Energy-Specific Technical Interview Questions and How to Answer Them

Introduction

Energy investment banking interviews include a layer of technical questions that candidates from generalist banking preparation will not have encountered. These questions test whether you understand the unique financial metrics, valuation methods, business models, and market dynamics that define energy coverage. Unlike generalist technicals (which focus on DCF mechanics, LBO modeling, and accounting), energy technicals require knowledge of commodity markets, reserve engineering concepts, energy-specific accounting, and sub-sector business models. This article provides the 25 most frequently asked energy technical questions with concise, interview-ready answers.

Q1: What is EBITDAX and why is it used instead of EBITDA for E&P companies?

EBITDAX is EBITDA before exploration expenses. It normalizes for the different treatment of exploration costs under full cost versus successful efforts accounting. Under successful efforts, dry hole costs are expensed immediately, reducing EBITDA. Under full cost, all exploration costs are capitalized, inflating EBITDA. EBITDAX adds back exploration expense under both methods, making companies directly comparable regardless of accounting method. It is the standard denominator in E&P trading multiples (EV/EBITDAX).

Q2: What are the different reserve categories and why do they matter?

Reserves are classified by the probability of recovery. PDP (proved developed producing) are currently being extracted with 90%+ certainty, requiring no additional capital. PDNP (proved developed non-producing) are proved and developed but not currently producing (shut-in or behind-pipe). PUD (proved undeveloped) require new wells or significant capital to extract. Probable reserves have a 50% chance of recovery. Possible reserves have a 10% chance. Each category carries different risk, requires different capital, and is valued at a different discount rate in a NAV model.

Q3: Walk me through the concept of a type curve.

A type curve is a standardized production profile for a new well in a specific area. It shows three things: the initial production (IP) rate (e.g., 1,500 BOEPD for a Permian well), the decline rate schedule (how quickly production falls, often 60-70% in year one), and the estimated ultimate recovery (EUR) over the well's life (e.g., 1.2 million BOE over 30 years). Type curves are the building blocks of NAV models for undeveloped reserves: each new well generates cash flows according to its type curve, and the sum of all well-level cash flows drives the NAV.

Decline Curve Analysis

The process of fitting a mathematical curve (typically hyperbolic or exponential) to historical production data to forecast future production volumes. The key parameters are the initial decline rate (b factor), the nominal decline rate, and the terminal decline rate at which the curve transitions from hyperbolic to exponential. Decline curve analysis is used for both individual wells and field-level production, and is the primary tool for projecting PDP production volumes in a NAV model.

Q4: What is PV-10 and how does it differ from a full NAV?

PV-10 is the present value of estimated future net revenues from proved oil and gas reserves, discounted at 10%, using SEC-mandated pricing (12-month average of first-day-of-month prices). It includes only proved reserves and uses a flat 10% discount rate. A full NAV may include probable and possible reserves, use strip or consensus pricing rather than SEC pricing, and apply WACC or risk-adjusted discount rates rather than a flat 10%. PV-10 is a regulatory metric; NAV is an analytical, investment-decision tool.

Q5: What is the difference between full cost and successful efforts accounting?

Under successful efforts, only the costs of successful exploration wells are capitalized; dry hole costs are expensed immediately. Under full cost, all exploration costs (including dry holes) are capitalized and depleted over the reserve base. This means that a company using successful efforts will report lower EBITDA (due to dry hole expenses) than an identical company using full cost. EBITDAX eliminates this distortion.

Q6: What is the difference between WTI and Brent, and why do both matter?

WTI (West Texas Intermediate) is the US domestic benchmark crude, priced at Cushing, Oklahoma. Brent is the international benchmark, priced in the North Sea. Brent typically trades at a $3-5 premium to WTI due to differences in quality, transportation costs, and global supply-demand dynamics. Both matter because US E&Ps realize prices linked to WTI, but global oil trade and OPEC policy are referenced to Brent.

Q7: What is a basis differential and why does it matter for E&P valuation?

A basis differential is the difference between a benchmark commodity price (Henry Hub, WTI) and the actual price a producer receives at the wellhead or delivery point. The Waha basis (Permian gas) often trades $1.00-2.00+ below Henry Hub due to pipeline capacity constraints. Basis differentials directly affect the realized price in a NAV model, so a company with significant production in a constrained basin will have a lower NAV than one with identical production volume but better basis realization.

Q8: How do oil prices affect different energy sub-sectors differently?

