Vista Energy (VIST)

By both methods, the value today (DCF $147 · Multiples $83) exceeds the market price ($69).

Today — fairly valued: at $69 trades ~16.8% below its value discounted to today (~$83); the discount is positive but does not reach the margin of safety we require (≥38%).

At 5 years — En valor: the target price ($104) plus dividends yield between the 4% floor and the 10% average return — a reasonable return, though without the margin of a great investment.

The bridge: the return at 5 years exceeds the risk-free rate (4.5%) — but the discount does not reach the required margin of safety (≥38%). To require a 15% annual return, it would need to be bought at ~$52.

Educational / informational. Does not constitute investment advice.

The inverse approach: instead of projecting growth to obtain the value, the market price ($69) is taken as given and it solves for what annual owner-earnings growth would need to hold for 5 years for the present value —at the method's rate (4.5%, no-growth terminal)— to equal that price. It is the disconfirmation test: the expectations the price already pays for, contrasted against the method's projection.

The market discounts less growth (-4.7%/year) than we project (12.0%/year) → if the base case holds, there is margin: perception is more pessimistic than the estimated reality.

That growth implies ~$0.3 bn of owner earnings in year 5 (vs ~$0.7 bn of our base case). It recalculates if the DCF assumptions are edited.

Year-by-year projection of the selected scenario. From each year, two versions of the flow are derived: growth FCF (operating flow − total capex, the cash surplus) and maintenance FCF (the owner earnings: what the business yields if it only sustains its capacity). The flow is returned almost in full (dividend + buyback) or redeployed into the operation, so that EV stays roughly flat and multiples compress because the metric grows, not because of cash accumulation. The valuation is done on Utilidad neta normalizada a mitad de ciclo (P/E). In edit mode, revenue, margins, capex, and exit multiples can be adjusted.

Annual reporter: Vista files a 20-F and does not publish tagged quarters, so year 0 is the fiscal year ended 31 December 2025 and not a manufactured period; the year-0 column and that of the last fiscal year are the same period, which is why the history and year 0 coincide. The year-0 level is the real one (revenue of US$2,474.2 million); what is normalized is earnings. The normalization has two pieces and both come from the report itself: the increase in other operating income of US$458.7 million is removed (US$512.8 million in 2025 against US$54.1 million in 2024), which the report explains mainly by the result of the La Amarga Chica acquisition, and the US$38.3 million impairment from the return of the CS-01 block is added back. Normalized operating income comes to US$830.4 million (33.6% of revenue) against the US$1,250.8 million reported, and normalized net income to US$418 million against the US$719.1 million reported. Mid-cycle price: the projection uses a realized oil price of US$66 per barrel, the midpoint of the two realized prices the report declares (US$69.2 in 2024 and US$62.9 in 2025), and not the March 2026 Brent (US$99.6), which the report itself describes as fragile and reversible; the midpoint of the range is taken, never the top. The revenue path combines the exit production of the fourth quarter of 2025 (135.4 Mboe/d against an annual average of 115.5 Mboe/d), the contribution of the assets from the Equinor transaction and organic drilling, decelerating from 23% to 6.5% by year 5; the reported growth of 50.2% in 2025 is not extrapolated because it is explained by the La Amarga Chica acquisition. There is current guidance that had not been detected: the 6-K forms of 29-30 April 2026 (Q1'26, accession number 0001193125-26-306137, interim statements at 30 June 2026) and of 16-17 July 2026 (Q2'26, accession number 0001193125-26-306731) carry annual guidance of 100 to 110 well tie-ins and a sensitivity of ~US$200 million of adjusted earnings before interest, taxes, depreciation and amortization for every US$10 per barrel of Brent variation in the second half. Revenue in the first half of 2026 was US$2,099.9 million against US$1,049.0 million in the first half of 2025 (+100.2%), and the result for the period in the first half of 2026 was US$440.7 million, already above the normalized base for the whole of fiscal 2025 (US$418 million). The full re-anchoring of the path and the scenarios to these actuals and to the guidance is pending the update flow triggered by results (6-K forms), because the available interim statements do not carry the full first-half 2025 comparable needed to recompute the TTM from levels without estimating; the gap is declared rather than forcing a number. The share path models the delivery of 6,223,220 certificates in the Equinor transaction (genuine issuance for an acquisition, not compensation dilution) and projects no buybacks: the revealed net reduction is negative, the count rose every year, and the authorization is a ceiling. Cash does not accumulate because the surplus is redeployed into drilling and acquisitions: investment of US$1,455.4 million exceeded operating flow of US$796.2 million and cash held at US$538.4 million.

