.2.3 Oil & Gas NAV Line-by-Line Walkthrough – Capital Expenditures
- 2.2.4 Oil & Gas NAV Line-by-Line Walkthrough – Free Cash Flow and Asset Value of Producing Assets
- 2.2.5 Oil & Gas NAV Line-by-Line Walkthrough – Life of Project and Decline
- 2.2.6 Oil & Gas NAV Line-by-Line Walkthrough – Non-Producing Assets
- 2.2.7 Oil & Gas NAV Line-by-Line Walkthrough – Value of Undeveloped Land
- 2.2.8 Oil & Gas NAV Line-by-Line Walkthrough – Corporate Adjustments (Debt/ARO/Pension/Hedgebook/Cash)
- 2.2.9 Oil & Gas NAV Line-by-Line Walkthrough – Unbooked Locations
- 2.3 NPV at a glance – Looking at Well Economics
- 3 Exploration and Production Operating Metrics, Ratios and Terms
- 4 Exploration and Production Credit
- 5 Related Reading for Energy
Exploration and Production Industry Primer
From Wellhead to Point-of-Sale
Exploration and production companies make money by selling the oil they produce to the market.
Revenue = Realized Sale Price x Barrels Sold
Each barrel of oil they produce is sold at a market price, which based on the characteristics of the oil sold will determine the differential in pricing between the barrel sold and a relevant benchmark (for instance, if the barrel of oil has more favorable characteristics such as being a lighter oil in an area with light refineries, it may trade at a premium to the benchmark).
However, to get the oil to a point of sale, it needs to be extracted and transported. The extraction process varies greatly from company to company, and can be relatively high for some of the more difficult geologies in Canada. These operating costs are the marginal cost to get a barrel out of the ground and do not include the capital expenditures getting the infrastructure in place for extraction purposes (more on that later).
To get the oil from the extraction point to where it can be sold, the oil must be transported to a regional pipeline where it is shipped to the purchaser. Of course, the oil can be sold anywhere in between, but the earlier the risk is moved to the buyer, the larger the discount to the price that would have been realized at the end point. As such, transportation costs will include the cost of trucking or moving the oil through a regional pipeline to the national pipeline and from there to the purchaser.
In terms of transportation costs, the oil company may have contracted with the shipper to have a take-or-pay agreement (you will pay for x amount of capacity regardless of whether you use it), fee based agreement, or cost of service agreement. In the US, you will see a larger percentage of more esoteric (and riskier) contracts including percentage of proceeds (where there is commodity price risk) and make wholes (where there is commodity price risk in terms of the spread between natural gas and the NGLs).
On the oil itself, the government will take its pound of flesh through royalties, which will usually be a function of some average sale price. The government would like to encourage development and industry, so these royalty fees will ratchet up or down based on the underlying price of oil.
Sale Price – Royalties – Operating Costs – Transportation Costs = Operating Netback
Operating Netback – Hedges – General & Administrative – Interest – Other = Corporate Netback
A good estimate for operating profit, accordingly, is the operating netback multiplied by the production (net price x volume). Production is usually quoted in terms of barrels of oil per day, so you can multiply that by the number of days in the year to get the annual production, before multiplying with netback to get an approximation of EBITDA.
However, E&P companies cannot be modeled out using this EBITDA + a growth rate like a “normal company”. Analysts are aware that E&P companies produce a non-renewable resource, and as such their “inventory” or reserve base is finite.
Accordingly, it is very important for oil and gas companies to be replenishing reserves as quickly as (and preferably faster than) they are depleting them, which we will discuss in a separate section.
So how can companies bolster reserves? One way is through acquisition, and it has been the perception for some E&Ps with stronger balance sheets that the cheapest way to gain reserves on a per barrel basis is to acquire, especially when some overlevered companies have their hands tied and are being pressured by creditors to sell assets to extinguish debt.
Oil & Gas Exploration
Oil and gas companies must continuously explore for new reserves. For Canadian producers operating in Alberta, the Crown (Provincial government) has land sales, where oil producers will bid on the land based on the perceived quality of the geography. Discovering a quality reservoir close to where new auctions will take place will bump up the price per acre.
The exploration process itself is fairly straightforward, although the amount of data considered before exploring a certain area varies greatly (from extrapolating close to brownfield sites where there is already known oil produced in quality reservoirs to wildcatting – drilling in areas where oil is not known to exist a la Aubrey McClendon and Chesapeake Energy).
