Walking Through an E&P NAV Model: The Interview Framework

Introduction

The NAV model is the most important technical concept in energy investment banking interviews. When an interviewer asks "walk me through how you would value an E&P company," the NAV model is the first methodology you should discuss, and you should be able to walk through it step by step with clarity and confidence. Unlike a standard DCF that projects 5-10 years of consolidated cash flows and applies a terminal value, the NAV model projects cash flows for the entire productive life of the reserve base (often 20-40 years), reflecting the physical reality that an E&P company's primary asset, its oil and gas reserves, depletes over time and cannot be captured by a terminal value multiple.

This article provides the complete interview framework for walking through an E&P NAV model, from reserve classification through the equity value bridge, with the level of detail and analytical nuance that energy interviewers expect.

Before diving into the mechanics, understand why the NAV model exists. The standard DCF assumes that a company is a going concern that generates cash flows indefinitely, and the terminal value (often 60-80% of the total) captures the value of cash flows beyond the projection period. This assumption works poorly for E&P companies for two reasons.

First, E&P companies own a depleting asset. Oil and gas reserves are extracted and sold, and the reservoir declines over time. A company that does not replace its reserves through drilling or acquisitions will eventually produce nothing. There is no "perpetuity" of cash flows; there is a finite production life determined by the geology and the decline curve.

Second, the commodity price sensitivity of E&P cash flows makes terminal value calculations unreliable. A terminal value based on an exit multiple or Gordon Growth Model embeds assumptions about long-term commodity prices that may be completely wrong. The NAV model avoids this by projecting cash flows for the full reserve life using explicit price assumptions for each year, giving the analyst direct control over the commodity price scenario.

PV-10 vs. NAV

PV-10 is the present value of estimated future net revenues from proved oil and gas reserves, discounted at 10% per year. It is an SEC-mandated metric that uses SEC pricing rules (12-month average of first-day-of-month prices) and includes only proved reserves. NAV is a broader concept that may include proved, probable, and possible reserves; uses the analyst's chosen price deck (strip, consensus, or scenario pricing); and may apply WACC rather than a flat 10% discount rate. PV-10 is a standardized, regulatory measure; NAV is an analytical, investment-decision measure. Both follow the same structural framework, but NAV gives the analyst more flexibility and is the version used in M&A and advisory contexts.

The foundation of every NAV model is the company's reserve base, classified by the probability of economic extraction.

Probable reserves (2P minus 1P) have at least 50% probability of recovery. They are often included in NAV models at a risk-weighted value (e.g., 50% of the unrisked PV).

Possible reserves (3P minus 2P) have at least 10% probability. They are sometimes included at heavily discounted values or excluded entirely from base-case NAV calculations.

The reserve data comes from the company's annual 10-K filing (which includes an independent reserve engineer's report, typically from firms like DeGolyer and MacNaughton, Ryder Scott, or Netherland Sewell) and investor presentations that provide supplemental detail on acreage, type curves, and development plans.

For each reserve category, you project annual production volumes using decline curve analysis.

PDP reserves use the company's existing production as the starting point, then apply a decline rate to forecast how production decreases over time. Decline rates vary by basin and well type: Permian horizontal wells might decline 60-70% in the first year and 20-30% in subsequent years before settling into a low single-digit terminal decline rate. Conventional vertical wells decline more slowly. The decline rate is typically modeled using a hyperbolic or exponential function calibrated to the company's historical production data or basin-specific type curves from engineering firms.

The math is straightforward. If a well's current production is 500 barrels per day and the year-one decline rate is 40%, next year's average production is approximately 300 barrels per day. In year two, if the decline rate moderates to 25%, production drops to approximately 225 barrels per day, and so on. Over 20-30 years, the cumulative production from this single well represents the PDP reserve volume, and the revenue generated across those years (after applying prices) is the economic value of that well. The NAV model aggregates this calculation across every producing well in the company's portfolio.

PUD and probable reserves are modeled using type curves, which are standardized production profiles that represent the expected output of a new well in a specific area. A type curve specifies three critical parameters: the initial production (IP) rate (e.g., 1,500 barrels of oil equivalent per day for a Permian Midland Basin well), the decline rate schedule (the speed at which production falls from the IP rate), and the estimated ultimate recovery (EUR) over the well's productive life (e.g., 1.2 million BOE over 30 years). Companies disclose type curves in their investor presentations, and reserve engineers use them to estimate the volume of recoverable reserves in undeveloped locations.

You model the timing of new well drilling based on the company's development plan, rig count, and wells drilled per rig per year. For example, if a company runs 5 rigs and drills 20 wells per rig per year, it adds 100 new wells annually. Each new well generates production according to the type curve, and the capital cost of drilling each well ($7-10 million per Permian horizontal well, $12-15 million per Haynesville well) is deducted from the well's cash flow to determine its net contribution to NAV.

The production forecast must be disaggregated by product: crude oil (barrels), natural gas (Mcf or MMBtu), and NGLs (barrels). This disaggregation is essential because each product has a different price, and the product mix varies dramatically by basin. Permian Midland Basin wells produce approximately 70% oil, 15% gas, and 15% NGLs. Permian Delaware Basin wells are more gas-rich at approximately 50% oil. Haynesville wells produce almost entirely dry gas. The product mix directly affects the revenue per BOE and therefore the NAV per reserve unit.

