EV/DACF vs NAV: How to Value Oil & Gas E&P Companies

One Method Values the Barrels, the Other Prices This Year’s Cash

Reserve-based NAV asks what the reserve base is worth under a stated price and discount rate. EV/DACF asks what the market is currently paying for a year of cash generation. They are not rival answers to one question, and the most useful thing either produces is the gap between them.

The trap sits in the multiple. A producer on 3x looks cheaper than one on 6x, and often it is not: it is a producer whose cash flow runs out sooner. That relationship is the point of this guide, and it is the one thing you can work out from arithmetic rather than opinion.

NAV needs a production forecast, so decline curve analysis sits upstream of any reserve-based model. This guide walks through both methods, shows why reserve life caps the multiple, and covers when each is the right tool.

Reserve-Based NAV: Valuing the Resource

NAV Formula and Components

Reserve-based NAV is the present value of everything the proved reserves will earn, less what it costs to run the company, less what it owes:

NAV = Σ PV(Annual Cash Flow from Reserves) − PV(Corporate Costs) − Net Debt

The annual line, per year of the production schedule:

Annual Cash Flow = [Realised Price − Production Costs − Royalties − Development Capital] × Production, less tax

Those flows are then discounted. Ten per cent is the working convention, inherited from the SEC’s fixed 10% for the standardised measure, and it is applied here to after-tax cash flows.

The Assumptions That Do the Work

Prices. Our worked examples run the Selborne planning deck: WTI $70/bbl and Henry Hub $3.00/MMBtu. Any long-term deck is a judgement, not a forecast, and analysts differ. What matters is that a NAV is only as meaningful as the deck named beside it.

Production costs (lifting). Roughly $12-20/BOE for onshore unconventional, $8-15/BOE for conventional onshore, $10-20/BOE offshore. These cover operating expense, workovers and lease costs.

Royalties. A royalty is taken in barrels, not money: a 20% royalty means the company books and sells 80 of every 100 barrels produced. US onshore leases commonly run 12.5-25%; federal offshore leases sit at 12.5-18.75%. International fiscal regimes take considerably more, often through production-sharing splits rather than a flat royalty.

Tax is separate, and comes off the money rather than the volume. A blended 25% US effective rate is our default. Stacking a tax rate on top of a royalty rate and deducting the sum is a common and expensive mistake.

Development capital. $4-9/BOE across most basins, covering the wells needed to bring undeveloped reserves online and keep the producing base running. F&D cost benchmarks has the basin detail.

Discount rate. 10% by convention; 8% for lower-risk long-life assets, 12% where the jurisdiction or the balance sheet demands it. The spread between those two is wide enough to matter more than most operational disagreements, as the sensitivity table below shows.

Worked NAV Example

Company A: mid-cap E&P, Permian and Gulf of Mexico assets, 250 million shares, $1.8bn net debt.

Reserves and production

• Proved reserves: 400 MMBOE (250 developed, 150 undeveloped)
• Year 1 production: 45 MMBOE, so a reserve life of 400 / 45 = 8.9 years
• Years 2-5: 40 MMBOE a year; Years 6-10: 35 MMBOE a year
• Total produced over ten years: 45 + (4 × 40) + (5 × 35) = 380 MMBOE, a little under the booked reserves

Realised price. Production is 90% liquids and 10% gas. Gas converts to BOE at six thousand cubic feet to the barrel, an energy equivalence rather than a value one, so those six MMBtu fetch about $18 at a $3.00 gas price against the barrel’s $70:

Blended realisation = (0.9 × $70) + (0.1 × $18) = $65/BOE

Year 1 cash flow

Revenue:              45 MMBOE × $65      = $2,925M
Production costs:     45 MMBOE × $16      =   $720M
Royalties:            12.5% × $2,925M     =   $366M
Pre-tax operating CF: 2,925 − 720 − 366   = $1,839M

Development capital:  45 MMBOE × $5       =   $225M
                                            $1,614M

Tax: 25% × ($1,839M − $300M DD&A)         =   $385M
After-tax cash flow:  1,614 − 385         = $1,229M