Oil and gas companies will gather data (or have data provided for them by third parties) via methods including making assumptions based on surrounding known oil fields, seismic assessments (using artificially induced shockwaves – think earthquakes – to generate imagery via vibrations) and satellite imaging.
From there, a decision is made whether to acquire rights to the land where they perceive oil to be. Depending on the jurisdiction, land can be purchased or leased. For some royalty companies who own the land and lease it out, they may provide seismic and production data for the field to assist in the land acquisition decision.
Once the land is acquired, further seismic activity may be conducted – generally more advanced 3D/4D seismic where the explorer will bring in an oilfield services company such as Schlumberger.
If the presence of oil is probable based on the data, the oil company will drill an exploration well. If there is actually no oil, this is a dry hole and it is plugged and everything is just expensed.
If the well is successful, appraisal wells are drilled (drilled close together to have a better gauge of the total volume) to see whether the oil field is commercially feasible.
Valuation of Exploration and Production Companies
This ratio (where price is market capitalization or the share price is divided by NAV per share) compares the market equity value is versus the net asset value. The net asset value that is referenced can be your core NAV, risked NAV or unrisked NAV. If the multiple is high, the stock is expensive. An analyst would have to justify this with a view with other factors (for instance, that resources on the land that the company owns has upside potential, the management is successful at finding new reserves).
Enterprise Value/Reserves (barrel of oil equivalent/boe)
The denominator is often proven & probable (2P) reserves or 2P reserve + contingent resource. The multiple must consider the quality of reserve (a reserve implies the barrel of oil equivalent is economical, however barrels can certainly be more economical than others – this consideration will include whether it is a gassy or oily asset).
DACF is debt-adjusted cash flow and calculated as CFO + after-tax financing costs + before-tax exploration expense +/- change in net working capital – taxation is very relevant based on jurisdiction and affects corporate finance decisions, so the idea is that this metric is after-tax but removes the effects of leverage.
Enterprise Value/EBITDAX or EV/(EBIDA + Deferred Taxes)
EBITDAX is EBITDA plus exploration expense to eliminate the distortions of costs relating to finding new reserves.
Price/Cash Flow (P/CF)
Recurring theme is that oil and gas investors tend to look at cash flow (discussed in valuation).
Usually for larger E&Ps and integrated names.
Justification for the above multiples factors in various operating drivers that speak to the quality of the company, including:
The Long-Term Oil Price Forecast
All banks’ equity research teams come up with their price decks for valuation, which they will apply to all the companies in their valuation universe. Depending on where the company’s cost structure is, a different long-term oil price means different things for different companies.
Return on Capital Employed (ROCE)
Return on capital employed is a good indication of how efficiently debt and equity invested into the company is generating a return. As this is independent of the effects of leverage, a continuously good ROCE demonstrates sound operating performance. A track record of executing strong IRR projects on time and on budget usually will lead to high ROCE.
Reserve Replacement Ratios and Finding, Development & Acquisition Costs (FD&A Costs)
Oil is a finite resource, so exploration & development companies can command a premium multiple when depleted reserves are replenished via technological advances or reservoir expansion.
Finding costs are exploration costs – money that is spent on figuring out if oil is in the ground. Development costs are capital expenditures required to extract the oil. Acquisition costs are the costs of oil & gas assets from another party.
As a standalone, FD&A costs per barrel can be misleading or incomplete when it comes to analysing a company – this is because in this instance, a barrel that yields $1 of profit versus a barrel that yields $12 of profit is still counted as a barrel. Oil and gas basins differ widely and the economics of oil-plays and gas-plays themselves vary.
This is addressed via the reserve replacement ratio – which divides the average cash netback per barrel of oil equivalent over the average FD&A cost per barrel of oil equivalent. This tells an analyst that the proceeds from production are able to yield x amount of barrels of future production. A ratio well above one is desired.
There are several reserve replacement/recycle ratios that are evaluated to isolate trends in method as well as to address for the vagaries of a cyclical industry. For instance, acquisition costs and barrels from acquisitions may be stripped out from F&D costs to isolate the company’s success as an explorer and operator. Also, FD&A costs may be evaluated on a 3-year or 5-year average to account for fluctuation in oil prices (and accordingly cash netbacks) as labor and capital costs tend to be more sticky.
Reserve ratios are also done on a proved (P1), probable (P2) and possible (P3) basis. As lower quality reserves are included, the ratio will go up. Of course, a track record in converting P2 to P1 and P3 to P2 is also desirable.