Higher oil prices are not universally good for all energy companies, and this question is designed to catch candidates who assume "high oil = good for everyone." Upstream E&Ps benefit directly because higher prices increase revenue per barrel. OFS companies benefit indirectly because higher E&P spending means more drilling activity and better pricing power for service providers. Midstream companies are largely insulated due to their fee-based revenue structures, though higher prices do increase throughput volumes by incentivizing more drilling. Downstream refiners are actually hurt by higher crude prices because crude oil is their primary input cost; refiner profitability depends on crack spreads (the margin between product prices and crude cost), not the absolute level of commodity prices. Power generators are affected differently depending on fuel source: gas-fired generators face higher fuel costs (compressing spark spreads unless electricity prices rise commensurately), while nuclear and renewable generators benefit because higher gas prices raise the marginal clearing price for wholesale electricity, boosting their revenue with no increase in fuel cost.

Q9: What is contango versus backwardation?

Contango means futures prices are higher than spot prices (the forward curve is upward-sloping). Backwardation means futures prices are lower than spot prices (downward-sloping). In contango, storage operators can profit by buying oil at the spot price, storing it, and selling futures at the higher price. In backwardation, the market is signaling near-term tightness. The shape of the forward curve affects the price assumptions in NAV models: during backwardation, strip pricing for years 2-3 will be lower than the current spot price.

Q10: How does reserve-based lending work?

An RBL is a revolving credit facility where the borrowing base is set by the value of the E&P company's proved reserves. Banks redetermine the borrowing base semiannually (typically April and October) based on current commodity prices and updated reserve estimates. If the borrowing base shrinks (due to lower prices or production shortfalls), the company must repay the deficiency within 30-90 days. RBLs are the primary source of liquidity for E&P companies and a common trigger for financial distress during commodity downturns.

Q11: What is a DrillCo arrangement?

A DrillCo is a joint venture structure where a financial partner (typically PE) funds the drilling of new wells on an E&P company's acreage in exchange for an overriding royalty interest or working interest that reverts to the operator after the investor achieves a target return. DrillCos allow E&Ps to develop acreage without deploying their own capital or drawing on their RBL, preserving balance sheet flexibility.

Q12: What is the difference between a fee-based contract and a percent-of-proceeds contract in midstream?

A fee-based contract charges a fixed rate per unit of throughput (e.g., $0.50 per barrel transported) regardless of commodity prices, providing predictable revenue. A percent-of-proceeds (POP) contract gives the midstream operator a percentage of the revenue from the products processed, exposing it directly to commodity prices. Fee-based contracts are valued at higher multiples because of their cash flow predictability. The midstream valuation framework treats these differently.

Q13: What is distribution coverage ratio and why does it matter?

The distribution coverage ratio is distributable cash flow divided by total distributions paid. A ratio above 1.0x means the company generates more cash than it distributes, providing a cushion. Below 1.0x means the distribution is unsustainable. The market closely monitors this metric because a distribution cut typically triggers a sharp decline in the unit price. Investment-grade midstream operators target 1.3-1.5x coverage.

Q14: How is a regulated utility valued differently from a merchant power company?

Regulated utilities are valued on P/E and rate base growth because their earnings are determined by regulators (allowed ROE on rate base). Merchant power companies are valued on EV/EBITDA and spark spread analysis because their revenue depends on wholesale electricity prices. Utilities trade at 16-20x P/E; merchant power trades at 8-12x EV/EBITDA. These are completely different business models with different risk profiles.

Q15: Why did ExxonMobil acquire Pioneer for $64.5 billion?

ExxonMobil acquired Pioneer to secure the largest and highest-quality drilling inventory in the Permian Basin, more than doubling its Permian production to approximately 1.3 million BOEPD (growing to 2 million by 2027). The deal was an inventory acquisition: as the Permian matures, the most valuable asset is the number of remaining high-quality, undrilled well locations, and Pioneer's approximately 850,000 net acres provided decades of future development.

Q16: What valuation metrics would you use for a Permian A&D transaction?

For a Permian asset acquisition, the primary metrics are: per-acre value (for undeveloped acreage), per-flowing-barrel (for producing wells), NAV at various price scenarios, and per-BOE of proved reserves. The choice depends on whether the deal is primarily a production acquisition (emphasize per-flowing-barrel) or an inventory acquisition (emphasize per-acre).

Q17: Where is oil trading right now and where do you think it is going?

Always check the morning of your interview. As of early 2026, Brent is elevated above **$90** due to Middle East geopolitical tensions, but forward curves project a decline to $70-80 by late 2026 as the geopolitical premium fades and the fundamental oversupply trend reasserts itself. State a range, explain the variables (OPEC+ policy, non-OPEC supply growth, geopolitical risk), and acknowledge what could make you wrong.

Q18: How is AI affecting the energy sector?