That is $27.3 per barrel of after-tax, after-capital cash flow, and carrying that margin across the ten-year schedule gives:

PV of the production stream (10%)          =  $6,513M
Less corporate G&A, discounted             =    $400M
Enterprise NAV                             =  $6,113M
Less net debt                              =  $1,800M
Equity NAV                                 =  $4,313M

NAV per share = $4,313M / 250M shares      =   $17.25

The Sensitivity Table Is the Real Output

NAV per share at a range of oil prices and discount rates, holding everything else in the example fixed:

WTI	8% discount	10% discount	12% discount
$60/bbl	$13.4	$11.6	$10.1
$70/bbl	$19.6	$17.3	$15.3
$80/bbl	$25.7	$22.9	$20.5
$90/bbl	$31.8	$28.5	$25.7

The $70 and 10% cell is $17.3, matching the worked example. Read across and down instead: the same reserves, the same wells, the same costs, and a value between $10 and $32 a share. That is a factor of three, and none of it comes from the assets.

This is why comparing two brokers’ NAVs on the same company is mostly comparing their price decks and their discount rates. Before arguing with someone’s NAV, find out what deck it runs and what rate it discounts at, because the answer usually settles the argument without anyone discussing the geology. On this ten-year profile, $10/bbl on the oil price moves NAV by about $5.60 a share and 100 basis points of discount rate moves it by about 6%. A longer-lived asset is more sensitive to the discount rate, because more of its value sits in distant years.

EV/DACF: The Cash Flow Multiple

What DACF Actually Is

Debt-adjusted cash flow strips capital structure out of the numerator, so a heavily borrowed producer and a debt-free one can be compared directly:

DACF = Operating cash flow before working capital movements + Financing costs, added back after tax

The after-tax part is not a technicality. Interest is deductible, so a company paying $150m of interest at a 25% tax rate is really out of pocket $113m. Add back the $113m and you have the cash the assets threw off before anyone decided how to finance them, which is what the enterprise value on the other side of the ratio is measuring. Add back the gross $150m and you have double-counted the tax shield.

Some analysts also add back exploration expense, because companies using successful-efforts accounting run failed wells through the income statement while full-cost companies capitalise them. DACF is not free cash flow: it sits before capital expenditure, which matters a great deal in a business that has to keep drilling to stand still.

Worked EV/DACF Example

Same Company A. Its cash flow before development capital is the $27.3/BOE margin plus the $5/BOE it spent, so $32.3/BOE.

Operating CF: 45 MMBOE × $32.3            = $1,454M
Interest expense $150M, after 25% tax     =   $113M
DACF                                      = $1,567M

Market cap: 250M shares × $14.00          = $3,500M
Net debt                                  = $1,800M
Enterprise value                          = $5,300M

EV/DACF = $5,300M / $1,567M               =    3.4x

At 3.4x against a large-cap band of roughly 3-6x, Company A screens cheap. The next section is why that reading is usually wrong.

Reserve Life Sets the Multiple

A multiple is a compressed present value, so it inherits the horizon of the cash flow it is compressing. At a 10% discount rate, a flat stream of cash lasting ten years is worth about 6 times one year of it. Lasting twenty years, about 8.5 times. Lasting forever, 10 times. Nothing about quality or cheapness enters that arithmetic; it is just how far out the money arrives.

Producers trade below those factors for two reasons. Production declines rather than staying flat, and DACF is struck before the capital required to hold it up.

Run it through the two examples. Company A has 8.9 years of reserves. Company B is a long-life producer: 1,200 MMBOE of proved reserves, 65 MMBOE of annual production, so 18.5 years, on identical margins, an identical price deck and an identical discount rate.

	Company A	Company B
Proved reserves	400 MMBOE	1,200 MMBOE
Annual production	45 MMBOE	65 MMBOE
Reserve life	8.9 years	18.5 years
Cash margin	$27.3/BOE	$27.3/BOE
Enterprise NAV (10%, $70 WTI)	$6,113M	$13,650M
DACF	$1,567M	$2,235M
EV/DACF the NAV supports	3.9x	6.1x

Same commodity, same costs, same discount rate. Company A’s reserve base justifies 3.9x and Company B’s justifies 6.1x, purely because B’s cash flow lasts twice as long.