Production Profile and Hydrocarbon Mix
Although oil is sold relative to a standardized benchmark, the production yield of each operating segment of each producer can be very different. Oil, natural gas liquids and gas all trade at different prices – so the benchmark will differ. The actual realized price for each of these commodities will also differ due to infrastructure constraints or regional supply-demand characteristics. Finally, depending on reservoir complexity and corporate know-how the extraction costs can also vary.
The first thing to look at is the gas-oil mix – generally, liquids producers trade at a premium to gas producers, although certain gas plays have extremely high IRRs and that can translate into share price.
What basins a company operates in can result in different multiples being assigned due to the relative economics of each play.
Calculating Net Asset Value
When looking at an E&P company or the E&P segment of an integrated oil company, the appropriate intrinsic valuation method to use is Net Asset Value (NAV). The idea is that you are first valuing the hydrocarbon resource only, and independent of how the company is operated as a corporate. Afterwards, you tack on corporate specific effects.
Differences Between NAV and a Normal DCF
First, you find the value of the hydrocarbon resource. This approach evaluates discounted cash flows, but differs from the standard DCF because:
- the business does not continue into perpetuity, as the resources are finite (you are assuming no new discoveries, so you do not include finding and development costs either);
- an industry standard discount rate of 9 or 10% (you will commonly see analysts discuss PV-9 or PV-10) do not use WACC or kE as a discount rate (there will also be valuations with other discount rates shown alongside the main valuation for comparability purposes; an investor looking for a larger margin of safety may want to see asset value given a much higher discount rate), again because we are looking at an asset independent of capital structure;
- you initially ignore corporate expenses and actions such as selling, general and administration (SG&A) again because you are looking from an asset level independent of how well a corporate is run.
Oil & Gas NAV Line-by-Line Walkthrough – After-Tax Net Revenue
The after-tax net revenue from oil production considers the production (volume) and the realized sale price net of expenses (when looking at historical data, netbacks are based on volumes sold, which may differ slightly from volumes produced – for modelling purposes sales should equal production when forecasting the future). The easiest way to get to this after-tax net revenue figure is via an operating netback. The operating netback is multiplied by the production to get to after-tax net revenue.
Realized Sale Price
The realized sale price will be based on an assumed differential to an assumed benchmark price, for instance an oil producer in Australia could have their realized sale price at a discount to Tapis Light. For an oil sands producer, the realized sale price may be a discount to an already discounted benchmark (for example: Christina Dilbit Blend (CDB) trading at a discount to Western Canadian Select (WCS) trading at a discount to West Texas Intermediate (WTI)).
Royalties the primary government or landholder tax on resources (oil and gas companies still have to pay standard income taxes on top of this). Depending on where the oil is produced, royalties can vary greatly. Generally, royalties will be a % of net revenue or gross profit which will ramp up depending on a prevailing benchmark oil price.
The realized sale price less royalties is the net realized sale price.
Transportation & Storage
To get to the point of sale, oil has to travel via some medium, be it pipelines, railcar, barge or truck. If the oil and gas company has a vertically integrated supply chain (it owns midstream/pipeline assets like BP or Shell), the cost of transportation and storage is much lower. If the company has egress issues (bottlenecks in getting the oil to where it can be sold), the cost of transportation is higher.
Heavier oils will need to be blended with a diluent (dilution agent, usually light hydrocarbons/condensate) before it can be transported via pipeline, so there may be a blending cost which will depend on a blending ratio (how much diluent is needed for the oil – the heavier the oil the more diluent required). If the cost of condensate goes up, the transportation cost will go up.
Operating Costs – Energy and Non-Energy
Operating costs have a large energy component which is often separated from the broader operating cost line (electricity needed to run machinery and gas used to generate heat). Depending on what fuel source the oil company uses (usually natural gas which may sometimes be produced in the same area or associated gas that comes out with the oil), energy costs will be influenced by the current price of natural gas.
Improving technologies that reduce the need for heat and otherwise make energy use more efficient as the company moves along the learning curve will push this down. Also keep in mind that for scalable projects (huge projects with hundreds of thousands of barrels of oil production a day), there are economies of scale and these will go down on a per-barrel basis. Otherwise, operating costs include labor, workover costs, waste handling etc.
After subtracting the above costs from net revenue, we have the pre-tax netback figure.