This is where the commodity price environment directly enters the model. You multiply projected production volumes by commodity price assumptions for each year to calculate gross revenue.

You also apply basis differentials to convert benchmark prices to realized prices. A Permian producer's realized gas price is Henry Hub minus the Waha basis differential, which can be $1.00-2.00+ below the benchmark. An Appalachian producer's realized price reflects the Dominion South basis. These differentials materially affect the NAV, especially for gas-weighted companies.

One additional pricing consideration that sophisticated candidates address is the company's hedge book. Many E&P companies hedge a portion of their near-term production using swaps, collars, and puts. In the NAV model, you should incorporate the hedge book for the hedged portion of production (typically 1-3 years), using the contract prices rather than the strip. For unhedged production, you apply the strip or consensus deck. The hedge book affects near-term cash flows but not the long-term NAV, since hedges rarely extend beyond 2-3 years. However, the hedge book can significantly affect the borrowing base and the company's ability to fund its drilling program, both of which are important for a complete analysis.

From gross revenue, subtract the costs associated with producing the reserves.

Lease operating expenses (LOE): The ongoing costs of operating producing wells (pumping, water disposal, well maintenance, field labor). LOE is typically modeled on a per-BOE basis (e.g., $8-12 per BOE for a Permian operator) and grows with inflation over time.

Production taxes and severance taxes: State-level taxes on oil and gas production, typically 4-8% of wellhead revenue depending on the state. Texas, where the Permian and Eagle Ford are located, charges approximately 4.6% for oil and 7.5% for gas. North Dakota (Bakken) charges a higher combined rate. These taxes are modeled as a percentage of revenue and scale proportionally with commodity prices.

General and administrative (G&A): Corporate overhead, including management salaries, office costs, legal, and accounting expenses. G&A is modeled as a total annual cost or on a per-BOE basis (typically $1-3 per BOE for large-cap E&Ps).

Capital expenditures: For PDP reserves, minimal maintenance capex. For PUD and probable reserves, the drilling and completion cost for each new well (e.g., $7-10 million per Permian horizontal well, $12-15 million per Haynesville well). Capex timing aligns with the development schedule modeled in Step 2.

The result is unlevered free cash flow (or net revenue) for each year across the reserve life.

Discount the annual net cash flows to present value.

For PV-10 (the SEC standard), use a flat 10% discount rate for all reserve categories. PV-10 is the metric reported in 10-K filings and used by reserve-based lenders to set borrowing bases.

For a full NAV (used in M&A advisory and equity research), the analyst may use WACC (typically 8-12% for E&P companies) or apply different discount rates to different reserve categories to reflect their varying risk levels: 10% for PDP, 12-15% for PUD, 15-20% for probable, 20-25% for possible. This risk-tiered approach is common in sell-side research and M&A marketing materials. The logic is intuitive: PDP reserves are already producing and carry minimal geological risk, so a lower discount rate is appropriate. PUD reserves require successful drilling (execution risk), and probable reserves carry additional geological uncertainty about whether the hydrocarbons are economically recoverable.

In an interview, be prepared to justify your discount rate choice. A common answer is: "For PV-10 as reported in the 10-K, I use 10% because that is the SEC standard. For a full NAV used in M&A analysis, I use the company's WACC for proved reserves, but I apply a higher discount rate or a probability weight to less certain reserve categories to reflect the incremental risk." This demonstrates that you understand both the regulatory and analytical uses of the NAV framework.

The final step converts the sum of discounted asset values into an equity value per share.

The NAV per share is then compared to the current stock price to assess whether the company is trading at a premium or discount to its asset value. An E&P trading at 0.8x NAV (a 20% discount) might represent a buying opportunity or a sell-side marketing pitch, while one trading at 1.2x NAV (a 20% premium) might be overvalued or reflect the market's view that the company has upside beyond its current proved reserve base (exploration potential, efficiency improvements, or an embedded commodity price premium).

The P/NAV ratio is one of the most important relative valuation metrics in upstream energy. In M&A contexts, buyers typically offer a premium to PDP NAV but may not fully pay for PUD or probable value, because these reserves carry development risk. A common bid structure for a Permian acquisition might be 1.0-1.1x PDP NAV plus 0.5-0.7x PUD NAV, with limited or no credit for probable and possible reserves. Understanding this bid framework helps explain why sellers and buyers often disagree on value: sellers believe their undeveloped reserves are worth more than buyers are willing to pay, creating the bid-ask spread that energy bankers spend much of their time bridging.

When walking through a NAV model in an interview, follow this structure:

Start with the "why." Explain that you use a NAV model for E&P companies because the depleting asset base means a terminal value is inappropriate, and the commodity sensitivity requires explicit price assumptions across the full reserve life.

Walk through the mechanics. Cover the six steps: classify reserves, project production with decline curves, apply pricing (mention strip for near-term, consensus for long-term), subtract costs and capex, discount at 10% (for PV-10) or WACC, and bridge to equity value per share.

Emphasize the price sensitivity. Mention that you would present the NAV as a sensitivity table across multiple commodity price scenarios, and explain which scenario you view as base case and why.

Connect to deal context. If discussing M&A, explain that the NAV is used to determine bid levels (buyers typically pay a premium to PDP NAV but a discount to full NAV including probable reserves), and that the gap between buyer and seller NAV assumptions is often the key negotiation variable.