Today's elevated multiple is the price of growth: if the business grows, the entry point cheapens on its own going forward (the metric grows while EV stays roughly flat). The exit multiple at 3 years is higher than the terminal at 5 years —at 3 years there is more growth still ahead—, so the value curve shows whether value creation is concentrated in the early or the later years. The required return is applied to the base scenario.

They are valued separately, with their own rationale, and are not incorporated into the base or the verdict (they are excess return). When assigning them value — in Editmode —, the total with optionalities updates live, without moving the base.

The verdict, the base CAGR, and the margin of safety are always calculated on the base; optionalities do not alter them (with optionalities at $0 they do not move).

Each card fixes a required annual return and answers: if the business is worth $104 in 5 years, what is the maximum that can be paid today to obtain that return? Since it now trades at $69, the margin of safety is how much cheaper the market is than that maximum. The three thresholds: 4% covers inflation (the floor), 10% is the long-term average return, and 15% is the level of a great investment.

With a target price of $104 in 5 years and a required return of 4.5% annually, the maximum to pay today is $83. Against the current market price ($69), the margin of safety is 16.8% (trades below the maximum → there is margin) and the total return at that price would be 8.4% annually.

• Multiple on normalized earnings. The stock trades at 18× on mid-cycle normalized net income, considerably more expensive than the multiple on the reported figure suggests.
• Estimated five-year return. +8% annually in the base scenario, with the value per share reaching $104 against a trading price of $69.
• Dispersion across scenarios. The range spans +8% to +8% annually: the valuation depends more on the price of crude and on the jurisdiction than on the multiple chosen.
• Exit multiple. Twelve times normalized earnings, within the range for a producing oil company and below its midpoint.

Each margin over sales, year by year: historical (solid line) → projection (dotted).

• ✓ ROIC exceeds the cost of capital (~10%)
• ✕ CFROIC backs up the ROIC (43%, cash vs. accruals)
• ✓ Healthy balance sheet (low corporate debt)
• ✓ Durable competitive moat (multiple advantages)

• Return on invested capital. 11.6% on normalized operating income, above the 10% bar. On reported earnings it would be 17.5%, but that figure includes the acquisition gain and is not repeatable.
• Cash generation. Operating cash flow of US$796.2 million did not cover investment of US$1,455.4 million: free cash is negative while the growth phase lasts.
• Predictability of results. Results depend on the price of crude and on domestic pricing policy, two variables outside the company's control.
• Reinvestment runway. 1,302 drilling locations ready to spud, more than fifteen years at the current pace, with cost per well declining.

Annual levels from the official filing (10-K); the % over each bar is the year-over-year (YoY) growth vs the prior year.

The engine of an unconventional crude producer is volume times realized price, and the two legs are read separately. Volume depends on how many wells are connected and on the productivity of each one; price depends on the international market for the 61% that is exported and on domestic policy for the rest. In 2025 volume did all the work (+66% in barrels) against a price that fell 9%, so reading revenue growth as if it were price would misread the driver. The lifting cost per barrel of oil equivalent, today at US$4.4, is the third variable that decides how much of that revenue reaches earnings.