Oil & Gas NAV Line-by-Line Walkthrough – Capital Expenditures
Capital expenditures can be split into growth capex and maintenance/sustaining capex.
Growth capex includes the drilling of new wells, engineering and design for a project that will come on, laying out infrastructure etc. For some massive field projects that produce over half a million barrels per day, there is a long lead time and billions of dollars that need to be spent before the project achieves first oil.
Maintenance capex is for sustaining current production levels – this may include stratigraphic test wells for wellpad placement, asset turnarounds (maintenance), debottlenecking/improving efficiency, asset replacement.
Capex can be modeled in several ways.
One way is to look at the stated capital intensity/capital efficiency of new production, which is the capex figure per flowing barrel of production going forward (company will offer guidance, but an equity research analyst may put conservative assumptions based on the capital intensities of geographically close projects).
For conventional oil and gas, production tends to trail off each year (decline curve) so assuming that production is growing, capex can be solved via (capex per barrel x [new production – existing production – decline rate*existing production]).
Another way is to use the capex provided in the type curves or using the net figure multiplied by the number of wells.
Oil & Gas NAV Line-by-Line Walkthrough – Free Cash Flow and Asset Value of Producing Assets
As tax is cash based versus accounting based, the timing of capital investment/capex spending will influence actual cash taxes. After subtracting cash taxes from the pre-tax net revenues, we have an after-tax net revenue figure. After-tax net revenue – capital expenditures is the free cash flow. The free cash flow is discounted at an appropriate discount rate to get the value of producing assets.
Oil & Gas NAV Line-by-Line Walkthrough – Life of Project and Decline
As oil and gas involves a finite resource, we cannot assume that the FCF goes on forever. Each year will have a production figure (which may or may not be growing at present – see growth capex – but will eventually decline) which is subtracted from the 2P reserves. When the assets are depleted, the asset does not produce cash flow and will need to be decommissioned (see asset retirement obligation below).
Oil & Gas NAV Line-by-Line Walkthrough – Non-Producing Assets
Oil and gas producers will have sanctioned projects that are not yet producing. Getting to the asset value for these is the same as that of producing assets or soon to be producing assets – when the asset starts producing, FCF is generated from after-tax net revenues less capex and discounted back. As these projects may produce 5-years later or so, the discount may be substantial.
The difference is that there is execution risk because the project is much further from first oil. Depending on what stage of development these projects are in (initial engineering, regulatory approval, sanction), a haircut must be applied to the NPV of these projects to take into account uncertainty (project could be delayed, cancelled, have an unforeseen liability).
As an example, an oil and gas company may have project A, B and C. The projects have NPVs of $100, $200 and $300 respectively. Collectively, they have a risked NAV of $600.
However, they are also assigned respective haircuts of 50%, 25% and 75%. As such the risk-adjusted or unrisked NAV of $50 + $150 + $75 or $275.
Oil & Gas NAV Line-by-Line Walkthrough – Value of Undeveloped Land
Oil and gas companies will have land or leaseholdings that may not have planned projects – alternatively, analysts may consider some projects to be so uncertain or far in the future that they do not care about anything other than land value. Land value is ascertained from acres of land multiplied by a $/acre based on comparable landholdings and previous sales.
Oil & Gas NAV Line-by-Line Walkthrough – Corporate Adjustments (Debt/ARO/Pension/Hedgebook/Cash)
After getting to the asset value, claims by other stakeholders must be subtracted to get to the net asset value to equityholders.
First, debt must be subtracted from the assets. Large cap E&P companies will have US$ debt as a part of their capital structure.
Second, the asset retirement obligation (ARO) must be subtracted. When the decision is made to shutter oil wells at the end of their productive life (which is an economic decision where the costs of production are higher than the marginal benefit), the well must be plugged and decommissioned in an environmentally friendly way so that it can be used for other purposes.
For large oil projects, this can be substantial and oil and gas companies try to kick it back as much as they can. The present value of the ARO is treated as debt for the NAV calculation. This is one big payment far in the future, so to reflect the eventual cost of the obligation, oil and gas companies must recognize an interest cost (or accretion on ARO/decommissioning liability) every year, which is basically an unwinding of the discounted ARO by an appropriate interest rate.
To make sure that oil and gas companies cannot just cut and run from their obligations, they may have to put up letters of credit from banks in order to guarantee payment if they are not creditworthy enough.