So Company A trading at 3.4x is not cheap because it is below 4x. It is 13% below what its own reserves support, which is a real but modest discount, and a chunk of it is explained the moment you see the reserve life. Company A at 6x would be expensive, on assets that stop producing before the multiple is earned. Never read an EV/DACF multiple without the reserve life next to it. The reserve life index is disclosed and takes one division to compute.

The corollary is worth holding onto too. If a short-life producer trades on a high multiple, the market is not paying for its reserves; it is paying for barrels the company has not booked yet, whether from the drill bit or from acquisitions. That is a bet on the drilling programme wearing the costume of a valuation.

When NAV and the Market Disagree

Company A’s NAV is $17.25 and the shares are $14.00, a 19% discount. Something has to explain it, and the candidates are short:

• The market’s price deck is below yours. The commonest answer, and the sensitivity table prices it. A market assuming $60 WTI gets $11.60, so the share price sits between a $60 and a $70 view.
• The market wants a higher discount rate. At 12% and $70 the NAV is $15.30, most of the way to the share price on its own.
• Execution risk on the undeveloped reserves. 150 of the 400 MMBOE are proved undeveloped, and a NAV values them as though the wells get drilled on schedule.
• Reserve replacement. A reserve replacement ratio, new reserves booked divided by the year’s production, running below 100% means the base is shrinking and the ten-year schedule flatters what comes after it.

Working out which one is operating is the actual job. If you cannot name it, your conviction on either number should be low, because a NAV that only works when the market is wrong is not evidence.

Blowdown NAV vs Going Concern NAV

The example above is a blowdown NAV: produce the booked reserves, spend the capital they require, stop. It suits mature producers, end-of-life assets and any company with no credible reserve replacement, and it is the closest analytical cousin to PV-10.

Going concern NAV assumes the company keeps replacing what it produces, and adds two things a blowdown ignores: production beyond the booked reserve schedule, and a terminal tail. For Company A:

• PV of proved reserves, ten years: $6.1bn
• PV of extended production, years 10-30 and declining: $1.8bn
• PV of the terminal tail: $0.8bn
• Going concern NAV: $8.7bn, a premium of about 40%

That premium is not free. It is a claim that the company can keep finding barrels at a cost below what they earn, which is exactly what F&D benchmarks test. Where a going-concern NAV is used without checking replacement costs, the 40% is a hope rather than a valuation.

Strip Prices vs a Planning Deck

There are two defensible ways to price a NAV and they answer different questions.

Strip pricing uses the futures curve on the day you build the model. It is the price at which the company could actually hedge, which makes it the right basis for anything with a financing or transaction angle. It is not automatically conservative: the curve sits above spot in contango and below it in backwardation, and which way it leans changes through the cycle.

A planning deck is a normalised long-term price, justified by the marginal cost of supply and a view on demand. It ignores the near-term noise the strip picks up, which is the point when you are valuing a twenty-year asset, and it is an opinion, which is the risk.

Neither is right. The failure is running one and describing it as the other, or comparing a NAV built on a $70 deck with one built on the strip and treating the difference as a disagreement about the assets.

Which Metric to Use When

NAV is the right tool for long-life assets, for M&A diligence where the barrels are what changes hands, and for anything where you have real reserve detail. It normalises across basins with different decline profiles and it ignores near-term commodity noise. It costs hours per company and it is only as good as the deck behind it.

EV/DACF is for screening. Scanning thirty E&Ps for relative value, nobody builds thirty NAVs. It is also the metric a generalist portfolio manager will recognise, which matters when you are the one pitching. Its weakness is that it says nothing about horizon on its own, which is why the reserve life belongs in the same column of the screen.

Run the multiple first to find the candidates, then the NAV on the handful that survive. A stock at a 30% NAV discount and 8x forward EV/DACF is telling you something specific: either the reserve assumptions are too generous, or the market is paying for growth the reserve report has not booked. Diagnosing which is the work. See the Oil & Gas Sector Primer for how these metrics fit the broader E&P picture.