The % are the annual (year-over-year) growth: each year —historical and projected— vs the prior one; the TTM (trailing 12m) vs the TTM of a year ago, to avoid overlapping windows. The historicals are exact figures from the official filings; the projected years come from the year-by-year model (the intermediate years without their own series are interpolated between the anchors). The projected columns (+1y…+5y) are 12-month windows counted from the TTM close (31-dic-2025): the projection starts from the most recently reported data, not the fiscal year. The projected base is realistic and unbiased — the risk discount is applied at the end, via the required return. The rationale for each metric is in the (i).

• Volume growth. Barrels sold went from 21.9 to 36.3 MMbbl in 2025, with 74 net wells connected against 50 the year before.
• Quality of growth. A good part of the 2025 jump came from the La Amarga Chica acquisition, not from organic development: the reported rate is not extrapolable.
• Reserve replacement. 605% in 2025 and 260% on an organic basis, meaning it replaces more than it produces even excluding acquisitions.
• Infrastructure constraint. The plan requires more transport and treatment capacity; the export pipeline will not be operational until mid-2027.

• Differentiated product or commodity. Crude is fungible and the market sets the price: the company has no pricing power, only cost power.
• Lowest-cost producer. Lifting cost of US$4.4 per barrel of oil equivalent in 2025 versus US$13.9 per barrel of oil equivalent in 2018, and cost per well of US$12.1 million versus US$16.6 million in 2019.
• Relevance ten years out. Proved reserves equate to fourteen years of production and the drilling inventory to more than fifteen, so the asset has life ahead of it.
• Behavior in a recession. A crude producer takes the full brunt of a demand downturn: the margin compresses faster than costs and investment gets cut.
• Operating leverage. Cost per barrel falls with volume, so every additional barrel comes in at a high margin; the same leverage works against the company when the price falls.

Not all debt is equal: only the structural needs refinancing; the rest is operational (self-liquidating).

Structural debt is what is exposed to the contraction phase of the cycle; operational debt (leases, matched funding) self-liquidates with the business.

• ✓Leverage (net debt / EBITDA)Net cash $0 bn
• !Interest coverage (EBIT / interest)5.1x
• –Liquidity (current ratio)no data
• ✕Cash quality (CFROIC vs ROIC)CFROIC backs 43% of ROIC
• !Value creation (ROIC − 10% bar)+2pp
• ✓Malinvestment test (capex vs incremental ROIC)Capex/D&A 2.0x
• !Float / working capitalConsumes cash $0.2 bn (positive WC)
• –Dilution (SBC % of revenue + shares)no data

A traffic-light interpreted by the method (not generic): float (negative WC) adds up, capex is judged by incremental ROIC (malinvestment test), and a lender is not subjected to corporate solvency. The (i) shows the derivation of each number.

• Leverage. 1.4 times net at year-end 2025, with cash of US$538.4 million against total debt of US$3,154.1 million.
• Cost of new debt. The April 2026 issuance was US$500 million at 7.875% maturing in 2038: the cost of funding reflects jurisdiction risk.
• Free cash flow. Negative due to voluntary growth investment, not operating deterioration, though operating cash flow did not grow every year: it rose from US$689.8 million in 2022 to US$959.0 million in 2024 and fell 17% in 2025, to US$796.2 million. The second quarter of 2026 already shows positive free cash flow (US$99 million; US$491 million excluding mergers and acquisitions).
• Reserve life. Fourteen years of production in third-party certified proved reserves, 89% oil.

How cash comes in and how it is deployed. In green, the business's own cash (the owner-FCF it generates and reinvests); in gray, the float and credit — customer and funding money, which is not the shareholder's.

Almost all capital is split between drilling and buying contiguous acreage. In 2025 drilling and completion investment was US$1,455.4 million and the La Amarga Chica acquisition cost roughly US$1,500 million between cash, deferred payment and the issuance of depositary receipts. The buyback is marginal against that (US$50 million authorized and fully executed during 2025) and there is no dividend. Funding combines own cash, new debt and the issuance of depositary receipts, which raises leverage and the share count at the same time: it is a bet that the return on the acquired asset exceeds its cost of capital.