Third, add the value of the hedge book (an oil company with US$90+/bbl hedges locked in for a sizable portion of production is going to see a valuation boost).
Fourth, subtract the present value of corporate costs (general & administrative) for the running of the company (as investors own the company, not just the assets).
Fifth, add or subtract any other adjustments that would affect value to the owner of the company (cash, investments, corporate liabilities, etc.).
Oil & Gas NAV Line-by-Line Walkthrough – Unbooked Locations
For a pure upside scenario and not really factored into the base valuation, the development potential of current assets can also be valued.
Unbooked locations are multipled by an expected recovery per well and then given a haircut for asset risk and development risk. Asset risk or geological risk is related to how well the company understands the geology and how precise it can forecast production. This risk is lessened when the asset is in a geography known to have good reservoir characteristics and a proven method of extraction.
Development risk is related to realising economic value. For instance, whether or not it will clear required hurdles for stakeholders and at what price (a factor that is very much out of the control of producers – possible deviation from expectation in the gas/oil mix that the project yields, and if the yield is expected, inability to hedge cheaply beyond one year), as well as what kind of infrastructure is in the region. Political and social risks may also factor into the project evaluation (especially given recent environmentalist sentiment for Keystone XL and various Bakken projects).
An analyst may also assign value to optimistic scenarios in bluesky NAV valuation (where the asset is completely derisked). For credit, purposes, these will all be ignored as you will only count assets which gives you certainty of cashflow and debt service.
NPV at a glance – Looking at Well Economics
For an entry level position in oil and gas, it is not expected for you to know well economics to such granular detail (and it can certainly get into even more granular detail), so this is meant as an information source rather than a cheat sheet.
To look at whether wells are economic or not, the entity that undertakes a project should look at whether it clears internal hurdles. Wells are an extremely basic example of NPV in action. A company will set a certain hurdle rate and then look at the well’s internal rate of return, or IRR.
The hurdle, or required return, will be a function of risk. The riskier the project, the higher the return required to satisfy investors. This risk will be based on country risk (in Venezuela, where the risk of expropriation is high, vs Australia, a developed market with strong legal frameworks that are unlikely to be violated, the required return on capital will be much higher), operating risk (difficulties in getting the oil out of the ground), operating leverage risk (as the price you receive is at the mercy of the markets, with some help from hedging but less so for very long-term projects, a change in supply-demand equilibria could cause your project to become uneconomic even at a variable cost level), and a variety of other factors.
Now that there is an appropriate discount rate, the cash flows generated by the well are to be discounted. A well has a finite resource of oil, of which not all the oil can be recovered, so there is a cap on how much economic value each well can generate. The netback generated from each barrel of oil multiplied by the output gives the revenue. From there, you will need to subtract the costs of extraction and the capital expenditures of getting the well operating and maintaining operations.
The production profile of a well is also non-linear, so you will expect a different initial production (IP) rate from when the well normalizes and declines. The decline curve and other technical aspects require specialized knowledge, which is why acquisition and divestiture teams prefer to hire petroleum engineers and focus on asset sales instead of corporate sales.
For wells, internal rates of return will usually be quoted based on assumed 12 month NYMEX strip pricing for WTI, which is the average of the daily settlement prices for the next 12 months’ WTI futures. This serves as an acceptable proxy, as theoretically the company could just hedge out a substantial portion of their production and guarantee such pricing.
For shale, production profiles are transparent and geological knowledge has advanced to the point where you have a very good idea of what your production will look like (as opposed to conventional techniques in the past with large fears of dry wells). This makes for a much more pragmatic business model where you can act opportunistically based on the price of oil, lowering risk substantially, and accordingly lowering hurdles.
Exploration and Production Operating Metrics, Ratios and Terms
Important Numbers for Oil and Gas
A characteristic used to differentiate crude benchmarks is a measurement of the density of oil (As defined by the American Petroleum Institute, or API) versus water. The lower the API, the thicker the oil – Western Canadian Select has an API gravity of 20.5 degrees while raw bitumen is denser than peanut butter and can be below 10 degrees. The global benchmark light crudes, WTI and Brent, are 39.6 and 38 degrees, respectively – oil tends to receive the highest price in the 40 – 45 degree range.
Oil producers will discuss oil as “sweet” or “sour”. Any oil with over 0.5% sulfur content is considered “sour” – sulfur is an impurity that needs to be taken out before crude can be optimally refined. The differential between sour and sweet crude will be the cost of treating the sulfur – the sulfur byproduct can be used as a commodity, especially in the form of sulfuric acid. The global benchmarks, WTI and Brent are sweet crudes while WCS is sour.