AI-driven data center demand is creating the first sustained increase in US electricity consumption in two decades. Data centers currently represent approximately 4% of US power consumption and are growing rapidly. This reprices dispatchable generation assets (gas and nuclear), drives power M&A (Constellation/Calpine, NRG/LS Power), increases natural gas demand (supporting Henry Hub pricing), and creates grid infrastructure investment needs.

Q19: What is the current state of Permian Basin consolidation?

The transformative megadeal phase is largely complete after ExxonMobil/Pioneer, Chevron/Hess, Diamondback/Endeavor, ConocoPhillips/Marathon, and Occidental/CrownRock. The remaining deal flow is mid-cap defensive mergers (Devon/Coterra), bolt-on A&D, and post-megadeal portfolio optimization divestitures. The focus is broadening toward gas-weighted basins driven by LNG demand.

Q20: Why has the gas price recovered from the 2024 lows?

Henry Hub recovered from a record-low $2.21 in 2024 to $3.53 in 2025, driven by three factors: LNG export capacity growth (Plaquemines LNG, Corpus Christi Stage 3), AI-driven power demand increasing gas consumption for electricity generation, and producer supply discipline in gas-weighted basins.

Q21: If oil prices drop $10 per barrel, what happens to an E&P company's NAV?

The NAV declines by approximately 15-25%, depending on the company's cost structure, product mix, and reserve life. The impact is larger for companies with higher operating costs (because the cash flow margin per barrel narrows proportionally more) and for oil-weighted producers (because oil revenue is the largest component). Gas-weighted E&Ps are less affected because their revenue is primarily driven by Henry Hub rather than oil. The hedge book provides partial insulation for 1-3 years, but the long-term NAV (which extends 20-40 years) is heavily affected because hedges only cover near-term production.

Q22: Why would an E&P company trade above its NAV?

A company trading above NAV (P/NAV greater than 1.0x) typically reflects one or more factors: the market believes the company has exploration upside beyond its current proved reserves, the management team is expected to improve well productivity or reduce costs, the company is an acquisition target (embedding a takeover premium), or the market is using a higher long-term commodity price assumption than the analyst's NAV model. Conversely, a company trading below NAV may signal market concerns about reserve quality, management execution, balance sheet risk, or an overly optimistic NAV from the analyst.

Q23: How would you model the impact of a new well program on an E&P's valuation?

Start with the company's development plan: how many wells per year, in which zones, at what cost per well. Apply the relevant type curve to each well to generate production volumes by product. Multiply by commodity prices (net of basis differentials) to get revenue, subtract LOE and taxes to get net revenue, deduct the drilling and completion cost, and discount the net cash flow at the appropriate rate. If the net present value of the well is positive, it adds value to the NAV; if negative, the well should not be drilled. The aggregate value of all planned wells is the PUD component of the NAV.

Q24: How does the energy transition affect E&P valuation?

The energy transition introduces long-term demand uncertainty for oil and gas, which can affect the discount rate (investors may require a higher return for long-dated hydrocarbon assets) and the long-term price assumption (if oil demand peaks, long-term prices may be lower). Some analysts apply a "terminal value haircut" or shorten the reserve life assumption to reflect the possibility that not all reserves will be economically extracted in a lower-demand world. European majors (Shell, BP, TotalEnergies) trade at lower multiples than US peers partly because of transition-related portfolio concerns.

Q25: What is a crack spread? The difference between refined product prices and crude oil input cost. The 3-2-1 crack spread (3 barrels crude = 2 barrels gasoline + 1 barrel distillate) is the standard measure of refining profitability.

Q26: What is DACF? Debt-adjusted cash flow, calculated as operating cash flow plus interest expense minus working capital changes. It provides a capital-structure-neutral cash flow metric for E&P comparison, commonly used alongside EV/EBITDAX.

Q27: What is a BOE? Barrel of oil equivalent, a unit that converts natural gas and NGLs to an oil-equivalent basis. 1 BOE = 6 Mcf of gas (energy-equivalent, not price-equivalent). The price-equivalence ratio is much wider since oil is worth approximately 6x more per BOE than gas.

Q28: What is an MLP? A master limited partnership, the historical structure for midstream companies that provided tax-advantaged pass-through income. Most large MLPs have converted to C-corps, but the structure is still relevant for understanding midstream history and certain remaining entities.

Q29: What is the IRA? The Inflation Reduction Act, which created approximately $369 billion in clean energy incentives including the ITC (30% investment tax credit), PTC (production tax credit), and 45Q ($85/ton for carbon capture). The OBBBA modified some provisions in mid-2025.

Q30: What is a spark spread? The margin between the price of electricity and the cost of the natural gas fuel used to generate it. Calculated as: electricity price (per MWh) minus gas price times heat rate. Spark spreads are the primary profitability metric for gas-fired merchant power generators.