Who owns the shares — the alignment and whether there is a controlling shareholder.

• Founder's stake. The founder holds 6.67% of the Class A shares and has run the company since its incorporation in 2017.
• Operating track record. Production from 24.5 to 135.4 Mboe/d and lifting cost from US$13.9 to US$4.4 per barrel between 2018 and 2025: the stated plan was delivered.
• Acquisitions. Two large purchases in twelve months of assets contiguous to its own; the company acknowledges it cannot ensure integration or the expected performance.
• Capital return to shareholders. It pays no dividends and the board states it is not considering adopting a policy; the authorized buyback is marginal against investment.

• Missing buyers due to jurisdiction: an issuer incorporated in Mexico, with all its operations in Argentina and listed in New York, falls outside the mandate of many funds that would buy the same asset in another geography.
• Reported 2025 net income is inflated by the gain from the La Amarga Chica acquisition, so the apparent multiple on the published figure is cheaper than the real one: whoever looks at the headline sees a bargain that is not there.
• Free cash flow is negative due to voluntary growth investment (US$1,455.4 million of investment against US$796.2 million of operating cash flow), which keeps away buyers who screen for cash generation.

The source of the discount is structural and verifiable: the asset sits in a country that the company itself describes as an independent market, with a history of price intervention and foreign-exchange controls, and that restricts the pool of buyers regardless of well quality. First- and second-quarter 2026 results moved the base of the business materially (closing of the Equinor transaction, production and realized price rising, free cash flow already positive in the second quarter), so any reading of the discount must be made against those current figures and not against year-end 2025. The honest counterweight is that the jurisdiction discount may be correctly priced: if the gap against export parity reopens, value falls for real, not just its perception.

The annual return (CAGR at 5 years) in each scenario, with the total period return below — the margin of safety made visual: upside range wide, downside range narrow.

Even in the bear scenario, the return holds at -15%/year (-55% total): the margin of safety protects the downside. The bull (+24%/year, +190% total) exceeds it comfortably — a favorable asymmetry, with a narrow downside range and a wide upside range.

• Single-jurisdiction concentration. Practically all reserves and production are in Argentina, with foreign-exchange controls, export duties and a history of price intervention.
• Crude price. The report warns that a resolution of the conflict in the Middle East would push Brent down sharply from the US$99.6 per barrel level of March 2026.
• Regulated domestic price. The gap between the realization price and export parity was 7% in 2023, 2% in 2024, and only closed in 2025, with no guarantee of permanence (against Brent the 2023 gap was 19% and the report does not report it as closed).
• Execution of the acquisitions. Two large purchases in twelve months, with leverage and capital needs rising alongside integration risk.
• Dilution from the Equinor transaction. The issuance of 6,223,220 depositary receipts raises the share count by 5.8% and is modeled in the path; the contingent consideration rises with Brent.

Each thinker's analytical framework applied to our data.

• Buffett / Graham Quality + margin of safety

  A narrow moat and ROIC 12% above the 10% bar, but the margin is limited (+17%) → excellent business at a fair price.

• Peter Lynch Growth at a reasonable price (GARP)

  A cyclical growing 12% at a PEG of 1.5 → reasonable for its growth.

• Joel Greenblatt Cheap and high-return (Magic Formula)

  Earnings yield 11% (EBIT/EV) + ROIC 12% → brushes the Magic Formula.

• Howard Marks Perception vs reality + cycle

  The price discounts -5% vs our 12%: perception is more pessimistic than reality, with an identified source of the discount.

• Seth Klarman Capital protection (bear scenario)

  Bear-scenario floor -15%/yr over 5y (material loss) → risk of permanent capital loss.

• Pat Dorsey Moat strength (Five Rules)

  A narrow moat, stable; sources: cost advantage, efficient scale, intangibles → partially passes the Five Rules.

• Aswath Damodaran Expectations implied by the price

  Justifying the price requires discounting -5%, within what we project (12%) — the story squares with the numbers.