Reserve Life Index (RLI)
Reserves/Production. A large number here means that there is less pressure to find new reserves.
Exploration and Production Credit
Oil and gas credit has garnered much more attention since the OPEC meeting and the bankruptcy of numerous high yield issuers in the energy space. Many companies continue to be cash flow negative at $50 oil and have resulted in ancillary business hungry lenders taking provisions for loan losses and bondholders seeing their securities fall to pennies on the dollar.
In evaluating the quality of E&P companies, an astute analyst must be cognisant of initiatives and quality of basins that are less obvious immediately from a cursory look at the financial statements. In company provided literature such as the management discussion and analysis (MD&A), there should be a screen on initiatives such as optimizing well spacing and other engineering ratios and resulting cost trends (is it falling per well or rising, while production stays the same or goes higher?). Understanding reservoirs and terms such as stacked pay are desirable.
Average Daily Production
the larger your barrel of oil equivalent per day (boe/d) is important as it gives perspective on the company’s scale. The production per day leads into cash flow for debt service, so it is an extremely pertinent metric, especially when combined with the hydrocarbon mix (gas vs. oil).
From a credit perspective, the size of proven developed reserves are key, as it is the most precise indicator of the production volume that you will actualize from the company’s assets. Proved undeveloped reserves (PUD) cannot be a good proxy from a credit perspective as there is a large future development cost component that is subject to variability and uncertainty.
However, the total proved reserve base should also be considered as that is a floor for liquidation value (cost per acre or NPV).
Leveraged Full Cycle Ratio
As E&P companies are dealing with a finite resource, it is important to see if they are recovering their reserves, but also to see how profitable they are in bringing a barrel of oil to market considering all of the exploration and development costs (F&D) as well as the marginal cost of extraction. The ideal company has netback per barrel high enough to satisfy costs from soup-to-nuts many times over.
This ratio gives perspective on debt service (although the contribution margin from the hydrocarbon needs to be considered as well). If the company is integrated, only the E&P allocation of debt should be considered from a capital structure perspective (other operations and projects may allow for more or less debt based on cash flow volatility).
Debt/PDP, Debt/P1, Debt/P2: from a strict debt service perspective (not liquidiation) it should be Debt/PDP as this is the asset that can reliably meet interest and principal obligations.
The netback per barrel of oil equivalent ties all of the previous ratios together as it gives value to each reserve barrel of oil equivalent. If the reserve base is small but the realized price is high, the oil company is in a much better position to deal with an oil shock than if it were the other way around due to operating leverage.
The gas/liquids or gas/oil mix is very important as you should be able to then evaluate the economics of the gas production and oil production separately. Currently, oily assets are preferred due to gas prices continuing to be depressed beyond its energy equivalent cost (6 units of natural gas in thousand cubic feet or mcf equals one barrel of oil, but gas is much cheaper due to its oversupply, lack of penetration as a transport fuel and difficulty in shipping across oceans), but this is not to say that it should not be looked at from a case to case standpoint.
Production growth is also very important as it means that assets are being better unlocked and derisked, directly flowing into revenue growth. Being able to replace reserves at a cheap price is also important from a full cycle perspective, because it means that going soup-to-nuts and finding, developing and producing from a well yields an acceptable return on your capital.
Drilling and completion costs (D&C costs) are a substantial part of the total cost of the well, and you will want to see declining curve as rigs are optimized and drilling more oil per well. If the D&C costs per well are declining and D&C costs are declining per barrel of production are declining, that means that there are economies of scale and they are an efficient company.
The quality of the acreage is tremendously important as the geology will tell you which E&Ps have the best asset to work with in any given price environment. If there are nearby fields owned by other E&Ps that have similar geology and are yielding very good economics, you can expect there to be similar output for the E&P you are evaluating.
Midstream assets owned (gathering and processing, splitters etc.) that are owned by an E&P where there are other E&Ps operating can be a substantial plus to valuation (as you can expect the characteristics of their production will be similar). As these are non-core, they are generally the first to be sold off when financial distress looms. These assets should be separated for the purposes of valuation as they have more stable cash flows independent of the oil price (depending on contract profile – is it take or pay, fee based, cost of service, percentage of proceeds – and whether it is the only asset servicing the area – read more about this in our energy infrastructure section).
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